APS filed an application with the ACC on October 28, 2022 (the “2022 Rate Case”) seeking an increase in annual retail base rates on the date rates become effective (“Day 1”) of a net $460 million. This Day 1 net impact represents a total base revenue deficiency of $772 million offset by proposed adjustor transfers of cost recovery to annual retail rates and adjustor mechanism modifications. The average annual customer bill impact of APS’s request on Day 1 is an increase of 13.6%.

The 2019 Rate Case ROO recommended, among other things, (i) a $111 million decrease in annual revenue requirements, (ii) a return on equity of 9.16%, (iii) a 0.30% return on the increment of fair value rate base greater than original cost, with total fair value rate of return further adjusted to include a 0.03% reduction to return on equity resulting in an effective fair value rate of return of 4.95%, (iv) the nonrecovery of the deferral and rate base effects of the operating costs and construction of the Four Corners Power Plant (“Four Corners”) selective catalytic reduction (“SCR”) project (see “Four Corners SCR Cost Recovery” below for additional information), (v) the recovery of the deferral and rate base effects of the operating costs and construction of the Ocotillo modernization project, which includes a reduction in the return on the deferral, (vi) a 15% disallowance of annual amortization of the Navajo Generating Station (the “Navajo Plant”) regulatory asset recovery related to the closure of the Navajo Plant (see “Navajo Plant” below), (vii) the denial of the request to defer, until APS’s next general rate case, the increase or decrease in its Arizona property taxes attributable to tax rate changes, and (viii) a collaborative process to review and recommend revisions to APS’s adjustment mechanisms within 12 months after the date of the decision. The 2019 Rate Case ROO also recommended that the Coal Community Transition (“CCT”) plan related to the closure or future closure of coal-fired generation facilities include the following components: (i) $50 million that will be paid over 10 years to the Navajo Nation, (ii) $5 million that will be paid over five years to the Navajo County Communities surrounding Cholla Power Plant, and (iii) $1.675 million that will be paid to the Hopi Tribe related to APS’s ownership interests in the Navajo Plant. These amounts would be recoverable from APS’s customers through the Arizona Renewable Energy Standard and Tariff (“RES”) adjustment mechanism. APS filed exceptions on September 13, 2021, regarding the disallowance of the SCR cost deferrals and plant investments that was recommended in the 2019 Rate Case ROO, among other issues.

On October 6, 2021 and October 27, 2021, the ACC voted on various amendments to the 2019 Rate Case ROO that would result in, among other things, (i) a return on equity of 8.70%, (ii) the recovery of the deferral and rate base effects of the operating costs and construction of the Four Corners SCR project, with the exception of $215.5 million (see “Four Corners SCR Cost Recovery” below), (iii) that the CCT plan include the following components: (a) a payment of $1 million to the Hopi Tribe within 60 days of the 2019 Rate Case decision, (b) a payment of $10 million over three years to the Navajo Nation, (c) a payment of $0.5 million to the Navajo County communities within 60 days of the 2019 Rate Case decision, (d) up to $1.25 million for electrification of homes and businesses on the Hopi reservation, and (e) up to $1.25 million for the electrification of homes and businesses on the Navajo Nation reservation. These payments and expenditures are attributable to the future closures of Four Corners and Cholla, along with the prior closure of the Navajo Plant and all ordered payments and expenditures would be recoverable through rates, and (iv) a change in the residential on-peak time-of-use period from 3 p.m. to 8 p.m. to 4 p.m. to 7 p.m. Monday through Friday, excluding holidays. The 2019 Rate Case ROO, as amended, resulted in a total annual revenue decrease for APS of $4.8 million, excluding temporary payments and expenditures, under the CCT plan. On November 2, 2021, the ACC approved the 2019 Rate Case ROO, as amended.

On November 24, 2021, APS filed an application for rehearing of the 2019 Rate Case with the ACC and the application was deemed denied on December 15, 2021, as the ACC did not act upon it. On December 17, 2021, APS filed its Notice of Direct Appeal at the Arizona Court of Appeals and a Petition for Special Action with the Arizona Supreme Court, requesting review of the disallowance of $215.5 million of Four Corners SCR plant investments and deferrals (see “Four Corners SCR Cost Recovery” below for additional information) and the 20-basis-point penalty reduction to the return on equity. On February 8, 2022, the Arizona Supreme Court declined to accept jurisdiction on APS’s Petition for Special Action. The Arizona Court of Appeals heard oral arguments on November 30, 2022. On March 6, 2023, the Court issued its opinion in this matter, affirming in part and reversing in part the ACC’s decision in the 2019 Rate Case. The Court vacated the 20-basis-point penalty included in the ACC’s allowed return on equity, as the Court determined the use of customer service metrics to justify the reduction exceeded the ACC’s ratemaking authority. Additionally, the Court vacated the disallowance of $215.5 million of APS’s Four Corners SCR investment because the ACC did not consider APS’s contractual obligations and improperly considered post-investment data in violation of its own rules. The Court remanded the issue to the ACC for further proceedings. The ACC requested an extension of the 30-day deadline to appeal the matter to the Arizona Supreme Court, and the Arizona Supreme Court granted the extension of the deadline to May 8, 2023. APS cannot predict the outcome of this proceeding.

Additionally, consistent with the 2019 Rate Case decision, as of April 2023, APS has completed the following payments that will be recoverable through rates related to the CCT: (i) $6.66 million to the Navajo Nation; (ii) $0.5 million to the Navajo County communities; and (iii) $1 million to the Hopi Tribe. Consistent with APS’s commitment to the impacted communities, APS has also completed the following payments: (i) $1 million to the Navajo Nation for CCT; (ii) $1.1 million to the Navajo County Communities for CCT and economic development; and (iii) $1.25 million to the Hopi Tribe for CCT and economic development. The ACC has also authorized $1.25 million to be recovered through rates for electrification of homes and businesses on both the Navajo Nation and Hopi reservation. Expenditure of the recoverable funds for electrification of homes and businesses on the Navajo Nation and the Hopi reservations is contingent upon completion of a census of the unelectrified homes and businesses in each that are also within APS service territory.

On September 28, 2022, ACC Staff filed their staff report in the Matter of Impact of the Closures of Fossil-Based Generation Plan on Impacted Communities. APS and other interested parties filed comments on the report. On October 21, 2022, ACC Staff filed a revised report and proposed order. The revised report and proposed order recommended that funds for CCT shall not be collected from rate payers. On December 8, 2022, the ACC voted against ACC Staff’s proposed order, and on April 17, 2023, the ACC closed the docket. Any further action on CCT issues will take place in utility rate cases, including the currently pending 2022 Rate Case. APS cannot predict the outcome of this matter.

On June 1, 2016, APS filed an application with the ACC for an annual increase in retail base rates. On March 27, 2017, a majority of the stakeholders in the general retail rate case, including the ACC Staff, RUCO, limited income advocates and private rooftop solar organizations signed a settlement agreement (the “2017 Settlement Agreement”) and filed it with the ACC. The 2017 Settlement Agreement provides for, among other things, a net retail base rate increase of $94.6 million, excluding the transfer of adjustor balances, consisting of: (1) a non-fuel, non-depreciation, base rate increase of $87.2 million per year; (2) a base rate decrease of $53.6 million attributable to reduced fuel and purchased power costs; and (3) a base rate increase of $61.0 million due to changes in depreciation schedules.

Renewable Energy Standard. In 2006, the ACC approved the RES. Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies. In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects. Each year, APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget. In

On July 1, 2020, APS filed its 2021 RES Implementation Plan and proposed a budget of approximately $84.7 million. APS’s budget request supported existing approved projects and commitments and requested a permanent waiver of the RES residential distributed energy requirement for 2021. In the 2021 RES Implementation Plan, APS requested $4.5 million to meet revenue requirements associated with the APS Solar Communities program to complete installations delayed as a result of the COVID-19 pandemic. The APS Solar Communities program was originally a 3-year program authorizing APS to spend $10 million to $15 million in capital costs each year to install utility-owned distributed renewable energy (“DG”) systems for low to moderate income residential homes, non-profit entities, Title I schools and rural government facilities. On June 7, 2021, the ACC approved the 2021 RES Implementation Plan, including APS’s requested waiver of the residential distributed energy requirements for 2021. As part of the approval, the ACC approved the requested budget and authorized APS to collect $68.3 million through the Renewable Energy Adjustment Charge to support APS’s RES programs.

In June 2021, the ACC adopted a clean energy rules package which would require APS to meet certain clean energy standards and technology procurement mandates, obtain approval for its action plan included in its IRP, and seek cost recovery in a rate process. Since the adopted clean energy rules differed substantially from the original Recommended Order and Opinion, supplemental rulemaking procedures were required before the rules could become effective. On January 26, 2022, the ACC reversed its prior decision and declined to send the final draft energy rules through the rulemaking process. Instead, the ACC opened a new docket to consider all-source requests for proposals (“RFP”) requirements and the IRP process. See “Energy Modernization Plan” below for more information.

On July 1, 2021, APS filed its 2022 RES Implementation Plan and proposed a budget of approximately $93.1 million. APS filed an amended 2022 RES Implementation Plan on December 9, 2021, with a proposed budget of $100.5 million. This budget includes funding for programs to comply with the decision in the 2019 Rate Case, including the ACC authorizing spending $20 million to $30 million in capital costs for the continuation of the APS Solar Communities program each year for a period of three years from the effective date of the 2019 Rate Case decision. APS’s budget proposal supports existing approved projects and commitments and requests a waiver of the RES residential and non-residential distributed energy requirements for 2022. On May 18, 2022, the ACC approved the 2022 RES Implementation Plan, including an amendment requiring a stakeholder working group convene to develop a community solar program for the Commission’s consideration at a future date. On September 23, 2022, APS filed a community solar proposal in compliance with the ACC order that was informed by a stakeholder working group. APS is proposing a small, pilot-scale program size of up to 140 MW that would be selected through a competitive RFP. The ACC has not yet ruled on the proposal. However, on November 10, 2022, the ACC approved a bifurcated community solar process, directing ACC Staff to develop a statewide policy through additional stakeholder involvement and establishing a separate evidentiary hearing to define other policy components. The community solar program was deferred to the ACC’s Hearing Division so that a formal evidentiary hearing could be held to consider issues of substance related to community solar. APS cannot predict the outcomes of these future activities.

On July 1, 2022, APS filed its 2023 RES Implementation Plan and proposed a budget of approximately $86.2 million, excluding any funding offsets. This budget contains funding for programs to comply with Commission-approved initiatives, including the 2019 Rate Case decision. APS’s budget proposal supports existing approved projects and commitments and requests a waiver of the RES residential and non-residential distributed energy requirements for 2022. On November 10, 2022, the ACC approved the 2023 RES Implementation Plan, including APS’s requested waiver of the distributed energy requirement for 2023.

Demand Side Management Adjustor Charge. The ACC Electric Energy Efficiency Standards require APS to submit a DSM Plan annually for review and approval by the ACC. Verified energy savings from APS’s resource savings projects can be counted toward compliance with the Electric Energy Efficiency Standards; however, APS is not allowed to count savings from systems savings projects toward determination of the achievement of performance incentives, nor may APS include savings from these system savings projects in the calculation of its Lost Fixed Cost Recovery (“LFCR”) mechanism. See below for discussion of the LFCR.

On December 31, 2019, APS filed its 2020 DSM Plan, which requested a budget of $51.9 million and continued APS’s focus on DSM strategies such as peak demand reduction, load shifting, storage and electrification strategies. The 2020 DSM Plan addressed all components of the pending 2018 and 2019 DSM plans, which enabled the ACC to review the 2020 DSM Plan only. On May 15, 2020, APS filed an amended 2020 DSM Plan to provide assistance to customers experiencing economic impacts of the COVID-19 pandemic. The amended 2020 DSM Plan requested the same budget amount of $51.9 million. On September 23, 2020, the ACC approved the amended 2020 DSM Plan.

On April 17, 2020, APS filed an application with the ACC requesting a COVID-19 emergency relief package to provide additional assistance to its customers. On May 5, 2020, the ACC approved APS returning $36 million that had been collected through the DSM Adjustor Charge, but not allocated for current DSM programs, directly to customers through a bill credit in June 2020. APS refunded approximately $43 million to customers. The additional $7 million over the ACC-approved amount was the result of the kWh credit being based on historic consumption which was different than actual consumption during the refund period. The difference was recorded to the DSM balancing account and was included in the 2021 DSM Implementation Plan, as described below.

On December 31, 2020, APS filed its 2021 DSM Implementation Plan, which requested a budget of $63.7 million and continued APS’s focus on DSM strategies, such as peak demand reduction, load shifting, storage and electrification strategies, as well as enhanced assistance to customers impacted economically by COVID-19. On April 6, 2021, APS filed an amended 2021 DSM Implementation Plan that proposed an additional one-time incentive for customers participating in the residential energy storage pilot program approved in the 2020 RES Implementation Plan. On July 13, 2021, the ACC approved the amended 2021 DSM Implementation Plan.

On December 17, 2021, APS filed its 2022 DSM Implementation Plan in accordance with an extension granted in 2021. The 2022 DSM Plan requested a budget of $78.4 million and represents an increase of approximately $14 million in DSM spending above 2021. On November 10, 2022, the ACC approved the 2022 DSM Implementation Plan, including a proposed performance incentive. On November 30, 2022, APS filed its 2023 DSM Implementation Plan, which requested a budget of $88 million. The ACC has not yet ruled on the 2023 DSM Implementation Plan.

•the PSA rate includes (a) a “forward component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) a “historical component,” under which differences between actual fuel and purchased power costs and those recovered or refunded through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “transition component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component; and

On November 30, 2020, APS filed its PSA rate for the PSA year beginning February 1, 2021. That rate was $0.003544 per kWh, which consisted of a forward component of $0.003434 per kWh and a historical component of $0.000110 per kWh. The 2021 PSA rate is a $0.004 per kWh increase compared to the 2020 PSA year, which is the maximum permitted under the Plan of Administration for the PSA. This left $215.9 million of fuel and purchased power costs above this annual cap which was reflected in future year resets of the PSA. These rates were to be effective on February 1, 2021, but APS delayed the effectiveness of these rates until the first billing cycle of April 2021 due to concerns of the impact on customers during COVID-19. In March 2021, the ACC voted to implement the 2021 PSA rate on a staggered basis, with 50% of the rate increase taking effect in April 2021, and the remaining 50% taking effect in November 2021. The PSA rate implemented on April 1, 2021 was $0.001544 per kWh, which consisted of a forward component of $(0.004444) per kWh and a historical component of $0.005988 per kWh. On November 1, 2021, the remaining increase was implemented to a rate of $0.003544 per kWh and consisted of a forward component of $(0.004444) per kWh and a historical component of $0.007988 per kWh. As part of this approval, the ACC ordered ACC Staff to conduct a fuel and purchased power procurement audit to better understand the factors that contributed to the increase in fuel costs.

On April 1, 2022, the ACC filed a final report of its third-party audit findings regarding APS’s fuel and purchased power costs for the period January 2019 through January 2021. The report contains an in-depth review of APS’s fuel and purchased power contracts, its monthly fuel accounting activities, its forecasting and dispatching procedures, and its monthly PSA filings, among other fuel-related activities. The report finds that APS’s fuel processing accounting practices, dispatching procedures, and procedures for hedging activity are reasonable and appropriate. The report includes several recommendations for the ACC’s consideration, including review of current contracts, maintenance schedules, and certain changes and improvements to the schedules in APS’s monthly PSA filings. On December 27, 2022, ACC Staff filed a proposed order supporting adoption of the recommendations in the third-party audit report, and the ACC approved the proposed order on February 22, 2023.

On November 30, 2022, APS filed its PSA rate for the PSA year beginning February 1, 2023. To address the growing under-collected PSA balance, APS also requested that one of three different options be adopted, including a temporary or permanent increase of the annual cap to $0.006 per kWh. On February 23, 2023, the ACC approved an overall PSA rate of $0.019074 per kWh, which consisted of a forward component of $(0.005527) per kWh, a historical component of $0.013071 per kWh and a transition component of $0.011530 per kWh, that will continue until further notice of the ACC. The rate became effective with the first billing cycle in March 2023 and is designed to bring the PSA balancing account to near-zero over a 24-month period. APS is also required to notify the ACC when the PSA balancing account approaches $0.5 million.

In accordance with the approved PSA Plan of Administration, on March 15, 2019, APS filed an application with the ACC requesting approval to recover the costs related to two energy storage power purchase tolling agreements through the PSA, and on January 12, 2021, the ACC approved this application. On October 28, 2021, APS filed an application requesting approval to recover costs related to three additional third-party energy storage projects through the PSA once the systems are in service, and on December 16, 2021, the ACC approved this application. On February 22, 2022, APS filed an application requesting similar recovery of the energy storage portion of a third-party solar plus energy storage project through the PSA, and on April 13, 2022, the ACC approved this application. On December 21, 2022, APS filed an application requesting similar recovery through the PSA for the energy storage portion of another third-party solar plus energy storage project, and on February 22, 2023, the ACC approved this application. On March 6, 2023, APS filed an application requesting similar recovery through the PSA for the energy storage portion of another third-party solar plus energy storage project, and on May 2, 2023, the ACC approved this application. The ACC has not yet ruled on the prudency of APS’s acquisition of these projects.

Environmental Improvement Surcharge (“EIS”). The EIS permits APS to recover the capital carrying costs (rate of return, depreciation and taxes) plus incremental operations and maintenance expenses associated with environmental improvements made outside of a test year to comply with environmental standards set by federal, state, tribal, or local laws and regulations. A filing is made on or before February 1 each year for qualified environmental improvements since the prior rate case test year, and the new charge becomes effective April 1 unless suspended by the ACC. The EIS includes an overall cap of $0.0005 per kWh (approximately $13 million to $15 million per year). APS’s February 1, 2023 application requested an increase in the charge to $14.7 million, or $3.3 million over the prior-period charge. On March 10, 2023, APS filed an amended application requesting an EIS charge of $4.0 million, a decrease of $10.7 million from the

Transmission Rates, Transmission Cost Adjustor (“TCA”) and Other Transmission Matters. In July 2008, FERC approved a modification to APS’s Open Access Transmission Tariff to allow APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services. A large portion of the rate represents charges for transmission services to serve APS’s retail customers (“Retail Transmission Charges”). In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA. Under the terms of the settlement agreement entered into in 2012 regarding APS’s rate case (“2012 Settlement Agreement”), however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC.

The formula rate is updated each year effective June 1 on the basis of APS’s actual cost of service, as disclosed in APS’s FERC Form 1 report for the previous fiscal year. Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items. APS reviews the proposed formula rate filing amounts with the ACC Staff. Any items or adjustments which are not agreed to by APS and the ACC Staff can remain in dispute until settled or litigated with FERC. Settlement or litigated resolution of disputed issues could require an extended period of time and could have a significant effect on the Retail Transmission Charges because any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts. The resolution of proposed adjustments can result in significant volatility in the revenues to be collected.

On March 17, 2020, APS made a filing to make modifications to its annual transmission formula to provide additional transparency for excess and deficient accumulated deferred income taxes resulting from the Tax Cuts and Job Act (the “Tax Act”), as well as for future local, state, and federal statutory tax rate changes. APS amended its March 17, 2020 filing on April 28, 2020, September 29, 2021, and October 27, 2021. In January 2022, FERC approved APS’s modifications to its annual transmission formula.

Effective June 1, 2021, APS’s annual wholesale transmission revenue requirement for all users of its transmission system increased by approximately $4 million for the 12-month period beginning June 1, 2021, in accordance with the FERC-approved formula. Of this net amount, wholesale customer rates decreased by approximately $3.2 million and retail customer rates would have increased by approximately $7.2 million. However, since changes in Retail Transmission Charges are reflected through the TCA after consideration of transmission recovery in retail base rates and the ACC approved balancing account, the retail revenue requirement decreased by $28.4 million, resulting in reductions to both residential and commercial rates. An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2021.

Effective June 1, 2022, APS’s annual wholesale transmission revenue requirement for all users of its transmission system decreased by approximately $33 million for the 12-month period beginning June 1, 2022, in accordance with the FERC-approved formula. Of this net amount, wholesale customer rates decreased by approximately $6.4 million and retail customer rates would have decreased by approximately $26.6 million. However, since changes in Retail Transmission Charges are reflected through the TCA after consideration of transmission recovery in retail base rates and the ACC approved balancing account, the retail revenue requirement decreased by $2.4 million, resulting in a reduction to the residential rate and increases to commercial rates. An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2022.

Lost Fixed Cost Recovery Mechanism. The LFCR mechanism permits APS to recover on an after-the-fact basis a portion of its fixed costs that would otherwise have been collected by APS in the kWh sales lost due to APS energy efficiency programs and to DG such as rooftop solar arrays. The fixed costs recoverable by the LFCR mechanism were 2.5 cents for both lost residential and non-residential kWh as set forth in the 2017 Settlement Agreement. The fixed costs recoverable by the LFCR mechanism are currently 2.56 cents for lost residential kWh and 2.68 cents for lost non-residential kWh as set forth in the 2019 Rate Case decision. The LFCR adjustment has a year-over-year cap of 1% of retail revenues. Any amounts left unrecovered in a particular year because of this cap can be carried over for recovery in a future year. The kWhs lost from energy efficiency are based on a third-party evaluation of APS’s energy efficiency programs. DG sales losses are determined from the metered output from the DG units.

On February 15, 2021, APS filed its 2021 annual LFCR adjustment, requesting that effective May 1, 2021, the annual LFCR recovery amount be increased to $38.5 million (an $11.8 million increase from previous levels). On April 13, 2021, the ACC voted not to approve the requested $11.8 million increase to the annual LFCR adjustment; thus, the previously approved rates continued to remain intact and the $11.8 million increase was reflected in APS’s 2022 filing in accordance with the compliance requirements.

As a result of the 2019 Rate Case decision, APS’s annual LFCR adjustor rate will be dependent on an annual earnings test filing, which will compare APS’s previous year’s rate of return with the related authorized rate of return. If the actual rate of return is higher than the authorized rate of return, the LFCR rate for the subsequent year is set at zero. APS determined that the changes to the LFCR mechanism, as a result of the 2019 Rate Case decision effective on December 1, 2021, did not materially impact its results of operations and financial statements for the year ended December 31, 2021. However, as a result of certain changes made to the LFCR mechanism in the 2019 Rate Case decision, the mechanism no longer qualified for alternative revenue program accounting treatment, which impacts the future timing of related revenue recognition.

On February 15, 2022, APS filed its 2022 annual LFCR adjustment, requesting that effective May 1, 2022, the annual LFCR recovery amount be increased to $59.1 million (a $32.5 million increase from previous levels, which was inclusive of the $11.8 million balance from the 2021 filing). On May 9, 2022, the ACC Staff filed its revised report and proposed order regarding APS’s 2022 LFCR adjustment, concluding that APS calculated the adjustment in accordance with its Plan of Administration. On May 18, 2022, the ACC approved the 2022 LFCR adjustment, with a rate effective date of June 1, 2022.

Tax Expense Adjustor Mechanism. As part of the 2017 Settlement Agreement, the parties agreed to a rate adjustment mechanism to address potential federal income tax reform and enable the pass-through of certain income tax effects to customers. The TEAM expressly applies to APS’s retail rates with the exception of a small subset of customers taking service under specially-approved tariffs. On December 22, 2017, the Tax Act was enacted. This legislation made significant changes to the federal income tax laws including a reduction in the corporate tax rate from 35% to 21% effective January 1, 2018.

On March 19, 2020, due to the COVID-19 pandemic, APS delayed the discontinuation of TEAM Phase II until the first billing cycle in May 2020. Amounts credited to customers after the last billing cycle in March 2020 were recorded as a part of the balancing account and were addressed for recovery as part of the 2019 Rate Case. Both the timing of the reduction in revenues refunded through TEAM Phase II and the offsetting income tax benefit were recognized based upon our seasonal kWh sales pattern.

On April 10, 2019, APS filed a third request with the ACC that addressed the amortization of depreciation related excess deferred taxes over a 28.5-year period consistent with IRS normalization rules (“TEAM Phase III”). On October 29, 2019, the ACC approved TEAM Phase III providing both (i) a one-time bill credit of $64 million which was credited to customers on their December 2019 bills, and (ii) a monthly bill credit effective the first billing cycle in December 2019 which provided an additional benefit of $39.5 million to customers through December 31, 2020. On November 20, 2020, APS filed an application to continue the TEAM Phase III monthly bill credit through the earlier of December 31, 2021, or at the conclusion of the 2019 Rate Case. On December 9, 2020, the ACC approved this request. Both the timing of the reduction in revenues refunded through the TEAM Phase III monthly bill credit and the offsetting income tax benefit were recognized based upon APS’s seasonal kWh sales pattern.

APS’s 2017 Rate Case Decision provides that payments by utilities for energy exported to the grid from residential DG solar facilities will be determined using a RCP methodology as determined in the ACC’s generic Value and Cost of Distributed Generation docket. RCP is a method that is based on the most recent five-year rolling average price that APS incurs for utility-scale solar photovoltaic projects. The price established by this RCP method will be updated annually (between general retail rate cases) but will not be decreased by more than 10% per year. The ACC is no longer pursuing development of a forecasted avoided cost methodology as an option for utilities in place of the RCP. Commercial customers, grandfathered residential solar customers, and residential customers with DG systems other than solar facilities continue to qualify for net metering.

In accordance with the 2017 Rate Case Decision, APS filed its request for a RCP export energy price of 10.5 cents per kWh on May 1, 2019. This price also reflects the 10% annual reduction discussed above. The new rate rider became effective on October 1, 2019. APS filed its request for a fourth-year export energy price of 9.4 cents per kWh on May 1, 2020, with a requested effective date of September 1, 2020. This price reflects the 10% annual reduction discussed above. On September 23, 2020, the ACC approved the annual reduction of the export energy price but voted to delay the effectiveness of the reduction in export prices until October 1, 2021. In accordance with this decision, the RCP export energy price of 9.4 cents per kWh became effective on October 1, 2021. On April 29, 2022, APS filed an application to decrease the RCP price to 8.46 cents per kWh, reflecting a 10% annual reduction, to become effective September 1, 2022. On July 12, 2022, the ACC approved the RCP as filed.

On January 30, 2018, the initial Energy Modernization Plan was proposed, which consisted of a series of energy policies tied to clean energy sources. Draft energy rules were subsequently issued and a series of revisions were made to the draft rules in 2019 and 2020. On July 30, 2020, the ACC Staff issued final draft energy rules which proposed 100% of retail kWh sales from clean energy resources by the end of 2050. Nuclear power was defined as a clean energy resource. The proposed rules also required 50% of retail energy served be renewable by the end of 2035. A new Energy Efficiency Standard (“EES”) was not included in the proposed rules.

The ACC discussed the final draft energy rules at several different meetings in 2020 and 2021. On November 13, 2020, the ACC approved a final draft energy rules package. On April 19, 2021, the Administrative Law Judge issued a Recommended Order and Opinion on the final energy rules. In June 2021, the ACC adopted revised clean energy rules based on a series of ACC amendments. The adopted rules included a final standard of 100% clean energy by 2070 and the following interim standards for carbon reduction from baseline carbon emissions level: 50% reduction by December 31, 2032; 65% reduction by December 31, 2040; 80% reduction by December 31, 2050, and 95% reduction by December 31, 2060. Since the adopted clean energy rules differed substantially from the original Recommended Order and Opinion, supplemental rulemaking procedures were required before the rules could become effective. On January 26, 2022, the ACC reversed its prior decision and declined to send the final draft energy rules through the rulemaking process. Instead, the ACC opened a new docket to consider all-source RFP requirements and the IRP process. During the August 2022 Open Meeting, Commissioners voted to postpone a decision on the all-source RFP and IRP rulemaking package until 2023. APS cannot predict the outcome of this matter.

ACC rules require utilities to develop triennial 15-year IRPs which describe how the utility plans to serve customer load in the plan timeframe. The ACC reviews each utility’s IRP to determine if it meets the necessary requirements and whether it should be acknowledged. In February 2022, the ACC acknowledged APS’s 2020 IRP filed on June 26, 2020. The ACC also approved certain amendments to the IRP process, including, setting an EES of 1.3% of retail sales annually (averaged over a three-year period) and a demand-side resource capacity of 35% of 2020 peak demand by January 1, 2030. APS intends to file its next IRP on August 1, 2023. See “Energy Modernization Plan” above for information regarding proposed changes to the IRP filings.

Under the Public Utility Regulatory Policies Act of 1978 (“PURPA”), qualifying facilities are provided the right to sell energy and/or capacity to utilities and are granted relief from certain regulatory burdens. On December 17, 2019, the ACC mandated a minimum contract length of 18 years for qualifying facilities over 100 kW in Arizona and established that the rate paid to qualifying facilities must be based on the long-term avoided cost. “Avoided cost” is generally defined as the price at which the utility could purchase or produce the same amount of power from sources other than the qualifying facility on a long-term basis. During calendar year 2020, APS entered into two 18-year PPAs with qualified facilities, each for 80 MW solar facilities. In March 2021, the ACC approved these agreements.

On June 13, 2019, APS voluntarily suspended electric disconnections for residential customers who had not paid their bills. On June 20, 2019, the ACC voted to enact emergency rule amendments to prevent residential electric utility customer service disconnections during the period June 1 through October 15 (“Summer Disconnection Moratorium”). During the Summer Disconnection Moratorium, APS could not charge late fees and interest on amounts that were past due from customers. Customer deposits must also be used to pay delinquent amounts before disconnection can occur. In accordance with the emergency rules, APS began putting delinquent customers on a mandatory four-month payment plan beginning on October 16, 2019.

In June 2019, the ACC began a formal regular rulemaking process to allow stakeholder input and time for consideration of permanent rule changes. The ACC further ordered that each regulated utility serving retail customers in Arizona update its service conditions by incorporating the emergency rule amendments, restore power to any customers who were disconnected during the month of June 2019 and credit any fees that were charged for a reconnection. The ACC Staff and ACC proposed draft amendments to the customer service disconnections rules. On April 14, 2021, the ACC voted to send to the formal rulemaking process a draft rules package governing customer disconnections that allows utilities to choose between a temperature threshold (above 95 degrees and below 32 degrees) or calendar method (June 1 – October 15) for disconnection moratoriums. On November 2, 2021, the ACC approved the final rules, and on November 23, 2021, the rules were submitted to the Arizona Office of the Attorney General for final review and approval. The new rules became effective on April 18, 2022.

In accordance with the ACC service disconnection rules, APS now uses the calendar-based method to suspend the disconnection of customers for nonpayment from June 1 through October 15 each year (“Annual Disconnection Moratorium”). Customers with past due balances of $75 or greater as of the end of the Annual Disconnection Moratorium are automatically placed on six-month payment arrangements. In addition, APS voluntarily began waiving late payment fees of its customers (“Late Fee Waivers”) on March 13, 2020. Effective February 1, 2023, late payment fees for residential customers were reinstated. Late payment fees for commercial and industrial customers were reinstated effective May 1, 2022. Since the suspensions and moratoriums on disconnections began, APS has experienced an increase in bad debt expense and the related write-offs of delinquent customer accounts.

On November 17, 2018, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona. On July 1 and July 2, 2019, ACC Staff issued a report and initial proposed draft rules regarding possible modifications to the ACC’s retail electric competition rules. On February 10, 2020, two ACC Commissioners filed two sets of draft proposed retail electric competition rules. On February 12, 2020, ACC Staff issued its second report regarding possible modifications to the ACC’s retail electric competition rules. During a July 15, 2020, ACC Staff meeting, the ACC Commissioners discussed the possible development of a retail competition pilot program, but no action was taken. The ACC continues to discuss matters related to retail electric competition, including the potential for additional buy-through programs or other pilot programs. In April 2022, the Arizona Legislature passed and the Governor signed a bill that repealed the electric deregulation law that had been in place in Arizona since 1998. APS cannot predict what impact, if any, this change will have on APS.

On August 4, 2021, Green Mountain Energy filed an application seeking a certificate of convenience and necessity to allow it to provide competitive electric generation service in Arizona. Green Mountain Energy has requested that the ACC grant it the ability to provide competitive service in APS’s and Tucson Electric Power Company’s certificated service territories and proposes to deliver a 100% renewable energy product to residential and general service customers in those service territories. APS opposes Green Mountain Energy’s application. On November 3, 2021, the ACC submitted questions to the Arizona Attorney General requesting legal opinions related to a number of issues surrounding retail electric competition and the ACC’s ability to issue competitive certificates of convenience and necessity. On November 26, 2021, the Administrative Law Judge issued a procedural order indicating it would not be appropriate to set a schedule until the Attorney General has provided his insights on the applicable law. As the ACC’s questions pertained to the retail competition law subsequently repealed in April 2022, the Attorney General has not responded to the ACC’s request and the questions are now moot. No action has been taken by the ACC regarding this application since that time.

On November 14, 2019, APS learned that its rate plan comparison tool was not functioning as intended due to an integration error between the tool and APS’s meter data management system. APS immediately removed the tool from its website and notified the ACC. The purpose of the tool was to provide customers with a rate plan recommendation based upon historical usage data. Upon investigation, APS determined that the error may have affected rate plan recommendations to customers between February 4, 2019, and November 14, 2019. By the middle of May 2020, APS provided refunds to approximately 13,000 potentially impacted customers equal to the difference between what they paid for electricity and the amount they would have paid had they selected their most economical rate, as applicable, and a $25 payment for any inconvenience that the customer may have experienced. The refunds and payment for inconvenience being provided did not have a material impact on APS’s financial statements. In February 2020, APS launched a new online rate comparison tool. The ACC hired an outside consultant to evaluate the extent of the error and the overall effectiveness of the tool. On August 20, 2020, ACC Staff filed the outside consultant’s report on APS’s rate comparison tool. The report concluded APS’s new rate comparison tool is working as intended.

The report also identified a small population of additional customers that may have been affected by the error and APS has provided refunds and the $25 inconvenience payment to approximately 3,800 additional customers. These additional refunds and payment for inconvenience did not have a material impact on APS’s financial statements. On September 28, 2020, the ACC discussed this report but did not take any action. APS cannot predict whether additional inquiries or actions may be taken by the ACC.

On December 29, 2017, in accordance with the 2017 Rate Case Decision, APS filed a Notice of Intent to file its SCR Adjustment to permit recovery of costs associated with the installation of SCR equipment at Four Corners Units 4 and 5. APS filed the SCR Adjustment request in April 2018. The SCR Adjustment request provided that there would be a $67.5 million annual revenue impact that would be applied as a percentage of base rates for all applicable customers. Also, as provided for in the 2017 Rate Case Decision, APS requested that the adjustment become effective no later than January 1, 2019. The hearing for this matter occurred in September 2018. At the hearing, APS accepted ACC Staff’s recommendation of a lower annual revenue impact of approximately $58.5 million. The Administrative Law Judge issued a Recommended Opinion and Order finding that the costs for the SCR project were prudently incurred and recommending authorization of the $58.5 million annual revenue requirement related to the installation and operation of the SCRs. The ACC did not issue a decision on this matter. APS included the costs for the SCR project in the retail rate base in its 2019 Rate Case filing with the ACC.

On November 2, 2021, the 2019 Rate Case decision was approved by the ACC allowing approximately $194 million of SCR related plant investments and cost deferrals in rate base and to recover, depreciate and amortize in rates based on an end-of-life assumption of July 2031. The decision also included a partial and combined disallowance of $215.5 million on the SCR investments and deferrals. APS believes the SCR plant investments and related SCR cost deferrals were prudently incurred, and on December 17, 2021, APS filed its Notice of Direct Appeal at the Arizona Court of Appeals requesting review of the $215.5 million disallowance. The Arizona Court of Appeals heard oral arguments on November 30, 2022. On March 6, 2023, the Court of Appeals issued its order in the matter, vacating the ACC’s disallowance of the SCR investment and remanding the matter back to the ACC for further review in accordance with ACC rules and the order of the Court of Appeals. The parties have until May 8, 2023 to file a petition requesting review by the Arizona Supreme Court. APS cannot predict the outcome of this proceeding. Based on the partial recovery of these investments and cost deferrals in current rates, the favorable Court of Appeals order, and the potential for further appellate review, APS has not recorded an impairment or write-off relating to the SCR plant investments or deferrals as of March 31, 2023. If the 2019 Rate Case decision to disallow $215.5 million of the SCRs is ultimately upheld, APS will be required to record a charge to its results of operations, net of tax, of approximately $154.4 million. See above for further discussion on the 2019 Rate Case decision.

On September 11, 2014, APS announced that it would close Unit 2 of the Cholla Power Plant (“Cholla”) and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if the United States Environmental Protection Agency (“EPA”) approved a compromise proposal offered by APS to meet required environmental and emissions standards and rules. On April 14, 2015, the ACC approved APS’s plan to retire Unit 2, without expressing any view on the future recoverability of APS’s remaining investment in the unit. APS closed Unit 2 on October 1, 2015. In early 2017, EPA approved a final rule incorporating APS’s compromise proposal, which took effect on April 26, 2017. In December 2019, PacifiCorp notified APS that it planned to retire Cholla Unit 4 by the end of 2020 and the unit ceased operation in December 2020. APS is required to cease burning coal at its remaining Cholla units by April 2025.

Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS has been recovering a return on and of the net book value of the unit in base rates. Pursuant to the 2017 Settlement Agreement described above, APS will be allowed continued recovery of the net book value of the unit and the unit’s decommissioning and other retirement-related costs, $36.1 million as of March 31, 2023, in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. In accordance with the 2019 Rate Case decision, the regulatory asset is being amortized through 2033.

APS has been recovering a return on and of the net book value of its interest in the Navajo plant in base rates over its previously estimated life through 2026. Pursuant to the 2019 Rate Case decision described above, APS will be allowed continued recovery of the book value of its remaining investment in the Navajo plant, $50.2 million as of March 31, 2023, in addition to a return on the net book value, with the exception of 15% of the annual amortization expense in rates. In addition, APS will be allowed recovery of other costs related to retirement and closure, including the Navajo coal reclamation regulatory asset, $13.1 million as of March 31, 2023. The disallowed recovery of 15% of the annual amortization does not have a material impact on APS financial statements.


	Amortization Through	March 31, 2023		December 31, 2022
Pension	(a)	$	628,727	$	637,656
Deferred fuel and purchased power (b) (c)	2024	469,962		460,561
Income taxes — allowance for funds used during construction (“AFUDC”) equity	2053	179,818		179,631
Ocotillo deferral (e)	2031	135,766		138,143
SCR deferral (e)(f)	2031	95,588		97,624
Retired power plant costs	2033	94,903		98,692
Deferred fuel and purchased power — mark-to-market (Note 7)	2025	61,858		—
Deferred property taxes	2027	38,915		41,057
Deferred compensation	2036	34,492		33,660
Income taxes — investment tax credit basis adjustment	2056	24,095		23,977
Palo Verde VIEs (Note 6)	2046	20,893		20,933
Active Union Medical Trust	(g)	15,010		18,226
Four Corners cost deferral	2024	13,979		15,999
Navajo coal reclamation	2026	13,117		13,862
Loss on reacquired debt	2038	9,238		9,468
Mead-Phoenix transmission line contributions in aid of construction (“CIAC”)	2050	8,965		9,048
Tax expense adjustor mechanism (b)	2031	5,681		5,845
Lost fixed cost recovery (b)	2023	—		9,547
Other	Various	8,458		8,171
Total regulatory assets (d)		$	1,859,465	$	1,822,100
Less: current regulatory assets		$	600,802	$	538,879
Total non-current regulatory assets		$	1,258,663	$	1,283,221

(a)This asset represents the future recovery of pension benefit obligations and expense through retail rates. If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future revenues. As a result of the 2019 Rate Case Decision, the amount authorized for inclusion in rate base was determined using an averaging methodology, which resulted in a reduced return in retail rates. See Note 5 for further discussion.


	Amortization Through	March 31, 2023		December 31, 2022
Excess deferred income taxes — ACC - Tax Act (a)	2046	$	970,578	$	971,545
Excess deferred income taxes — FERC - Tax Act (a)	2058	221,708		221,877
Asset retirement obligations	2057	396,107		354,002
Other postretirement benefits	(d)	258,955		270,604
Removal costs	(c)	106,102		106,889
Income taxes — change in rates	2051	64,739		64,806
Four Corners coal reclamation	2038	53,348		52,592
Income taxes — deferred investment tax credit	2056	49,031		48,035
Spent nuclear fuel	2027	37,313		39,217
Renewable energy standard (b)	2024	30,188		35,720
Sundance maintenance	2031	17,667		16,893
Property tax deferral (e)	2024	14,353		15,521
Demand side management (b)	2023	14,207		8,461
FERC transmission true up (b)	2025	12,597		22,895
Tax expense adjustor mechanism (b) (e)	N/A	4,835		4,835
Deferred fuel and purchased power — mark-to-market (Note 7)	2025	3,396		96,367
Other	Various	7,415		3,092
Total regulatory liabilities		$	2,262,539	$	2,333,351
Less: current regulatory liabilities		$	202,266	$	271,575
Total non-current regulatory liabilities		$	2,060,273	$	2,061,776