FERC Form

Name of Respondent:

Arizona Public Service Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/24/2023

Year/Period of Report

End of:

2023

IMPORTANT CHANGES DURING THE QUARTER/YEAR

Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in accordance with the inquiries. Each inquiry should be answered. Enter "none," "not applicable," or "NA" where applicable. If information which answers an inquiry is given elsewhere in the report, make a reference to the schedule in which it appears.

Changes in and important additions to franchise rights: Describe the actual consideration given therefore and state from whom the franchise rights were acquired. If acquired without the payment of consideration, state that fact.
Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to Commission authorization.
Purchase or sale of an operating unit or system: Give a brief description of the property, and of the transactions relating thereto, and reference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accounts were submitted to the Commission.
Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Give effective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give reference to such authorization.
Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operations began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of customers added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major new continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location and approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc.
Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as appropriate, and the amount of obligation or guarantee.
Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments.
State the estimated annual effect and nature of any important wage scale changes during the year.
State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any such proceedings culminated during the year.
Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an officer, director, security holder reported on Pages 104 or 105 of the Annual Report Form No. 1, voting trustee, associated company or known associate of any of these persons was a party or in which any such person had a material interest.
(Reserved.)
If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are applicable in every respect and furnish the data required by Instructions 1 to 11 above, such notes may be included on this page.
Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have occurred during the reporting period.
In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30 percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.


1

During the second quarter of 2023, the Yuma County franchise renewal was approved and became effective on May 22, 2023. County franchises do not include the collection and payment of franchise fees.


2

None.


3

None.


4

Lease Reassignments:

Perryville Substation (5-Acre Farm Lease)

Effective Date: 6/8/23

Length of Term: 25 years (4/4/19–4/29/24)

Names of Parties: Arizona Public Service Company (“APS”) and Silverton Ventures LLC (new lessee)

Rents: $1.00 per year

Other conditions: original lease terms did not change; lease was reassigned from prior lessee, Vaquero Company

Name of commission authorizing the lease: APS Land Services Department

Reference to authorization: LE-CA-PRD-0001 Commitment Authority and Signing Procedure

Freedom Substation (45-Acre Farm Lease)

Effective Date: 6/8/23

Length of Term: 5 years (1/1/22–12/31/27)

Names of Parties: APS and Silverton Ventures LLC (new lessee)

Rents: $5,889.00 per year

Other conditions: original lease terms did not change; lease was reassigned from prior lessee, Vaquero Company

Name of commission authorizing the lease: APS Land Services Department

Reference to authorization: LE-CA-PRD-0001 Commitment Authority and Signing Procedure


5

Distribution: None.

Transmission: None.


6

Contractual Obligations

As of June 30, 2023, our fuel and purchased power and purchase obligation commitments have increased by $5.5 billion from the information provided in our 2022 FERC Form 1. The change is primarily due to new purchased power and energy storage commitments and also includes a $505 million reduction of commitments due to the termination of an energy storage purchased power contract for a project that was not developed. The majority of the changes relate to 2025 and thereafter. This amount includes approximately $4.3 billion of commitments relating to purchased power lease contracts. See Note 14.

Other than the items described above, there have been no material changes, as of June 30, 2023, outside the normal course of business in contractual obligations from the information provided in our 2022 FERC Form 1. See Note 5 for discussion regarding changes in our short-term and long-term debt obligations.

Credit Facilities

On April 10, 2023, APS replaced its two $500 million revolving credit facilities that would have matured on May 28, 2026, with a new $1.25 billion revolving credit facility that matures on April 10, 2028. APS has the option to increase the amount of the facility up to a maximum of $400 million, for a total of $1.65 billion, upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on APS’s senior unsecured debt credit ratings and the agreement includes a sustainability-linked pricing metric which permits an interest rate reduction or increase by meeting or missing targets related to specific environmental and employee health and safety sustainability objectives. This facility is available to support APS’s general corporate purposes, including support for APS’s commercial paper program, which was increased from $750 million to $1 billion on April 10, 2023, for bank borrowings or for issuances of letters of credit. At June 30, 2023, APS had no outstanding borrowings under its revolving credit facilities, no letters of credit outstanding under the credit facilities, and $285 million of outstanding commercial paper borrowings.

On January 6, 2023, Pinnacle West contributed $150 million into APS in the form of an equity infusion. APS used this contribution to repay short-term indebtedness.

On June 30, 2023, APS issued $500 million of 5.55% unsecured senior notes that mature August 1, 2033. The net proceeds from the sale were used to repay short-term indebtedness consisting of commercial paper and for general corporate purposes.

See “Financial Assurances” in Note 10 for a discussion of other outstanding letters of credit.

Financial Assurances

In the normal course of business, we obtain standby letters of credit and surety bonds from financial institutions and other third parties. These instruments guarantee our own future performance and provide third parties with financial and performance assurance in the event we do not perform. These instruments support commodity contract collateral obligations and other transactions. As of June 30, 2023, standby letters of credit totaled approximately $0.2 million and will expire in 2023 and 2024. As of June 30, 2023, surety bonds expiring through 2025 totaled approximately $15 million. The underlying liabilities insured by these instruments are reflected on our balance sheets, where applicable. Therefore, no additional liability is reflected for the letters of credit and surety bonds themselves.

We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements. Most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely.

Authorizations

On December 17, 2020, the Arizona Corporation Commission (“ACC”) issued a financing order, Decision No. 77853, in which, subject to specified parameters and procedures, it approved APS’s short-term debt authorization equal to a sum of (i) 7% of APS’s capitalization, and (ii) $500 million (which is required to be used for costs relating to purchases of natural gas and power) and a long-term debt authorization of $7.5 billion.

On December 15, 2022, the ACC issued a financing order, Decision No. 78814, approving APS’s application filed on April 6, 2022 requesting to further increase the long-term debt limit from $7.5 billion to $8.0 billion and to exclude financing lease power purchase agreements (“PPAs”) from the definition of long-term debt for purposes of the ACC financing orders. The order also reaffirmed the short-term debt authorization from the 2020 financing order.


7

None.


8

The non-union annualized wage scale increases for active employees during 2023 as of June 30, 2023, were as follows:


	Type of Cost	Number of Increases	Annualized Costs
a.	Non-Union Base Salary Increases	4,044	13,135,277
b.	Special Increases	411	1,569,207
c.	Promotions	364	3,890,643
	Total	4,819	$	18,595,127

COMMENTS:

a.The overall non-union employee merit budget was 3.0%. Actual merit adjustments ranged from 0% to 7.1% based upon an employee's performance and their pay position within the salary range. Merit pay awards were added to base pay.

b.Salary adjustments to base pay are awarded to non-union employees throughout the year in special instances.

c.Promotions were awarded to union and non-union employees due to changes in job functions or grade level changes.


9

Legal Proceedings

I. LITIGATION & ENVIRONMENTAL MATTERS

Palo Verde Generating Station

Spent Nuclear Fuel and Waste Disposal

On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a second breach of contract lawsuit against the United States Department of Energy (“DOE”) in the United States Court of Federal Claims (“Court of Federal Claims”). The lawsuit sought to recover damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste (“Standard Contract”) for failing to accept Palo Verde’s spent nuclear fuel and high level

waste from January 1, 2007, through June 30, 2011, pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act. On August 18, 2014, APS and DOE entered into a settlement agreement, which required DOE to pay the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007, through June 30, 2011. In addition, the settlement agreement provided APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2016, which was extended to December 31, 2025.

APS has submitted eight claims pursuant to the terms of the August 18, 2014 settlement agreement, for eight separate time periods during July 1, 2011 through June 30, 2021. The DOE has approved and paid $123.9 million for these claims (APS’s share is $36.0 million). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. In accordance with the 2017 Rate Case Decision, this regulatory liability is being refunded to customers. On October 31, 2022, APS filed its ninth claim pursuant to the terms of the August 18, 2014 settlement agreement. On March 16, 2023, the DOE approved a payment in the amount of $14.3 million (APS’s share is $4.2 million), and on April 6, 2023, APS received this payment.

Superfund and Other Related Matters

The Comprehensive Environmental Response Compensation and Liability Act (“Superfund” or “CERCLA”) establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who released, generated, transported to or disposed of hazardous substances at a contaminated site are among the parties who are potentially responsible (each a “PRP”). PRPs may be strictly, jointly, and severally liable for clean-up. On September 3, 2003, the Environmental Protection Agency (“EPA”) advised APS that EPA considers APS to be a PRP in the Motorola 52nd Street Superfund Site, Operable Unit 3 (“OU3”) in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS has agreed with EPA to perform certain investigative activities of the APS facilities within OU3. In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study (“RI/FS”). The RI/FS for OU3 was finalized and submitted to EPA at the end of 2022. APS cannot predict the EPA’s timing with respect to this matter. APS’s estimated costs related to this investigation and study is approximately $3 million. APS anticipates incurring additional expenditures in the future, but because the ultimate remediation requirements are not yet finalized by EPA, at the present time expenditures related to this matter cannot be reasonably estimated.

On August 6, 2013, the Roosevelt Irrigation District (“RID”) filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants. The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID. The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3. As part of a state governmental investigation into groundwater contamination in this area, on January 25, 2015, the Arizona Department of Environmental Quality (“ADEQ”) sent a letter to APS seeking information concerning the degree to which, if any, APS’s current and former ownership of these facilities may have contributed to groundwater contamination in this area. APS responded to ADEQ on May 4, 2015. On December 16, 2016, two RID environmental and engineering contractors filed an ancillary lawsuit for recovery of costs against APS and the other defendants in the RID litigation. That same day, another RID service provider filed an additional ancillary CERCLA lawsuit against certain of the defendants in the main RID litigation but excluded APS and certain other parties as named defendants. Because the ancillary lawsuits concern past costs allegedly incurred by these RID vendors, which were ruled unrecoverable directly by RID in November of 2016, the additional lawsuits do not increase APS’s exposure or risk related to these matters.

On April 5, 2018, RID and the defendants in that particular litigation executed a settlement agreement, fully resolving RID’s CERCLA claims concerning both past and future cost recovery. APS’s share of this settlement was immaterial. In addition, the two environmental and engineering vendors voluntarily dismissed their lawsuit against APS and the other named defendants without prejudice. An order to this effect was entered on April 17, 2018. With this disposition of the case, the vendors may file their lawsuit again in the future. On August 16, 2019, Maricopa County, one of the three direct defendants in the service provider lawsuit, filed a third-party complaint seeking contribution for its liability, if any, from APS and 28 other third-party defendants. On September 30, 2022, the U.S. District Court for the District of Arizona granted partial summary judgment to the direct defendants for $20.7 million of the approximately $21.2 million in CERCLA response costs claimed by the service provider. Based on the court’s denial of the service provider’s motion for reconsideration, the service provider filed a motion for entry of judgment on June 12, 2023, and waived its rights to recover the remaining approximately $500,000 in claimed response costs, for the stated purpose of appealing the September 2022 summary judgment order to the Ninth Circuit Court of Appeals. We are unable to predict the outcome of any further litigation related to the claim for $20.7 million in response costs; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows.

On February 28, 2022, EPA provided APS with a request for information under CERCLA related to APS’s Ocotillo power plant site located in Tempe, Arizona. In particular, EPA seeks information from APS regarding APS’s use, storage, and disposal of substances containing per-and polyfluoroalkyl (“PFAS”) compounds at the Ocotillo power plant site in order to aid EPA’s investigation into actual or threatened releases of PFAS into groundwater within the South Indian Bend Wash (“SIBW”) Superfund site. The SIBW Superfund site includes the APS Ocotillo power plant site. APS filed its response to this information request on April 29, 2022. On January 17, 2023, EPA contacted APS to inform the Company that it would be commencing on-site investigations within the SIBW site, including the Ocotillo power plant, and performing a remedial investigation and feasibility study related to potential PFAS impacts to groundwater over the next two to three years. APS estimates that its costs to oversee and participate in the remedial investigation work will be approximately $1.7 million. At the present time, we are unable to predict the outcome of this matter and any further expenditures related to necessary remediation, if any, or further investigations cannot be reasonably estimated.

Four Corners SCR Cost Recovery

As part of APS’s 2019 Rate Case, APS included recovery of the deferral and rate base effects of the Four Corners Power Plant (“Four Corners”) selective catalytic reduction (“SCR”) project. 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. On June 21, 2023, the ACC approved a joint settlement filed by APS and the ACC’s Legal Division that resolved all issues relating to the 2019 Rate Case decision, including recovery of the cost of the Four Corners SCRs. See “Four Corners SCR Cost Recovery” and “2019 Retail Rate Case” below for additional information.

Environmental Matters

APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions of both conventional pollutants and greenhouse gases (“GHGs”), water quality, wastewater discharges, solid waste, hazardous waste, and coal combustion residuals (“CCRs”). These laws and regulations can change from time to time, imposing new obligations on APS resulting in increased capital, operating, and other costs. Associated capital expenditures or operating costs could be material. APS intends to seek recovery of any such environmental compliance costs through our rates but cannot predict whether it will obtain such recovery. The following proposed and final rules involve material compliance costs to APS.

Coal Combustion Waste. On December 19, 2014, EPA issued its final regulations governing the handling and disposal of CCR, such as fly ash and bottom ash. The rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act (“RCRA”) and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions. These criteria include standards governing location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and internet posting requirements. The rule generally requires any existing unlined CCR surface impoundment to stop receiving CCR and either retrofit or close, and further requires the closure of any CCR landfill or surface impoundment that cannot meet the applicable performance criteria for location restrictions or structural integrity. Such closure requirements are deemed “forced closure” or “closure for cause” of unlined surface impoundments and are the subject of the regulatory and judicial activities described below.

Since these regulations were finalized, EPA has taken steps to substantially modify the federal rules governing CCR disposal. While certain changes have been prompted by utility industry petitions, others have resulted from judicial review, court-approved settlements with environmental groups, and statutory changes to RCRA. The following lists the pending regulatory changes that, if finalized, could have a material impact as to how APS manages CCR at its coal-fired power plants:

•Following the passage of the Water Infrastructure Improvements for the Nation Act in 2016, EPA possesses authority to either authorize states to develop their own permit programs for CCR management or issue federal permits governing CCR disposal both in states without their own permit programs and on tribal lands. Although ADEQ has taken steps to develop a CCR permitting program, and new state legislation has been adopted providing ADEQ with appropriate permitting authority for CCR under the state solid waste management program, it is not clear when that program will be put into effect. On December 19, 2019, EPA proposed its own set of regulations governing the issuance of CCR management permits, which would impact facilities like Four Corners located on the Navajo Nation. The proposal remains pending.

•On March 1, 2018, as a result of a settlement with certain environmental groups, EPA proposed adding boron to the list of constituents that trigger corrective action requirements to remediate groundwater impacted by CCR disposal activities. Apart from a subsequent proposal issued on August 14, 2019, to add a specific, health-based groundwater protection standard for boron, EPA has yet to take action on this proposal.

•With respect to APS’s Cholla Power Plant (“Cholla”) facility, APS’s application for alternative closure was submitted to EPA on November 30, 2020. While EPA has deemed APS’s application administratively “complete,” the Agency’s approval remains pending. If granted, this application would allow the continued disposal of CCR within Cholla’s existing unlined CCR surface impoundments until the required date for ceasing coal-fired boiler operations in April

2025. This application will be subject to public comment and, potentially, judicial review. We expect to have a proposed decision from EPA regarding Cholla sometime in 2023.

•On May 18, 2023, EPA published a proposal that expands the scope of federal CCR regulations to address the impacts from historical CCR disposal activities that would have ceased prior to 2015. EPA proposes to define a new class of CCR management units (“CCRMUs”) that broadly encompass any location at an operating coal-fired power plant where CCR would have been placed on land. As proposed, this would include not only historically closed landfills and surface impoundments but also prior applications of CCR beneficial use. EPA expects to finalize this proposal by spring of 2024.

We cannot at this time predict the outcome of these regulatory proceedings or when EPA will take final action on those matters that are still pending. Depending on the eventual outcome, the costs associated with APS’s management of CCR could materially increase, which could affect APS’s financial position, results of operations, or cash flows.

APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners. APS estimates that its share of incremental costs to comply with the CCR rule for Four Corners is approximately $30 million and its share of incremental costs to comply with the CCR rule for Cholla is approximately $19 million. The Navajo Generating Station (“Navajo Plant”) disposed of CCR only in a dry landfill storage area. To comply with the CCR rule for the Navajo Plant, APS’s share of incremental costs was approximately $1 million, which has been incurred. Additionally, the CCR rule requires ongoing, phased groundwater monitoring.

As of October 2018, APS has completed the statistical analyses for its CCR disposal units that triggered assessment monitoring. APS determined that several of its CCR disposal units at Cholla and Four Corners will need to undergo corrective action. In addition, under the current regulations, all such disposal units must have ceased operating and initiated closure by April 11, 2021, at the latest (except for those disposal units subject to alternative closure). APS completed the assessments of corrective measures on June 14, 2019; however, additional investigations and engineering analyses that will support the remedy selection are still underway. In addition, APS will also solicit input from the public and host public hearings as part of this process. Based on the work performed to date, APS currently estimates that its share of corrective action and monitoring costs at Four Corners will likely range from $10 million to $15 million, which would be incurred over 30 years. As to Cholla, APS currently estimates that its share of corrective action and monitoring costs at this facility will likely range from $35 million to $40 million, which similarly would be incurred over 30 years. As APS continues to implement the CCR rule’s corrective action assessment process, the current cost estimates may change. Given uncertainties that may exist until we have fully completed the corrective action assessment and final remedy selection process, APS cannot predict any ultimate impacts to APS; however, at this time APS does not believe that any potential changes to the cost estimate for Four Corners or Cholla would have a material impact on its financial position, results of operations or cash flows.

EPA Power Plant Carbon Regulations. EPA’s regulation of carbon dioxide emissions from electric utility power plants has proceeded in fits and starts over most of the last decade. Starting on August 3, 2015, EPA finalized the Clean Power Plan, which was the Agency’s first effort at such regulation through system-wide generation dispatch shifting. Those regulations were subsequently repealed by the EPA on June 19, 2019 and replaced by the Affordable Clean Energy (“ACE”) regulations, which were a far narrower set of rules. While the U.S. Court of Appeals for the D.C. Circuit subsequently vacated the ACE regulations on January 19, 2021, and ordered a remand for EPA to develop replacement regulations consistent with the

original 2015 Clean Power Plan, the U.S. Supreme Court subsequently reversed that decision on June 30, 2022, holding that the Clean Power Plan exceeded EPA’s authority under the Clean Air Act.

In the latest set of proposed rules, released on May 23, 2023, EPA contemplates emission standards and guidelines for various subcategories of new and existing power plants. Unlike EPA’s Clean Power Plan regulations from 2015, which took a broad, system-wide approach to regulating carbon emissions from electric utility fossil-fuel burning power plants, the most recent proposal is limited to measures that can be installed at individual power plants to limit planet-warming emissions.

As such, for new natural gas-fired combustion turbine power plants, EPA is proposing that carbon emission performance standards apply based on the annual capacity factors. For the highest utilization combustion turbines, EPA is therefore proposing that such facilities be retrofitted for carbon capture and sequestration or utilization controls (“CCS”) or varying levels of hydrogen gas (“H2”) co-firing. As for existing natural gas-fired combustion turbines, EPA is imposing similar control requirements at large, high utilization generating units, but is otherwise not proceeding at this time with further regulation. As such, under EPA’s proposal, this means that both new and existing peaking gas-fired combustion turbines (i.e., those with a 20% or less annual capacity factor) are effectively unregulated under the proposed regulations.

For coal-fired power plants, instead of imposing regulations based on capacity and utilization, EPA has developed subcategories based on planned retirement dates. This means that facilities retiring between 2030 and before 2040 must meet increasingly stringent emission limits up to natural-gas co-firing starting in 2030. However, for those facilities with no planned retirement date prior to 2040, EPA is requiring those plants to be retrofitted with CCS controls by 2030.

EPA expects to take final action on this proposal by spring or summer of 2024. At this time, APS cannot predict the outcome of this rulemaking or when EPA will take final action. In addition, APS is continuing to evaluate this proposal and its potential impact on APS’s operations. Depending on the eventual outcome, the costs associated with APS’s operation of its current and future thermal power plants could materially increase, which could affect APS’s financial position, results of operations, or cash flows.

Other environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standard and other rules or matters involving the Clean Air Act, Clean Water Act, Endangered Species Act, RCRA, Superfund, the Navajo Nation, and water supplies for our power plants. The financial impact of complying with current and future environmental rules could jeopardize the economic viability of APS’s fossil-fuel powered plants or the willingness or ability of power plant participants to fund any required equipment upgrades or continue their participation in these plants. The economics of continuing to own certain resources, particularly our coal plants, may deteriorate, warranting early retirement of those plants, which may result in asset impairments. APS would seek recovery in rates for the book value of any remaining investments in the plants, as well as other costs related to early retirement, but cannot predict whether it would obtain such recovery.

Four Corners National Pollutant Discharge Elimination System (“NPDES”) Permit

The latest NPDES permit for Four Corners was issued on September 30, 2019. Based upon a November 1, 2019 filing by several environmental groups, the Environmental Appeals Board (“EAB”) took up review of the Four Corners NPDES Permit. The EAB denied the environmental group petition on September 30, 2020. While on January 22, 2021, the environmental groups filed a petition for review of the EAB’s decision with the U.S. Court of Appeals for the Ninth Circuit, the parties to the litigation (including APS) finalized a settlement on May 2, 2022. This settlement requires investigation of thermal wastewater

discharges from Four Corners, administratively closes the litigation filed in January of 2021, and is not expected to have a material impact on APS’s financial position, results of operations, or cash flows.

II. REGULATORY MATTERS

2022 Retail Rate Case

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 principal provisions of APS’s application are:

•a test year comprised of twelve months ended June 30, 2022, adjusted as described below;

•an original cost rate base of $10.5 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits;

•the following proposed capital structure and costs of capital:


	Capital Structure		Cost of Capital
Long-term debt	48.07	%	3.85	%
Common stock equity	51.93	%	10.25	%
Weighted-average cost of capital			7.17	%

•a 1% return on the increment of fair value rate base above APS’s original cost rate base, as provided for by Arizona law;

•a rate of $0.038321 per kWh for the portion of APS’s retail base rates attributable to fuel and purchased power costs (“Base Fuel Rate”);

•modification of its adjustment mechanisms including:

•eliminate the Environmental Improvement Surcharge (“EIS”) and collect costs through base rates,

▪eliminate the Lost Fixed Cost Recovery (“LFCR”) mechanism and collect costs through base rates and the Demand Side Management Adjustment Charge (“DSMAC”),

▪maintain as inactive the Tax Expense Adjustor Mechanism (“TEAM”),

▪maintain the Transmission Cost Adjustment (“TCA”) mechanism,

▪modify the performance incentive in the DSMAC, and

▪modify the Renewable Energy Adjustment Charge (“REAC”) to include recovery of capital carrying costs of APS owned renewable and storage resources;

•changes to its limited-income program, including a second tier to provide an additional discount for customers with greater need; and

•twelve months of post-Test Year plant investments to reflect used and useful projects that will be placed into service prior to July 1, 2023.

On June 5, 2023 and June 15, 2023, the ACC Staff, the Residential Utility Consumer Office (“RUCO”) and other intervenors filed their initial written testimony with the ACC. The ACC Staff recommends, among other things, (i) a $251 million revenue increase or, as an alternative, a $312 million revenue increase, (ii) a 9.6% return on equity, (iii) a 0.0% fair value increment or, as an alternative, a 0.75% fair value increment, and (iv) a continuation of a 12-month post-test year plant. RUCO recommends, among other things, (i) an $84.9 million revenue increase, (ii) an 8.2% return on equity or, as an alternative, an 8.7%

return on equity if the ACC imputes a hypothetical capital structure with a 46% equity layer, (iii) a fair value increment of 0.0%, and (iv) a reduction of post-test year plant to six months.

On July 12, 2023, APS filed rebuttal testimony addressing the ACC Staff and intervenors’ direct testimonies. The principal provisions of APS’s rebuttal testimony are:

•reducing the revenue requirement increase to $383.1 million;

•maintaining a return on equity request of 10.25%;

•reducing the increment of fair value rate base return to 0.5% from 1.0%;

•maintaining a post-test year plant request of 12 months, plus the Four Corners Effluent Limitation Guidelines (“ELG”) project;

•withdrawing the Payment Fee Removal Proposal (net reduction) which was originally requested in APS’s initial application;

•maintaining the LFCR mechanism and DSMAC as separate adjustors;

•increasing the Power Supply Adjustment (“PSA”) annual rate change limit from $0.004/kWh to $0.006/kWh;

•proposing a new System Reliability Benefit (“SRB”) recovery mechanism;

•maintaining the REAC in its current state;

•maintaining adjustor base transfers and elimination of EIS; and

•maintaining the request to recover Coal Community Transition (“CCT”) funding.

On July 26, 2023, the ACC Staff, RUCO and other intervenors filed their surrebuttal testimony with the ACC. The ACC Staff adjusted their initial recommendations to, among other things, (i) a $281.9 million revenue increase, (ii) a 9.68% return on equity, (iii) a 0.5% fair value increment, (iv) a continuation of a 12-month post-test year plant that includes the Four Corners ELG project, and (v) support of an increase to the annual PSA increase limit to $0.006/kWh. RUCO maintained their direct position and also recommended further review of the PSA in a second phase of the 2022 Rate Case.

APS’s rejoinder testimony is due on August 4, 2023.

APS requested that the increase become effective December 1, 2023. The hearing for this rate case is currently scheduled to begin in August 2023. APS cannot predict the outcome of its request.

2019 Retail Rate Case

On October 31, 2019, APS filed an application with the ACC for an annual increase in retail base rates (the “2019 Rate Case”). On August 2, 2021, an Administrative Law Judge issued a Recommended Opinion and Order in the 2019 Rate Case (the “2019 Rate Case ROO”) and issued corrections on September 10 and September 20, 2021.

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 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, 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%, which includes a 20-basis point penalty, (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.

Consistent with the 2019 Rate Case decision, APS implemented the new rates effective as of December 1, 2021. In addition, the ACC ordered extensive compliance and reporting obligations. APS completed the implementation of the new on-peak hours for residential customers before the September 1, 2022 deadline.

Additionally, consistent with the 2019 Rate Case decision, as of July 2023, APS 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.

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. 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. The ACC filed an appeal on May 8, 2023, and on May 15, 2023, requested a suspension of the case to allow for settlement discussions between the parties, which was approved by the Court.

On June 14, 2023, APS and the ACC Legal Division filed a joint resolution to allow recovery of the $215.5 million in costs related to the installation of the Four Corners SCR, a reversal of the 20-basis point reduction to APS’s return on equity from 8.9% to 8.7% as a result of the 2019 Rate Case Decision, and recovery of $59.6 million in revenue lost by APS between December of 2021 and June 20, 2023. On June 21, 2023, the ACC approved the joint resolution, and the proposals in the joint resolution became effective on July 1, 2023. On July 18, 2023, the Sierra Club filed an application for rehearing of the Commission’s decision. If the Commission does not grant the application within 20 days, it will be deemed denied. The Sierra Club will have 30 days after resolution of its request for rehearing to file a notice of appeal to Arizona Court of Appeals.

Matter of Impact of the Closures of Fossil-Based Generation Plan on Impacted Communities

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.

Information Technology ACC Investigation

On December 16, 2021, the ACC opened an investigation into various matters related to APS’s Information Technology department, including information about technology projects, costs, vendor management leadership and decision making. APS is cooperating with the investigation. APS cannot predict the outcome of this matter.

2016 Retail Rate Case Filing and the 2017 Settlement Agreement

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.

On August 15, 2017, the ACC approved the 2017 Settlement Agreement without material modifications, and on August 18, 2017, the ACC issued a final written Opinion and Order reflecting its decision in APS’s general retail rate case (the “2017 Rate Case Decision”). The new rates went into effect on August 19, 2017.

See “Rate Plan Comparison Tool and Investigation” below for information regarding a review and investigation pertaining to the rate plan comparison tool offered to APS customers and other related issues.

Cost Recovery Mechanisms

APS has received regulatory decisions that allow for more timely recovery of certain costs outside of a general retail rate case through the following recovery mechanisms. See “2022 Retail Rate Case” above for proposed modifications of adjustment mechanisms in the 2022 Rate Case.

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 2015, the ACC revised the RES rules to allow the ACC to consider all available information, including the number of rooftop solar arrays in a utility’s service territory, to determine compliance with the RES.

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 REAC 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 integrated resource plan (“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.

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 supported 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 proposed 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 contained funding for programs to comply with Commission-approved initiatives, including the 2019 Rate Case decision. APS’s budget proposal supported existing approved projects and commitments and requested 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.

On June 30, 2023, APS filed its 2024 RES Implementation Plan and proposed a budget of approximately $95.1 million. APS’s budget proposal supports existing approved projects and commitments and requests a waiver of the RES renewable energy credit requirements to demonstrate compliance with the Annual Renewable Energy Requirement for 2023. The ACC has not yet ruled on the 2024 RES Implementation Plan.

Demand Side Management Adjustor Charge. The ACC Electric Energy Efficiency Standards (“EES”) 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 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. On May 31, 2023, APS filed an amended 2023 DSM Implementation Plan. The amended plan maintains the originally proposed budget of $88 million. The ACC has not yet ruled on the 2023 DSM Implementation Plan.

In accordance with an extension granted by the ACC, APS intends to file its 2024 DSM Implementation Plan by November 30, 2023.

Power Supply Adjustor Mechanism and Balance. The PSA provides for the adjustment of retail rates to reflect variations primarily in retail fuel and purchased power costs. The PSA is subject to specified parameters and procedures, including the following:

•APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate;

•an adjustment to the PSA rate is made annually each February 1 (unless otherwise approved by the ACC) and goes into effect automatically unless suspended by the ACC;

•the PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which is reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point);

•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

•the PSA rate may not be increased or decreased more than $0.004 per kWh in a year without permission of the ACC.

The following table shows the changes in the deferred fuel and purchased power regulatory asset for 2023 and 2022 (dollars in thousands):


	Six Months Ended June 30,
	2023		2022
Beginning balance	$	460,561	$	388,148
Deferred fuel and purchased power costs — current period	191,304		98,707
Amounts charged to customers	(218,586)		(96,842)
Ending balance	$	433,279	$	390,013

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 was 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, 2021, APS filed its PSA rate for the PSA year beginning February 1, 2022. That rate was $0.007544 per kWh, which consisted of a forward component of $(0.004842) per kWh and a historical component of $0.012386 per kWh. The 2022 PSA rate was a $0.004 per kWh increase compared to the 2021 PSA year, which is the maximum permitted under the Plan of Administration for the PSA. These rates went into effect as filed on February 1, 2022.

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 PSA Plan of Administration, APS is required to seek ACC approval to recover costs related to third-party energy storage systems through its PSA adjustment mechanism. To date in 2023, APS has executed six energy storage PPAs whose costs have been approved for recovery through the PSA. APS executed one energy storage PPA in 2022 that was approved for cost-recovery through the PSA and four in 2021, excluding one energy storage PPA that was approved but later terminated by APS due to project delays.

Environmental Improvement Surcharge. 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 February EIS request and a decrease of $7.5 million from the prior-period charge. The revised 2023 EIS became effective with the first billing cycle in April 2023.

Transmission Rates, Transmission Cost Adjustor 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 submitted 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.

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.

Effective June 1, 2023, APS’s annual wholesale transmission revenue requirement for all users of its transmission system increased by approximately $34.7 million for the 12-month period beginning June 1, 2023, in accordance with the FERC-approved formula. Of this net amount, wholesale customer rates increased by approximately $20.7 million and retail customer rates would have increased by approximately $14 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 $10 million, resulting in reductions to the residential and commercial rates. An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2023.

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 2.50 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.

On February 15, 2023, APS filed a letter to the ACC docket stating that, in accordance with Decision No. 78585, APS and ACC Staff have agreed to move the filing date for the annual LFCR adjustment to July 31 each year. On July 31, 2023, APS filed its 2023 annual LFCR adjustment, requesting that effective November 1, 2023, the annual LFCR recovery amount be increased to $68.7 million (a $9.6 million increase from previous levels). The ACC has not yet ruled on this application.

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 August 13, 2018, APS filed a request with the ACC that addressed the return of $86.5 million in tax savings to customers related to the amortization of non-depreciation related excess deferred taxes previously collected from customers (“TEAM Phase II”). The ACC approved this request on March 13, 2019, effective the first billing cycle in April 2019 through the last billing cycle in March 2020.

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.

As part of the 2019 Rate Case decision, the TEAM rates were reset to zero beginning December 31, 2021, and all impacts of the Tax Act were removed from the TEAM and incorporated into APS’s base rates. The TEAM was retained to address potential changes in tax law that may be enacted prior to a decision in a subsequent APS rate case.

Court Resolution Surcharge (“CRS”). The CRS mechanism permits APS to recover certain costs associated with investments and expenses for APS’s purchase and installation of SCR technology for Four Corners Units 4 and 5 and a change in APS’s allowable return on equity as required by the Arizona Court of Appeals and approved by the ACC in Decision No. 78979. The CRS went into effect on July 1, 2023 at a rate of $0.00175 per kWh. The rate is designed to recover $59.6 million in revenue lost by APS between December of 2021 and June 20, 2023, and the prospective recovery of ongoing costs related to the SCR investments and expense and the allowable return on equity difference in current base rates. The current CRS will be recalculated at the end of the 2022 Rate Case to remove the effects of the prospective recovery related to the allowable return on equity difference. The portion of the CRS representing the recovery of lost revenue between December of 2021 and June 20, 2023 will cease upon full collection of the lost revenue. Finally, recovery of ongoing costs related to the SCR investments will continue until the Company’s next rate case in which they can be incorporated therein. See “2019 Retail Rate Case” above for more information.

Net Metering

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 Resource Comparison Proxy (“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 addition, the ACC made the following determinations in the Value and Cost of Distributed Generation docket:

•RCP customers who have interconnected a DG system or submitted an application for interconnection for DG systems will be grandfathered for a period of 20 years from the date the customer’s interconnection application was accepted by the utility (for APS residential customers, as of September 1, 2017, based on APS’s 2017 Rate Case Decision);

•customers with DG solar systems are to be considered a separate class of customers for ratemaking purposes; and

•once an initial export price is set for utilities, no netting or banking of retail credits will be available for new DG customers, and the then-applicable export price will be guaranteed for new customers for a period of 10 years.

This decision of the ACC addresses policy determinations only. The decision states that its principles will be applied in future general retail rate cases, and the policy determinations themselves may be subject to future change, as are all ACC policies.

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 May 1, 2023, APS filed an application for revisions to the RCP. This application would decrease the RCP price to 7.619 cents per kWh, reflecting a 10% annual reduction, to become effective September 1, 2023. The ACC has not yet ruled on this application.

Energy Modernization Plan

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 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.

Integrated Resource Planning

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.

On May 1, 2023, APS, Tucson Electric Power Company, and UNS Electric, Inc. filed a joint request for an extension to file the IRPs from August 1, 2023 to November 1, 2023. On June 21, 2023, the ACC granted the extension. As a result, APS intends to file its next IRP on November 1, 2023. See “Energy Modernization Plan” above for information regarding proposed changes to the IRP filings.

Public Utility Regulatory Policies Act

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 July 16, 2020, FERC issued a final rule revising FERC’s regulations implementing PURPA. The final rule went into effect on December 31, 2020.

Residential Electric Utility Customer Service Disconnections

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.

Retail Electric Competition Rules

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. However, on May 17, 2023, the Retail Energy Supply Association filed a motion with the ACC requesting it to re-open the generic docket to re-examine the ACC’s electric competition rules. No action has been taken by the ACC regarding this motion. APS cannot predict the outcome of these matters.

On October 28, 2021, an ACC Commissioner docketed a letter directing ACC Staff and interested stakeholders to design a 200 to 300 MW pilot program that would allow residential and small commercial customers of APS to elect a competitive electricity supplier. The letter also states that similar programs should be designed for other Arizona regulated electric utilities. APS cannot predict the outcome of these future activities.

Rate Plan Comparison Tool and Investigation

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.

Four Corners SCR Cost Recovery

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. On June 21, 2023, the ACC approved a joint settlement filed by APS and the ACC’s Legal Division that resolved all issues relating to the 2019 Rate Case decision, including recovery of the cost of the Four Corners SCRs. See above for further discussion on the 2019 Rate Case decision.

Cholla

On September 11, 2014, APS announced that it would close Unit 2 of Cholla and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if 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, $34.9 million as of June 30, 2023, in addition to a return on its investment. In accordance with generally accepted accounting principles (“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.

Navajo Plant

The Navajo Plant ceased operations in November 2019. The co-owners and the Navajo Nation executed a lease extension on November 29, 2017, that allows for decommissioning activities to begin after the plant ceased operations. In accordance with GAAP, in the second quarter of 2017, APS’s remaining net book value of its interest in the Navajo Plant was reclassified from property, plant and equipment to a regulatory asset.

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, $47.8 million as of June 30, 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, $12.4 million as of June 30, 2023. The disallowed recovery of 15% of the annual amortization does not have a material impact on APS financial statements.


10

None.


13

Board and Officer Elections, Retirements, Resignations and Changes During 2023:

Board and Officer Elections, Retirements, Resignations and Changes During Second Quarter 2023:

Directors – Note – all of the Directors are voted on or reappointed in May.

Officers – Note – all of the officers are re-elected in May.

•Dale E. Klein retired the Board of Directors effective May 17, 2023

•David P. Wagener resigned from the Board of Directors effective April 27, 2023

•Shannon Standaert elected VP, Human Resources on June 21, 2023, to be effective June 26, 2023.


14

N/A

Name of Respondent:

Arizona Public Service Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/24/2023

Year/Period of Report

End of:

2023

COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line No.	Title of Account (a)	Ref. Page No. (b)	Current Year End of Quarter/Year Balance (c)	Prior Year End Balance 12/31 (d)
1	UtilityPlantAbstract UTILITY PLANT
2	UtilityPlant Utility Plant (101-106, 114)	200	26,297,662,505	24,515,009,011
3	ConstructionWorkInProgress Construction Work in Progress (107)	200	1,296,260,650	1,712,700,234
4	UtilityPlantAndConstructionWorkInProgress TOTAL Utility Plant (Enter Total of lines 2 and 3)		27,593,923,155	26,227,709,245
5	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115)	200	9,128,837,178	8,823,869,641
6	UtilityPlantNet Net Utility Plant (Enter Total of line 4 less 5)		18,465,085,977	17,403,839,604
7	NuclearFuelInProcessOfRefinementConversionEnrichmentAndFabrication Nuclear Fuel in Process of Ref., Conv., Enrich., and Fab. (120.1)	202	128,033,041	118,776,703
8	NuclearFuelMaterialsAndAssembliesStockAccountMajorOnly Nuclear Fuel Materials and Assemblies-Stock Account (120.2)			1,681
9	NuclearFuelAssembliesInReactorMajorOnly Nuclear Fuel Assemblies in Reactor (120.3)		222,350,788	226,277,637
10	SpentNuclearFuelMajorOnly Spent Nuclear Fuel (120.4)
11	NuclearFuelUnderCapitalLeases Nuclear Fuel Under Capital Leases (120.6)
12	AccumulatedProvisionForAmortizationOfNuclearFuelAssemblies (Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5)	202	122,331,474	126,156,617
13	NuclearFuelNet Net Nuclear Fuel (Enter Total of lines 7-11 less 12)		228,052,355	218,896,042
14	UtilityPlantAndNuclearFuelNet Net Utility Plant (Enter Total of lines 6 and 13)		18,693,138,332	17,622,735,646
15	OtherElectricPlantAdjustments Utility Plant Adjustments (116)
16	GasStoredUndergroundNoncurrent Gas Stored Underground - Noncurrent (117)
17	OtherPropertyAndInvestmentsAbstract OTHER PROPERTY AND INVESTMENTS
18	NonutilityProperty Nonutility Property (121)		7,408,963	7,408,963
19	AccumulatedProvisionForDepreciationAndAmortizationOfNonutilityProperty (Less) Accum. Prov. for Depr. and Amort. (122)		47,531	35,956
20	InvestmentInAssociatedCompanies Investments in Associated Companies (123)
21	InvestmentInSubsidiaryCompanies Investment in Subsidiary Companies (123.1)	224
23	NoncurrentPortionOfAllowances Noncurrent Portion of Allowances	228
24	OtherInvestments Other Investments (124)
25	SinkingFunds Sinking Funds (125)
26	DepreciationFund Depreciation Fund (126)
27	AmortizationFundFederal Amortization Fund - Federal (127)
28	OtherSpecialFunds Other Special Funds (128)		1,904,357,843	1,810,587,905
29	SpecialFunds Special Funds (Non Major Only) (129)
30	DerivativeInstrumentAssetsLongTerm Long-Term Portion of Derivative Assets (175)		20,857,061	49,776,549
31	DerivativeInstrumentAssetsHedgesLongTerm Long-Term Portion of Derivative Assets - Hedges (176)
32	OtherPropertyAndInvestments TOTAL Other Property and Investments (Lines 18-21 and 23-31)		1,932,576,336	1,867,737,461
33	CurrentAndAccruedAssetsAbstract CURRENT AND ACCRUED ASSETS
34	CashAndWorkingFunds Cash and Working Funds (Non-major Only) (130)
35	Cash Cash (131)		27,479	192,870
36	SpecialDeposits Special Deposits (132-134)
37	WorkingFunds Working Fund (135)		3,773,000	3,773,020
38	TemporaryCashInvestments Temporary Cash Investments (136)		1,301	75,644
39	NotesReceivable Notes Receivable (141)
40	CustomerAccountsReceivable Customer Accounts Receivable (142)		360,920,385	363,542,814
41	OtherAccountsReceivable Other Accounts Receivable (143)		109,503,273	85,176,917
42	AccumulatedProvisionForUncollectibleAccountsCredit (Less) Accum. Prov. for Uncollectible Acct.-Credit (144)		19,806,240	23,777,703
43	NotesReceivableFromAssociatedCompanies Notes Receivable from Associated Companies (145)
44	AccountsReceivableFromAssociatedCompanies Accounts Receivable from Assoc. Companies (146)		126	160,083
45	FuelStock Fuel Stock (151)	227	34,659,710	30,531,924
46	FuelStockExpensesUndistributed Fuel Stock Expenses Undistributed (152)	227
47	Residuals Residuals (Elec) and Extracted Products (153)	227
48	PlantMaterialsAndOperatingSupplies Plant Materials and Operating Supplies (154)	227	441,943,549	408,533,750
49	Merchandise Merchandise (155)	227
50	OtherMaterialsAndSupplies Other Materials and Supplies (156)	227
51	NuclearMaterialsHeldForSale Nuclear Materials Held for Sale (157)	202/227
52	AllowanceInventoryAndWithheld Allowances (158.1 and 158.2)	228	15,397,749	9,622,639
53	NoncurrentPortionOfAllowances (Less) Noncurrent Portion of Allowances	228
54	StoresExpenseUndistributed Stores Expense Undistributed (163)	227	791,946	1,946,988
55	GasStoredCurrent Gas Stored Underground - Current (164.1)
56	LiquefiedNaturalGasStoredAndHeldForProcessing Liquefied Natural Gas Stored and Held for Processing (164.2-164.3)
57	Prepayments Prepayments (165)		93,265,030	49,805,891
58	AdvancesForGas Advances for Gas (166-167)
59	InterestAndDividendsReceivable Interest and Dividends Receivable (171)
60	RentsReceivable Rents Receivable (172)
61	AccruedUtilityRevenues Accrued Utility Revenues (173)		216,739,663	164,764,276
62	MiscellaneousCurrentAndAccruedAssets Miscellaneous Current and Accrued Assets (174)		36,873,152	36,186,092
63	DerivativeInstrumentAssets Derivative Instrument Assets (175)		43,732,890	153,260,923
64	DerivativeInstrumentAssetsLongTerm (Less) Long-Term Portion of Derivative Instrument Assets (175)		20,857,061	49,776,549
65	DerivativeInstrumentAssetsHedges Derivative Instrument Assets - Hedges (176)
66	DerivativeInstrumentAssetsHedgesLongTerm (Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176)
67	CurrentAndAccruedAssets Total Current and Accrued Assets (Lines 34 through 66)		1,316,965,700	1,234,019,579
68	DeferredDebitsAbstract DEFERRED DEBITS
69	UnamortizedDebtExpense Unamortized Debt Expenses (181)		49,982,728	48,266,270
70	ExtraordinaryPropertyLosses Extraordinary Property Losses (182.1)	230a
71	UnrecoveredPlantAndRegulatoryStudyCosts Unrecovered Plant and Regulatory Study Costs (182.2)	230b
72	OtherRegulatoryAssets Other Regulatory Assets (182.3)	232	1,822,781,002	1,802,266,062
73	PreliminarySurveyAndInvestigationCharges Prelim. Survey and Investigation Charges (Electric) (183)		2,482,675	2,168,960
74	PreliminaryNaturalGasSurveyAndInvestigationChargesAndOtherPreliminarySurveyAndInvestigationCharges Preliminary Natural Gas Survey and Investigation Charges 183.1)
75	OtherPreliminarySurveyAndInvestigationCharges Other Preliminary Survey and Investigation Charges (183.2)
76	ClearingAccounts Clearing Accounts (184)		229,647	701,946
77	TemporaryFacilities Temporary Facilities (185)
78	MiscellaneousDeferredDebits Miscellaneous Deferred Debits (186)	233	41,820,029	32,554,784
79	DeferredLossesFromDispositionOfUtilityPlant Def. Losses from Disposition of Utility Plt. (187)
80	ResearchDevelopmentAndDemonstrationExpenditures Research, Devel. and Demonstration Expend. (188)	352
81	UnamortizedLossOnReacquiredDebt Unamortized Loss on Reaquired Debt (189)		9,007,181	9,468,114
82	AccumulatedDeferredIncomeTaxes Accumulated Deferred Income Taxes (190)	234	1,091,297,907	946,281,284
83	UnrecoveredPurchasedGasCosts Unrecovered Purchased Gas Costs (191)
84	DeferredDebits Total Deferred Debits (lines 69 through 83)		3,017,601,169	2,841,707,420
85	AssetsAndOtherDebits TOTAL ASSETS (lines 14-16, 32, 67, and 84)		24,960,281,537	23,566,200,106

Name of Respondent:

Arizona Public Service Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/24/2023

Year/Period of Report

End of:

2023

COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line No.	Title of Account (a)	Ref. Page No. (b)	Current Year End of Quarter/Year Balance (c)	Prior Year End Balance 12/31 (d)
1	ProprietaryCapitalAbstract PROPRIETARY CAPITAL
2	CommonStockIssued Common Stock Issued (201)	250	178,162,368	178,162,368
3	PreferredStockIssued Preferred Stock Issued (204)	250
4	CapitalStockSubscribed Capital Stock Subscribed (202, 205)
5	StockLiabilityForConversion Stock Liability for Conversion (203, 206)
6	PremiumOnCapitalStock Premium on Capital Stock (207)		3,340,807,686	3,190,807,686
7	OtherPaidInCapital Other Paid-In Capital (208-211)	253	18,400,365	18,400,365
8	InstallmentsReceivedOnCapitalStock Installments Received on Capital Stock (212)	252
9	DiscountOnCapitalStock (Less) Discount on Capital Stock (213)	254
10	CapitalStockExpense (Less) Capital Stock Expense (214)	254b	37,511,652	37,511,652
11	RetainedEarnings Retained Earnings (215, 215.1, 216)	118	3,541,061,982	3,607,463,846
12	UnappropriatedUndistributedSubsidiaryEarnings Unappropriated Undistributed Subsidiary Earnings (216.1)	118
13	ReacquiredCapitalStock (Less) Reacquired Capital Stock (217)	250
14	NoncorporateProprietorship Noncorporate Proprietorship (Non-major only) (218)
15	AccumulatedOtherComprehensiveIncome Accumulated Other Comprehensive Income (219)	122(a)(b)	15,547,102	15,596,457
16	ProprietaryCapital Total Proprietary Capital (lines 2 through 15)		7,025,373,647	6,941,726,156
17	LongTermDebtAbstract LONG-TERM DEBT
18	Bonds Bonds (221)	256	163,975,000	163,975,000
19	ReacquiredBonds (Less) Reacquired Bonds (222)	256
20	AdvancesFromAssociatedCompanies Advances from Associated Companies (223)	256
21	OtherLongTermDebt Other Long-Term Debt (224)	256	7,210,696,764	6,710,339,069
22	UnamortizedPremiumOnLongTermDebt Unamortized Premium on Long-Term Debt (225)		11,764,949	12,368,152
23	UnamortizedDiscountOnLongTermDebtDebit (Less) Unamortized Discount on Long-Term Debt-Debit (226)		14,753,291	14,548,205
24	LongTermDebt Total Long-Term Debt (lines 18 through 23)		7,371,683,422	6,872,134,016
25	OtherNoncurrentLiabilitiesAbstract OTHER NONCURRENT LIABILITIES
26	ObligationsUnderCapitalLeaseNoncurrent Obligations Under Capital Leases - Noncurrent (227)		1,382,378,192	807,000,648
27	AccumulatedProvisionForPropertyInsurance Accumulated Provision for Property Insurance (228.1)
28	AccumulatedProvisionForInjuriesAndDamages Accumulated Provision for Injuries and Damages (228.2)		8,347,050	1,301,000
29	AccumulatedProvisionForPensionsAndBenefits Accumulated Provision for Pensions and Benefits (228.3)		153,273,673	158,402,804
30	AccumulatedMiscellaneousOperatingProvisions Accumulated Miscellaneous Operating Provisions (228.4)
31	AccumulatedProvisionForRateRefunds Accumulated Provision for Rate Refunds (229)
32	LongTermPortionOfDerivativeInstrumentLiabilities Long-Term Portion of Derivative Instrument Liabilities		32,179,639	9,223,020
33	LongTermPortionOfDerivativeInstrumentLiabilitiesHedges Long-Term Portion of Derivative Instrument Liabilities - Hedges
34	AssetRetirementObligations Asset Retirement Obligations (230)		839,119,150	797,761,972
35	OtherNoncurrentLiabilities Total Other Noncurrent Liabilities (lines 26 through 34)		2,415,297,704	1,773,689,444
36	CurrentAndAccruedLiabilitiesAbstract CURRENT AND ACCRUED LIABILITIES
37	NotesPayable Notes Payable (231)		285,000,000	325,000,000
38	AccountsPayable Accounts Payable (232)		428,827,010	417,732,096
39	NotesPayableToAssociatedCompanies Notes Payable to Associated Companies (233)
40	AccountsPayableToAssociatedCompanies Accounts Payable to Associated Companies (234)		104,459,829	108,704,159
41	CustomerDeposits Customer Deposits (235)		41,584,812	41,769,156
42	TaxesAccrued Taxes Accrued (236)	262	196,290,204	184,991,636
43	InterestAccrued Interest Accrued (237)		59,766,622	61,698,811
44	DividendsDeclared Dividends Declared (238)
45	MaturedLongTermDebt Matured Long-Term Debt (239)
46	MaturedInterest Matured Interest (240)
47	TaxCollectionsPayable Tax Collections Payable (241)		78	310
48	MiscellaneousCurrentAndAccruedLiabilities Miscellaneous Current and Accrued Liabilities (242)		106,617,275	139,763,920
49	ObligationsUnderCapitalLeasesCurrent Obligations Under Capital Leases-Current (243)		104,080,216	118,463,138
50	DerivativesInstrumentLiabilities Derivative Instrument Liabilities (244)		110,921,124	56,893,467
51	LongTermPortionOfDerivativeInstrumentLiabilities (Less) Long-Term Portion of Derivative Instrument Liabilities		32,179,639	9,223,020
52	DerivativeInstrumentLiabilitiesHedges Derivative Instrument Liabilities - Hedges (245)
53	LongTermPortionOfDerivativeInstrumentLiabilitiesHedges (Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges
54	CurrentAndAccruedLiabilities Total Current and Accrued Liabilities (lines 37 through 53)		1,405,367,375	1,445,793,053
55	DeferredCreditsAbstract DEFERRED CREDITS
56	CustomerAdvancesForConstruction Customer Advances for Construction (252)		536,578,588	422,102,857
57	AccumulatedDeferredInvestmentTaxCredits Accumulated Deferred Investment Tax Credits (255)	266	223,278,034	180,677,340
58	DeferredGainsFromDispositionOfUtilityPlant Deferred Gains from Disposition of Utility Plant (256)
59	OtherDeferredCredits Other Deferred Credits (253)	269	327,108,117	324,264,137
60	OtherRegulatoryLiabilities Other Regulatory Liabilities (254)	278	2,187,825,245	2,264,628,850
61	UnamortizedGainOnReacquiredDebt Unamortized Gain on Reacquired Debt (257)		37,117	25,259
62	AccumulatedDeferredIncomeTaxesAcceleratedAmortizationProperty Accum. Deferred Income Taxes-Accel. Amort.(281)	272
63	AccumulatedDeferredIncomeTaxesOtherProperty Accum. Deferred Income Taxes-Other Property (282)		2,521,238,541	2,513,421,009
64	AccumulatedDeferredIncomeTaxesOther Accum. Deferred Income Taxes-Other (283)		946,493,747	827,737,985
65	DeferredCredits Total Deferred Credits (lines 56 through 64)		6,742,559,389	6,532,857,437
66	LiabilitiesAndOtherCredits TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)		24,960,281,537	23,566,200,106

Name of Respondent:

Arizona Public Service Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/24/2023

Year/Period of Report

End of:

2023

STATEMENT OF INCOME
Quarterly Report in column (c) the current year to date balance. Column (c) equals the total of adding the data in column (g) plus the data in column (i) plus the data in column (k). Report in column (d) similar data for the previous year. This information is reported in the annual filing only. Enter in column (e) the balance for the reporting quarter and in column (f) the balance for the same three month period for the prior year. Report in column (g) the quarter to date amounts for electric utility function; in column (i) the quarter to date amounts for gas utility, and in column (k) the quarter to date amounts for other utility function for the current year quarter. Report in column (h) the quarter to date amounts for electric utility function; in column (j) the quarter to date amounts for gas utility, and in column (l) the quarter to date amounts for other utility function for the prior year quarter. If additional columns are needed, place them in a footnote. Annual or Quarterly if applicable Do not report fourth quarter data in columns (e) and (f) Report amounts for accounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility column in a similar manner to a utility department. Spread the amount(s) over Lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals. Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above. Use page 122 for important notes regarding the statement of income for any account thereof. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be made to the utility's customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effected the gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights of the utility to retain such revenues or recover amounts paid with respect to power or gas purchases. Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rate proceeding affecting revenues received or costs incurred for power or gas purchases, and a summary of the adjustments made to balance sheet, income, and expense accounts. If any notes appearing in the report to stockholders are applicable to the Statement of Income, such notes may be included at page 122. Enter on page 122 a concise explanation of only those changes in accounting methods made during the year which had an effect on net income, including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes. Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports. If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to this schedule.
Line No.	Title of Account (a)	(Ref.) Page No. (b)	Total Current Year to Date Balance for Quarter/Year (c)	Total Prior Year to Date Balance for Quarter/Year (d)	Current 3 Months Ended - Quarterly Only - No 4th Quarter (e)	Prior 3 Months Ended - Quarterly Only - No 4th Quarter (f)	Electric Utility Current Year to Date (in dollars) (g)	Electric Utility Previous Year to Date (in dollars) (h)	Gas Utiity Current Year to Date (in dollars) (i)	Gas Utility Previous Year to Date (in dollars) (j)	Other Utility Current Year to Date (in dollars) (k)	Other Utility Previous Year to Date (in dollars) (l)
1	UtilityOperatingIncomeAbstract UTILITY OPERATING INCOME
2	OperatingRevenues Operating Revenues (400)	300	2,063,123,163	1,854,656,159	1,127,863,481	1,073,162,068	2,063,123,163	1,854,656,159
3	OperatingExpensesAbstract Operating Expenses
4	OperationExpense Operation Expenses (401)	320	1,177,663,477	932,811,871	613,555,895	526,351,252	1,177,663,477	932,811,871
5	MaintenanceExpense Maintenance Expenses (402)	320	113,285,656	100,476,241	59,136,321	53,536,917	113,285,656	100,476,241
6	DepreciationExpense Depreciation Expense (403)	336	299,800,634	288,478,799	151,054,983	145,093,268	299,800,634	288,478,799
7	DepreciationExpenseForAssetRetirementCosts Depreciation Expense for Asset Retirement Costs (403.1)	336	5,529,312	4,669,928	3,194,348	2,334,964	5,529,312	4,669,928
8	AmortizationAndDepletionOfUtilityPlant Amort. & Depl. of Utility Plant (404-405)	336	59,966,075	54,989,092	30,690,667	26,797,821	59,966,075	54,989,092
9	AmortizationOfElectricPlantAcquisitionAdjustments Amort. of Utility Plant Acq. Adj. (406)	336	5,436,722	5,436,722	2,718,361	2,718,361	5,436,722	5,436,722
10	AmortizationOfPropertyLossesUnrecoveredPlantAndRegulatoryStudyCosts Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)
11	AmortizationOfConversionExpenses Amort. of Conversion Expenses (407.2)
12	RegulatoryDebits Regulatory Debits (407.3)		15,881,151	17,712,935	7,614,876	8,647,272	15,881,151	17,712,935
13	RegulatoryCredits (Less) Regulatory Credits (407.4)		299,188		299,188		299,188
14	TaxesOtherThanIncomeTaxesUtilityOperatingIncome Taxes Other Than Income Taxes (408.1)	262	128,994,544	125,152,340	64,831,502	60,526,831	128,994,544	125,152,340
15	IncomeTaxesOperatingIncome Income Taxes - Federal (409.1)	262	6,423,039	42,358,982	6,394,700	35,974,006	6,423,039	42,358,982
16	IncomeTaxesUtilityOperatingIncomeOther Income Taxes - Other (409.1)	262	11,556	990,408	207,392	665,776	11,556	990,408
17	ProvisionsForDeferredIncomeTaxesUtilityOperatingIncome Provision for Deferred Income Taxes (410.1)	234, 272	140,270,499	16,359,212	115,077,657	13,991,667	140,270,499	16,359,212
18	ProvisionForDeferredIncomeTaxesCreditOperatingIncome (Less) Provision for Deferred Income Taxes-Cr. (411.1)	234, 272	164,368,169	22,280,925	138,699,777	18,551,476	164,368,169	22,280,925
19	InvestmentTaxCreditAdjustments Investment Tax Credit Adj. - Net (411.4)	266
20	GainsFromDispositionOfPlant (Less) Gains from Disp. of Utility Plant (411.6)
21	LossesFromDispositionOfServiceCompanyPlant Losses from Disp. of Utility Plant (411.7)
22	GainsFromDispositionOfAllowances (Less) Gains from Disposition of Allowances (411.8)		12,751	12,521	6,912	7,099	12,751	12,521
23	LossesFromDispositionOfAllowances Losses from Disposition of Allowances (411.9)		13,011	12,626	6,407	6,806	13,011	12,626
24	AccretionExpense Accretion Expense (411.10)
25	UtilityOperatingExpenses TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)		1,788,595,568	1,567,155,710	915,477,232	858,086,366	1,788,595,568	1,567,155,710
27	NetUtilityOperatingIncome Net Util Oper Inc (Enter Tot line 2 less 25)		274,527,595	287,500,449	212,386,249	215,075,702	274,527,595	287,500,449
28	OtherIncomeAndDeductionsAbstract Other Income and Deductions
29	OtherIncomeAbstract Other Income
30	NonutilityOperatingIncomeAbstract Nonutilty Operating Income
31	RevenuesFromMerchandisingJobbingAndContractWork Revenues From Merchandising, Jobbing and Contract Work (415)		911,006	1,035,976	541,690	460,003
32	CostsAndExpensesOfMerchandisingJobbingAndContractWork (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)		1,373,732	569,999	952,008	136,358
33	RevenuesFromNonutilityOperations Revenues From Nonutility Operations (417)
34	ExpensesOfNonutilityOperations (Less) Expenses of Nonutility Operations (417.1)		98,453	11,576	44,021	5,788
35	NonoperatingRentalIncome Nonoperating Rental Income (418)		51,381	53,042	226	761
36	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings of Subsidiary Companies (418.1)	119
37	InterestAndDividendIncome Interest and Dividend Income (419)		10,715,125	2,494,672	5,690,784	1,395,276
38	AllowanceForOtherFundsUsedDuringConstruction Allowance for Other Funds Used During Construction (419.1)		28,095,440	21,832,767	13,034,241	12,085,841
39	MiscellaneousNonoperatingIncome Miscellaneous Nonoperating Income (421)		152,081,897	238,805,700	44,627,668	163,981,112
40	GainOnDispositionOfProperty Gain on Disposition of Property (421.1)		424,117	2,188,798	306,479	948,195
41	OtherIncome TOTAL Other Income (Enter Total of lines 31 thru 40)		190,806,781	265,829,380	63,205,059	178,729,042
42	OtherIncomeDeductionsAbstract Other Income Deductions
43	LossOnDispositionOfProperty Loss on Disposition of Property (421.2)		221,398	640,087	33,255	248,380
44	MiscellaneousAmortization Miscellaneous Amortization (425)
45	Donations Donations (426.1)		1,452,991	464,291	1,023,558	176,370
46	LifeInsurance Life Insurance (426.2)
47	Penalties Penalties (426.3)			132,000		132,000
48	ExpendituresForCertainCivicPoliticalAndRelatedActivities Exp. for Certain Civic, Political & Related Activities (426.4)		1,525,722	1,429,594	762,032	703,650
49	OtherDeductions Other Deductions (426.5)		156,985,263	242,832,043	47,397,525	166,452,631
50	OtherIncomeDeductions TOTAL Other Income Deductions (Total of lines 43 thru 49)		160,185,374	245,498,015	49,216,370	167,713,031
51	TaxesApplicableToOtherIncomeAndDeductionsAbstract Taxes Applic. to Other Income and Deductions
52	TaxesOtherThanIncomeTaxesOtherIncomeAndDeductions Taxes Other Than Income Taxes (408.2)	262	321,401	289,675	162,626	144,649
53	IncomeTaxesFederal Income Taxes-Federal (409.2)	262	1,159,407	3,134,299	232,431	1,893,415
54	IncomeTaxesOther Income Taxes-Other (409.2)	262	315,368	697,012	89,017	410,560
55	ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions Provision for Deferred Inc. Taxes (410.2)	234, 272	43,371	3,207,218	2,408	1,900,428
56	ProvisionForDeferredIncomeTaxesCreditOtherIncomeAndDeductions (Less) Provision for Deferred Income Taxes-Cr. (411.2)	234, 272	1,125,902	123,546	62,509	73,207
57	InvestmentTaxCreditAdjustmentsNonutilityOperations Investment Tax Credit Adj.-Net (411.5)
58	InvestmentTaxCredits (Less) Investment Tax Credits (420)		40,365,932	2,537,526	36,811,713	2,218,814
59	TaxesOnOtherIncomeAndDeductions TOTAL Taxes on Other Income and Deductions (Total of lines 52-58)		41,079,577	2,995,490	37,235,686	2,550,919
60	NetOtherIncomeAndDeductions Net Other Income and Deductions (Total of lines 41, 50, 59)		10,458,170	23,326,855	23,246,997	13,566,930
61	InterestChargesAbstract Interest Charges
62	InterestOnLongTermDebt Interest on Long-Term Debt (427)		134,261,630	118,871,332	67,176,463	59,437,873
63	AmortizationOfDebtDiscountAndExpense Amort. of Debt Disc. and Expense (428)		2,426,486	2,180,952	1,217,339	1,090,476
64	AmortizationOfLossOnReacquiredDebt Amortization of Loss on Reaquired Debt (428.1)		460,933	792,598	230,467	396,299
65	AmortizationOfPremiumOnDebtCredit (Less) Amort. of Premium on Debt-Credit (429)		603,203	603,203	301,602	301,602
66	AmortizationOfGainOnReacquiredDebtCredit (Less) Amortization of Gain on Reaquired Debt-Credit (429.1)		11,858	21,652	6,186	10,826
67	InterestOnDebtToAssociatedCompanies Interest on Debt to Assoc. Companies (430)
68	OtherInterestExpense Other Interest Expense (431)		18,809,313	5,550,548	11,624,297	3,748,090
69	AllowanceForBorrowedFundsUsedDuringConstructionCredit (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)		20,895,728	10,111,118	9,739,200	5,688,870
70	NetInterestCharges Net Interest Charges (Total of lines 62 thru 69)		134,471,289	116,659,457	70,201,578	58,671,440
71	IncomeBeforeExtraordinaryItems Income Before Extraordinary Items (Total of lines 27, 60 and 70)		129,598,136	194,167,847	118,937,674	169,971,192
72	ExtraordinaryItemsAbstract Extraordinary Items
73	ExtraordinaryIncome Extraordinary Income (434)
74	ExtraordinaryDeductions (Less) Extraordinary Deductions (435)
75	NetExtraordinaryItems Net Extraordinary Items (Total of line 73 less line 74)
76	IncomeTaxesExtraordinaryItems Income Taxes-Federal and Other (409.3)	262
77	ExtraordinaryItemsAfterTaxes Extraordinary Items After Taxes (line 75 less line 76)
78	NetIncomeLoss Net Income (Total of line 71 and 77)		129,598,136	194,167,847	118,937,674	169,971,192

Name of Respondent:

Arizona Public Service Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/24/2023

Year/Period of Report

End of:

2023

STATEMENT OF RETAINED EARNINGS
Do not report Lines 49-53 on the quarterly report. Report all changes in appropriated retained earnings, unappropriated retained earnings, and unappropriated undistributed subsidiary earnings for the year. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436-439 inclusive). Show the contra primary account affected in column (b). State the purpose and amount for each reservation or appropriation of retained earnings. List first Account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow by credit, then debit items, in that order. Show dividends for each class and series of capital stock. Show separately the State and Federal income tax effect of items shown for Account 439, Adjustments to Retained Earnings. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated. If any notes appearing in the report to stockholders are applicable to this statement, attach them at page 122.
Line No.	Item (a)	Contra Primary Account Affected (b)	Current Quarter/Year Year to Date Balance (c)	Previous Quarter/Year Year to Date Balance (d)
	UnappropriatedRetainedEarningsAbstract UNAPPROPRIATED RETAINED EARNINGS (Account 216)
1	UnappropriatedRetainedEarnings Balance-Beginning of Period		3,607,463,846	3,470,235,012
2	ChangesAbstract Changes
3	AdjustmentsToRetainedEarningsAbstract Adjustments to Retained Earnings (Account 439)
4	AdjustmentsToRetainedEarningsCreditAbstract Adjustments to Retained Earnings Credit
9	AdjustmentsToRetainedEarningsCredit TOTAL Credits to Retained Earnings (Acct. 439)
10	AdjustmentsToRetainedEarningsDebitAbstract Adjustments to Retained Earnings Debit
15	AdjustmentsToRetainedEarningsDebit TOTAL Debits to Retained Earnings (Acct. 439)
16	BalanceTransferredFromIncome Balance Transferred from Income (Account 433 less Account 418.1)		129,598,136	194,167,847
17	AppropriationsOfRetainedEarningsAbstract Appropriations of Retained Earnings (Acct. 436)
22	AppropriationsOfRetainedEarnings TOTAL Appropriations of Retained Earnings (Acct. 436)
23	DividendsDeclaredPreferredStockAbstract Dividends Declared-Preferred Stock (Account 437)
29	DividendsDeclaredPreferredStock TOTAL Dividends Declared-Preferred Stock (Acct. 437)
30	DividendsDeclaredCommonStockAbstract Dividends Declared-Common Stock (Account 438)
30.1	DividendsDeclaredCommonStock	234	196,000,000	192,000,000
36	DividendsDeclaredCommonStock TOTAL Dividends Declared-Common Stock (Acct. 438)		196,000,000	192,000,000
37	TransfersFromUnappropriatedUndistributedSubsidiaryEarnings Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
38	UnappropriatedRetainedEarnings Balance - End of Period (Total 1,9,15,16,22,29,36,37)		3,541,061,982	3,472,402,859
39	AppropriatedRetainedEarningsAbstract APPROPRIATED RETAINED EARNINGS (Account 215)
45	AppropriatedRetainedEarnings TOTAL Appropriated Retained Earnings (Account 215)
	AppropriatedRetainedEarningsAmortizationReserveFederalAbstract APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)
46	AppropriatedRetainedEarningsAmortizationReserveFederal TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1)
47	AppropriatedRetainedEarningsIncludingReserveAmortization TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)
48	RetainedEarnings TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1)		3,541,061,982	3,472,402,859
	UnappropriatedUndistributedSubsidiaryEarningsAbstract UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account Report only on an Annual Basis, no Quarterly)
49	UnappropriatedUndistributedSubsidiaryEarnings Balance-Beginning of Year (Debit or Credit)
50	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings for Year (Credit) (Account 418.1)
51	DividendsReceived (Less) Dividends Received (Debit)
52	ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits TOTAL other Changes in unappropriated undistributed subsidiary earnings for the year
53	UnappropriatedUndistributedSubsidiaryEarnings Balance-End of Year (Total lines 49 thru 52)

Name of Respondent:

Arizona Public Service Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/24/2023

Year/Period of Report

End of:

2023

STATEMENT OF CASH FLOWS
Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as investments, fixed assets, intangibles, etc. Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and Cash Equivalents at End of Period" with related amounts on the Balance Sheet. Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid. Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the dollar amount of leases capitalized with the plant cost.
Line No.	Description (See Instructions No.1 for explanation of codes) (a)	Current Year to Date Quarter/Year (b)	Previous Year to Date Quarter/Year (c)
1	NetCashFlowFromOperatingActivitiesAbstract Net Cash Flow from Operating Activities
2	NetIncomeLoss Net Income (Line 78(c) on page 117)	129,598,136	194,167,847
3	NoncashChargesCreditsToIncomeAbstract Noncash Charges (Credits) to Income:
4	DepreciationAndDepletion Depreciation and Depletion	305,329,946	293,148,727
5	NoncashAdjustmentsToCashFlowsFromOperatingActivities Amortization of (Specify) (footnote details)
5.1	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization of UTL PLT; ACQ; ADJ; Prop Loss; Reg Study; Nuclear Fuel	109,263,682	109,921,234
5.2	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Deferred Fuel and Purchased Power	27,287,236	1,868,200
8	DeferredIncomeTaxesNet Deferred Income Taxes (Net)	27,414,963	2,838,041
9	InvestmentTaxCreditAdjustmentsNet Investment Tax Credit Adjustment (Net)	42,600,694	2,537,526
10	NetIncreaseDecreaseInReceivablesOperatingActivities Net (Increase) Decrease in Receivables	76,927,930	132,154,956
11	NetIncreaseDecreaseInInventoryOperatingActivities Net (Increase) Decrease in Inventory	36,382,544	32,256,348
12	NetIncreaseDecreaseInAllowancesInventoryOperatingActivities Net (Increase) Decrease in Allowances Inventory	5,775,110	2,060,000
13	NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities Net Increase (Decrease) in Payables and Accrued Expenses	3,169,365	108,242,510
14	NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities Net (Increase) Decrease in Other Regulatory Assets	26,573,788	13,750,551
15	NetIncreaseDecreaseInOtherRegulatoryLiabilitiesOperatingActivities Net Increase (Decrease) in Other Regulatory Liabilities	61,706,916	256,138,914
16	AllowanceForOtherFundsUsedDuringConstructionOperatingActivities (Less) Allowance for Other Funds Used During Construction	28,095,440	21,832,767
17	UndistributedEarningsFromSubsidiaryCompaniesOperatingActivities (Less) Undistributed Earnings from Subsidiary Companies
18	OtherAdjustmentsToCashFlowsFromOperatingActivities Other (provide details in footnote):
18.1	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Other Current Assets	592,075	229,463
18.2	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Cloud Computing - ST	1,464,659	31,192
18.3	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Income Tax Receivable		10,755,546
18.4	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Prepaids	43,459,139	18,529,078
18.5	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Other Current Liabilities	8,988	106,257
18.6	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Accrued Taxes	11,298,568	39,408,684
18.7	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Arizona Attorney General Settlement		223,022
18.8	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Community Coal Transition - ST	37,500	2,350,000
18.9	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Customer Deposits	184,344	833,976
18.10	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Employee Benefits	2,803,347	1,736,812
18.11	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Four Corners Take or Pay	2,041,830	5,077,397
18.12	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Interest Accrued	1,932,188	241,270
18.13	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Payroll Accrual	29,236,880	13,341,089
18.14	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription SCE Right of Way	912,141	644,518
18.15	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Software License Agreements - ST	1,509,470
18.16	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Unbilled Revenue	1,050,253	1,878,210
18.17	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Operating Leases	16,118,836	23,363,280
18.18	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Other Long Term Assets/Liabilities Net
18.19	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Active Union Medical Trust	2,746,142	10,433,963
18.20	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Asset retirement obligations expenditures	2,868,000	3,314,000
18.21	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Carbon Allowance	5,178,283	1,800,159
18.22	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Collateral	464,000	40,695,000
18.23	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Community Coal Transition - LT	204,167	500,000
18.24	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Coal Reclamation	2,381,066	2,319,447
18.25	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Coal Reclamation Escrow	2,020,692	1,054,532
18.26	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Customer advances for construction	114,475,731	79,047,359
18.27	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Decommissioning Trust	87,846,440	219,809,407
18.28	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Information Systems Maintenance	1,878,002	3,351,218
18.29	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Interconnection Deposits	9,689,287	598,457
18.30	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Interconnection Study	13,402,740	10,572,035
18.31	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Long Term Operating Leases	30,247,000	27,470,000
18.32	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Operating Lease - Right of Use Assets	17,841,000	29,613,000
18.33	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Pension and other benefits	2,662,000	2,954,000
18.34	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Postretirement assets	26,140,733	43,853,602
18.35	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Retention Accrual	9,009,452	7,128,591
18.36	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Software License Agreements - LT		1,509,470
18.37	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Utility Plant (Removal Costs)	26,931,824	28,014,087
18.38	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Other Long-Term Assets/Liabilities Net	761,404	2,088,953
22	NetCashFlowFromOperatingActivities Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 21)	455,070,217	591,393,959
24	CashFlowsFromInvestmentActivitiesAbstract Cash Flows from Investment Activities:
25	ConstructionAndAcquisitionOfPlantIncludingLandAbstract Construction and Acquisition of Plant (including land):
26	GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities Gross Additions to Utility Plant (less nuclear fuel)	873,849,455	728,816,912
27	GrossAdditionsToNuclearFuelInvestingActivities Gross Additions to Nuclear Fuel	38,800,970	35,554,955
28	GrossAdditionsToCommonUtilityPlantInvestingActivities Gross Additions to Common Utility Plant
29	GrossAdditionsToNonutilityPlantInvestingActivities Gross Additions to Nonutility Plant
30	AllowanceForOtherFundsUsedDuringConstructionInvestingActivities (Less) Allowance for Other Funds Used During Construction	20,895,728	10,111,118
31	OtherConstructionAndAcquisitionOfPlantInvestmentActivities Other (provide details in footnote):
31.1	OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription Contributions in Aid of Construction	60,681,000	68,306,000
34	CashOutflowsForPlant Cash Outflows for Plant (Total of lines 26 thru 33)	872,865,153	706,176,985
36	AcquisitionOfOtherNoncurrentAssets Acquisition of Other Noncurrent Assets (d)
37	ProceedsFromDisposalOfNoncurrentAssets Proceeds from Disposal of Noncurrent Assets (d)
39	InvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies Investments in and Advances to Assoc. and Subsidiary Companies
40	ContributionsAndAdvancesFromAssociatedAndSubsidiaryCompanies Contributions and Advances from Assoc. and Subsidiary Companies
41	DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompaniesAbstract Disposition of Investments in (and Advances to)
42	DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies Disposition of Investments in (and Advances to) Associated and Subsidiary Companies
44	PurchaseOfInvestmentSecurities Purchase of Investment Securities (a)
45	ProceedsFromSalesOfInvestmentSecurities Proceeds from Sales of Investment Securities (a)
46	LoansMadeOrPurchased Loans Made or Purchased
47	CollectionsOnLoans Collections on Loans
49	NetIncreaseDecreaseInReceivablesInvestingActivities Net (Increase) Decrease in Receivables	562,638	573,722
50	NetIncreaseDecreaseInInventoryInvestingActivities Net (Increase) Decrease in Inventory
51	NetIncreaseDecreaseInAllowancesHeldForSpeculationInvestingActivities Net (Increase) Decrease in Allowances Held for Speculation
52	NetIncreaseDecreaseInPayablesAndAccruedExpensesInvestingActivities Net Increase (Decrease) in Payables and Accrued Expenses	9,920,181	61,624,147
53	OtherAdjustmentsToCashFlowsFromInvestmentActivities Other (provide details in footnote):
53.1	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Proceeds from Trust and Other Special Use Funds Sales (a)	567,527,544	692,186,134
53.2	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Investment in Trust and Other Special Use Funds (a)	568,668,044	692,811,236
53.3	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Other (provide details in footnote):
53.4	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Investments and Other Assets
53.5	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Post-Employment Benefits	716,843	21,092
53.6	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Restricted Cash Investments	21	298,643
53.7	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Other Assets	69,997	886,369
57	CashFlowsProvidedFromUsedInInvestmentActivities Net Cash Provided by (Used in) Investing Activities (Total of lines 34 thru 55)	865,434,971	767,285,878
59	CashFlowsFromFinancingActivitiesAbstract Cash Flows from Financing Activities:
60	ProceedsFromIssuanceAbstract Proceeds from Issuance of:
61	ProceedsFromIssuanceOfLongTermDebtFinancingActivities Long-Term Debt (b)	496,025,000
62	ProceedsFromIssuanceOfPreferredStockFinancingActivities Preferred Stock
63	ProceedsFromIssuanceOfCommonStockFinancingActivities Common Stock
64	OtherAdjustmentsToCashFlowsFromFinancingActivities Other (provide details in footnote):
64.1	OtherAdjustmentsToCashFlowsFromFinancingActivitiesDescription Equity Infusion from Pinnacle West	150,000,000	150,000,000
66	NetIncreaseInShortTermDebt Net Increase in Short-Term Debt (c)		236,300,000
67	OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Other (provide details in footnote):
67.1	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Short-term debt borrowings under revolving credit facility
67.2	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Short-term debt repayments under revolving credit facility
70	CashProvidedByOutsideSources Cash Provided by Outside Sources (Total 61 thru 69)	646,025,000	386,300,000
72	PaymentsForRetirementAbstract Payments for Retirement of:
73	PaymentsForRetirementOfLongTermDebtFinancingActivities Long-term Debt (b)
74	PaymentsForRetirementOfPreferredStockFinancingActivities Preferred Stock
75	PaymentsForRetirementOfCommonStockFinancingActivities Common Stock
76	OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities Other (provide details in footnote):
78	NetDecreaseInShortTermDebt Net Decrease in Short-Term Debt (c)	40,000,000
80	DividendsOnPreferredStock Dividends on Preferred Stock
81	DividendsOnCommonStock Dividends on Common Stock	195,900,000	192,000,000
83	CashFlowsProvidedFromUsedInFinancingActivities Net Cash Provided by (Used in) Financing Activities (Total of lines 70 thru 81)	410,125,000	194,300,000
85	NetIncreaseDecreaseInCashAndCashEquivalentsAbstract Net Increase (Decrease) in Cash and Cash Equivalents
86	NetIncreaseDecreaseInCashAndCashEquivalents Net Increase (Decrease) in Cash and Cash Equivalents (Total of line 22, 57 and 83)	239,754	18,408,081
88	CashAndCashEquivalents Cash and Cash Equivalents at Beginning of Period	4,041,534	9,374,391
90	CashAndCashEquivalents Cash and Cash Equivalents at End of Period	3,801,780	27,782,472

Name of Respondent:

Arizona Public Service Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/24/2023

Year/Period of Report

End of:

2023

NOTES TO FINANCIAL STATEMENTS

Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement, providing a subheading for each statement except where a note is applicable to more than one statement.
Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation of any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of a claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrears on cumulative preferred stock.
For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of disposition contemplated, giving references to Commission orders or other authorizations respecting classification of amounts as plant adjustments and requirements as to disposition thereof.
Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give an explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.
Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such restrictions.
If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein.
For the 3Q disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information not misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be omitted.
For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements; status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such matters shall be provided even though a significant change since year end may not have occurred.
Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are applicable and furnish the data required by the above instructions, such notes may be included herein.


1.			Other Comprehensive Basis of Accounting

The accompanying financial statements were prepared in accordance with the accounting requirements of the Federal Energy Regulatory Commission (“FERC”) as set forth in its applicable Uniform System of Accounts and published accounting releases, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America (“GAAP”). The primary differences in the accompanying FERC financial statements as compared to GAAP include presenting certain decommissioning and reclamation activities, deferred tax assets and liabilities, regulatory assets and liabilities and risk management assets and liabilities on a gross versus net basis; presenting cost of removal liabilities in accumulated provision for depreciation; presenting tax benefits related to uncertain tax positions as deferred income tax liabilities; presenting intangible assets in net utility plant; deconsolidating certain Variable Interest Entities (“VIE”) and presenting debt issuance costs in deferred debits rather than as a reduction of long-term debt. Additionally, the accompanying FERC financial statements do not separately present the current portion of such items as long-term debt, Asset Retirement Obligations (“ARO”) and regulatory assets and liabilities as required by GAAP.

Arizona Public Service’s (“APS”) notes to financial statements have been combined with Pinnacle West Capital Corporation’s financial statements and are prepared in accordance with GAAP; accordingly, certain footnotes are not reflective of APS’s financial statements contained herein.


2.			Summary of Significant Accounting Policies

Accounting Records and Use of Estimates

Our accounting records are maintained in accordance with accounting principles GAAP. The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Our unaudited financial statements reflect all adjustments (consisting only of normal recurring adjustments except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented. These statements and notes should be read in conjunction with the financial statements and related notes included in our 2022 FERC Form 1.

Allowance for Funds Used During Construction

On June 30, 2020, FERC issued an order granting a waiver request related to the existing Allowance for Funds Used During Construction ("AFUDC") rate calculation beginning March 1, 2020, through February 28, 2021. On February 23, 2021, this waiver was extended until September 30, 2021. On September 21, 2021, it was further extended until March 31, 2022. The order provided a simplified approach that companies may elect to implement in order to minimize the significant distorted effect on the AFUDC formula resulting from increased short-term debt financing during the COVID-19 pandemic. APS adopted this simplified approach to computing the AFUDC composite rate by using a simple average of the actual historical short-term debt balances for 2019, instead of current period short-term debt balances, and left all other aspects of the AFUDC formula composite rate calculation unchanged. This change impacted the AFUDC composite rate in 2021 and for the three-month period ended March 31, 2022. Furthermore, the

change in the composite rate calculation did not impact our accounting treatment for these costs. The change did not have a material impact on our financial statements.

Cash and Cash Equivalents

We consider cash equivalents to be highly liquid investments with a remaining maturity of three months or less at acquisition

The following table summarizes supplemental APS cash flow information (dollars in thousands):


	Six Months Ended June 30,
	2023		2022
Cash paid (received) during the period for:
Income taxes, net of refunds	$	94	$	(25)
Interest, net of amounts capitalized	134,107		114,069
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	151,453	$	106,033

Dividends accrued but not yet paid	98,000		96,000

Subsequent Events

Management evaluates events or transactions that occur after the balance sheet date, but before the financial statements are issued or available to be issued for potential recognition or disclosures in the financial statements as required by GAAP. We have evaluated subsequent events for recognition in the financial statements through August 3, 2023, which is the date the financial statements, prepared in accordance with GAAP were issued. Management updated such evaluation for disclosure purposes through August 24, 2023. The accompanying statements contain all adjustments and disclosures necessary for fair presentation.


3.			Quarterly Fluctuations

Significant seasonal fluctuations in our revenues are due to the effects of seasonal temperature variations on energy consumption, timing of maintenance on electric generating units, and other factors. For these reasons, amounts reported in interim periods are not necessarily indicative of amounts expected for the respective annual period.


4.			Revenue

Sources of Revenue

The following table provides detail of revenue disaggregated by revenue sources (dollars in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Retail Electric Service
Residential	$	542,315	$	537,589	$	952,039	$	904,935
Non-Residential	516,712		462,669		922,849		822,185
Wholesale Energy Sales	34,269		42,729		120,647		71,419
Transmission Services for Others	33,174		29,426		64,981		54,912
Other Sources	1,394		750		2,607		1,206
Total operating revenues	$	1,127,864	$	1,073,163	$	2,063,123	$	1,854,657

Retail Electric Revenue. Retail electric revenue is generated by the sale of electricity to our regulated customers within the authorized service territory at tariff rates approved by the Arizona Corporation Commission ("ACC") and based on customer usage. Revenues related to the sale of electricity are generally recognized when service is rendered or electricity is delivered to customers. The billing of electricity sales to individual customers is based on the reading of their meters. We obtain customers’ meter data on a systematic basis throughout the month, and generally bill customers within a month from when service was provided. Customers are generally required to pay for services within 21 days of when the services are billed. See “Allowance for Doubtful Accounts” discussion below for additional details regarding payment terms.

Wholesale Energy Sales and Transmission Services for Others. Revenues from wholesale energy sales and transmission services for others represent energy and transmission sales to wholesale customers. These activities primarily consist of managing fuel and purchased power risks in connection with the cost of serving our retail customers’ energy requirements. We may also sell into the wholesale markets generation that is not needed for APS’s retail load. Our wholesale activities and tariff rates are regulated by FERC.

In the electricity business, some contracts to purchase energy are settled by netting against other contracts to sell electricity. This is referred to as a book-out, and usually occurs in contracts that have the same terms (product type, quantities, and delivery points) and for which power does not flow. We report these book-outs on a gross basis, presenting both revenues and fuel and purchased power costs.

Revenue Activities

Our revenues primarily consist of activities that are classified as revenues from contracts with customers. We derive our revenues from contracts with customers primarily from sales of electricity to our regulated retail customers. Revenues from contracts with customers also include wholesale and transmission activities. Our revenues from contracts with customers for the three and six months ended June 30, 2023 were $1,118 million and $2,030 million, respectively, and for the three and six months ended June 30, 2022 were $1,075 million and $1,845 million, respectively.

We have certain revenues that do not meet the specific accounting criteria to be classified as revenues from contracts with customers. For the three and six months ended June 30, 2023, our revenues that do not qualify as revenue from contracts with customers were $10 million and $33 million, respectively, and for the three and six months ended June 30, 2022 were $(2) million and $10 million, respectively. This amount includes revenues related to certain regulatory cost recovery mechanisms that are considered alternative revenue programs. We recognize revenue associated with alternative revenue programs when specific events permitting recognition are completed. Certain amounts associated with alternative revenue programs will

subsequently be billed to customers; however, we do not reclassify billed amounts into revenue from contracts with customers. See Note 6 for a discussion of our regulatory cost recovery mechanisms.

Contract Assets and Liabilities from Contracts with Customers

There were no material contract assets, contract liabilities, or deferred contract costs recorded on the Comparative Balance Sheets as of June 30, 2023, or December 31, 2022.

Allowance for Doubtful Accounts

The allowance for doubtful accounts represents our best estimate of accounts receivable and accrued unbilled revenues that will ultimately be uncollectible due to credit loss risk. The allowance includes a write-off component that is calculated by applying an estimated write-off factor to retail electric revenues. The write-off factor used to estimate uncollectible accounts is based upon consideration of historical collections experience, the current and forecasted economic environment, changes to our collection policies, and management’s best estimate of future collections success. We continue to monitor the impacts of our disconnection policies, payment arrangements, among other considerations impacting our estimated write-off factor and allowance for doubtful accounts.

The following table provides a rollforward of the allowance for doubtful accounts (dollars in thousands):


	June 30, 2023		December 31, 2022
Allowance for doubtful accounts, balance at beginning of period	$	23,778	$	25,354
Bad debt expense	8,125		17,006
Actual write-offs	(12,097)		(18,582)
Allowance for doubtful accounts, balance at end of period	$	19,806	$	23,778


5.			Long-Term Debt and Liquidity Matters

APS maintains committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs, to refinance indebtedness, and for other general corporate purposes.

On January 6, 2023, Pinnacle West contributed $150 million into APS in the form of an equity infusion. APS used this contribution to repay short-term indebtedness.

See “Financial Assurances” in Note 10 for a discussion of other outstanding letters of credit.

Debt Fair Value

Our long-term debt fair value estimates are classified within Level 2 of the fair value hierarchy. The following table presents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):


	As of June 30, 2023				As of December 31,2022
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Total	$	7,371,683	$	6,298,044	$	6,872,134	$	5,659,830


6.			Regulatory Matters

2022 Retail Rate Case

The principal provisions of APS’s application are:

•a test year comprised of twelve months ended June 30, 2022, adjusted as described below;

•an original cost rate base of $10.5 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits;

•the following proposed capital structure and costs of capital:


	Capital Structure		Cost of Capital
Long-term debt	48.07	%	3.85	%
Common stock equity	51.93	%	10.25	%
Weighted-average cost of capital			7.17	%

•a 1% return on the increment of fair value rate base above APS’s original cost rate base, as provided for by Arizona law;

•a rate of $0.038321 per kWh for the portion of APS’s retail base rates attributable to fuel and purchased power costs (“Base Fuel Rate”);

•modification of its adjustment mechanisms including:

▪eliminate the Environmental Improvement Surcharge (“EIS”) and collect costs through base rates,

▪eliminate the Lost Fixed Cost Recovery (“LFCR”) mechanism and collect costs through base rates and the Demand Side Management Adjustment Charge (“DSMAC”),

▪maintain as inactive the Tax Expense Adjustor Mechanism (“TEAM”),

▪maintain the Transmission Cost Adjustment ("TCA") mechanism,

▪modify the performance incentive in the DSMAC, and

▪modify the Renewable Energy Adjustment Charge (“REAC”) to include recovery of capital carrying costs of APS owned renewable and storage resources;

•changes to its limited-income program, including a second tier to provide an additional discount for customers with greater need; and

•twelve months of post-Test Year plant investments to reflect used and useful projects that will be placed into service prior to July 1, 2023.

On July 12, 2023, APS filed rebuttal testimony addressing the ACC Staff and intervenors’ direct testimonies. The principal provisions of APS’s rebuttal testimony are:

•reducing the revenue requirement increase to $383.1 million;

•maintaining a return on equity request of 10.25%;

•reducing the increment of fair value rate base return to 0.5% from 1.0%;

•maintaining a post-test year plant request of 12 months, plus the Four Corners Effluent Limitation Guidelines (“ELG”) project;

•withdrawing the Payment Fee Removal Proposal (net reduction) which was originally requested in APS’s initial application;

•maintaining the LFCR mechanism and DSMAC as separate adjustors;

•increasing the Power Supply Adjustment (“PSA”) annual rate change limit from $0.004/kWh to $0.006/kWh;

•proposing a new System Reliability Benefit (“SRB”) recovery mechanism;

•maintaining the REAC in its current state;

•maintaining adjustor base transfers and elimination of EIS; and

•maintaining the request to recover Coal Community Transition (“CCT”) funding.

APS’s rejoinder testimony is due on August 4, 2023.

APS requested that the increase become effective December 1, 2023. The hearing for this rate case is currently scheduled to begin in August 2023. APS cannot predict the outcome of its request.

2019 Retail Rate Case

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 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 (“Cholla”), 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.

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, among other things. 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. 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. The ACC filed an appeal on May 8, 2023, and on May 15, 2023, requested a suspension of the case to allow for settlement discussions between the parties, which was approved by the Court.

Sierra Club will have 30 days after resolution of its request for rehearing to file a notice of appeal to Arizona Court of Appeals.

Matter of Impact of the Closures of Fossil-Based Generation Plan on Impacted Communities

Information Technology ACC Investigation

2016 Retail Rate Case Filing and the 2017 Settlement Agreement

Cost Recovery Mechanisms

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 2015, the ACC revised the RES rules to allow the ACC to consider all available information, including the number of rooftop solar arrays in a utility’s service territory, to determine compliance with the RES.

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 included 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 supported 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 proposed 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.

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 LFCR mechanism. See below for discussion of the LFCR.

In accordance with an extension granted by the ACC, APS intends to file its 2024 DSM Implementation Plan by November 30, 2023.

Power Supply Adjustor Mechanism and Balance. The Power Supply Adjustor (“PSA”) provides for the adjustment of retail rates to reflect variations primarily in retail fuel and purchased power costs. The PSA is subject to specified parameters and procedures, including the following:

•APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate;

•an adjustment to the PSA rate is made annually each February 1 (unless otherwise approved by the ACC) and goes into effect automatically unless suspended by the ACC;

•the PSA rate may not be increased or decreased more than $0.004 per kWh in a year without permission of the ACC.

The following table shows the changes in the deferred fuel and purchased power regulatory asset for 2023 and 2022 (dollars in thousands):


	Six Months Ended June 30,
	2023		2022
Beginning balance	$	460,561	$	388,148
Deferred fuel and purchased power costs - current period	191,304		98,707
Amounts charged to customers	(218,586)		(96,842)
Ending balance	$	433,279	$	390,013

PSA and four in 2021, excluding one energy storage PPA that was approved but later terminated by APS due to project delays.

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 February EIS request and a decrease of $7.5 million from the prior-period charge. The revised 2023 EIS became effective with the first billing cycle in April 2023.

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.

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.

Net Metering

In addition, the ACC made the following determinations in the Value and Cost of Distributed Generation docket:

•customers with DG solar systems are to be considered a separate class of customers for ratemaking purposes; and

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.

Energy Modernization Plan

Integrated Resource Planning

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.

Public Utility Regulatory Policies Act

On July 16, 2020, FERC issued a final rule revising FERC’s regulations implementing PURPA. The final rule went into effect on December 31, 2020.

Residential Electric Utility Customer Service Disconnections

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.

Retail Electric Competition Rules

Rate Plan Comparison Tool and Investigation

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.

Four Corners SCR Cost Recovery

recovery of the cost of the Four Corners SCRs. See above for further discussion on the 2019 Rate Case decision.

Cholla

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, $34.9 million as of June 30, 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.

Navajo Plant


7.			Retirement Plans and Other Postretirement Benefits

Pinnacle West sponsors a qualified defined benefit and account balance pension plan, a non-qualified supplemental excess benefit retirement plan, and other postretirement benefit plans for the employees of Pinnacle West and our subsidiaries. The other postretirement benefit plans include a group life and medical plan and a post-65 retiree health reimbursement arrangement (“HRA”). Pinnacle West uses a December 31 measurement date each year for its pension and other postretirement benefit plans. The market-related value of our plan assets is their fair value at the measurement date.

The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction or billed to electric plant participants) (dollars in thousands):


	Pension Benefits								Other Benefits
	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022		2023		2022		2023		2022
Service cost-benefits earned during the period	$	9,573	$	13,406	$	19,730	$	27,737	$	2,164	$	4,017	$	4,284	$	8,235
Non-service costs (credits):
Interest cost on benefit obligation	38,418		26,723		76,780		53,746		5,582		4,283		11,255		8,746
Expected return on plan assets	(45,908)		(46,494)		(91,469)		(92,888)		(10,872)		(11,511)		(21,744)		(23,021)
Amortization of:
Prior service credit	—		—		—		—		(9,447)		(9,447)		(18,894)		(18,894)
Net actuarial (gain)/loss	9,497		3,989		19,210		8,757		(2,504)		(3,436)		(4,807)		(6,418)
Net periodic cost/(benefit)	$	11,580	$	(2,376)	$	24,251	$	(2,648)	$	(15,077)	$	(16,094)	$	(29,906)	$	(31,352)
Portion of cost/(benefit) charged to expense	$	6,513	$	(4,722)	$	13,740	$	(8,012)	$	(10,948)	$	(11,523)	$	(21,685)	$	(22,418)

Contributions

Pinnacle West has not made any voluntary contributions to our pension plan year-to-date in 2023. The minimum required contributions for the pension plan are zero for the next three years and Pinnacle West does not expect to make any contributions in 2023, 2024 or 2025. With regard to contributions to Pinnacle West's other postretirement benefit plan, Pinnacle West has not made a contribution year-to-date in 2023 and does not expect to make any contributions in 2023, 2024 or 2025.


8.			Palo Verde Sale Leaseback Variable Interest Entities

In 1986, APS entered into agreements with three separate VIE lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. APS will retain the assets through 2033 under all three lease agreements. APS will be required to make payments relating to the

three leases in total of approximately $21 million annually for the period 2023 through 2033. At the end of the lease period, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to two years, or return the assets to the lessors.

For regulatory reporting purposes, APS accounts for the three leases as operating leases for income statement and cash flow statement purposes, and for balance sheet purposes all three leases are classified as finance leases. See Note 10 for a discussion of leases.

APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the Nuclear Regulatory Commission (“NRC”) issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event were to occur during the lease periods, APS may be required to pay the noncontrolling equity participants approximately $324 million beginning in 2023, and up to $501 million over the lease terms.


9.			Derivative Accounting

Derivative financial instruments are used to manage exposure to commodity price and transportation costs of electricity, natural gas, emissions allowances, and interest rates. Risks associated with market volatility are managed by utilizing various physical and financial derivative instruments, including futures, forwards, options and swaps. As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and natural gas. Derivative instruments that meet certain hedge accounting criteria may be designated as cash flow hedges and are used to limit our exposure to cash flow variability on forecasted transactions. The changes in market value of such instruments have a high correlation to price changes in the hedged transactions. Derivative instruments are also entered into for economic hedging purposes. While economic hedges may mitigate exposure to fluctuations in commodity prices, these instruments have not been designated as accounting hedges. Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are presented gross, which increases both revenues and fuel and purchased power costs in our Comparative Statements of Income, but does not impact our financial condition, net income or cash flows.

Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the balance sheet as an asset or liability and are measured at fair value. See Note 11 for a discussion of fair value measurements. Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery and the quantities represent those transacted in the normal course of business. Derivative instruments qualifying for the normal purchases and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below.

APS defers for future rate treatment 100% of the unrealized gains and losses on derivatives pursuant to the PSA mechanism that would otherwise be recognized in income. Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate, see Note 6. Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.

The following table shows the outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):

Quantity

Commodity

Unit of Measure

June 30, 2023

December 31, 2022

Power

GWh

1,236

1,197

Gas

Billion cubic feet

202

149

Gains and Losses from Derivative Instruments

For the three and six months ended June 30, 2023 and 2022, APS had no derivative instruments in designated accounting hedging relationships.

The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments (dollars in thousands):


	Financial Statement Location	Three Months Ended June 30,				Six Months Ended June 30,
Commodity Contracts		2023		2022		2023		2022

Net Gain (Loss) Recognized in Income	Fuel and purchased power (a)	$	(50,145)	$	62,525	$	(239,075)	$	286,267

(a) Amounts are before the effect of PSA deferrals.

Derivative Instruments in the Comparative Balance Sheets

Our derivative transactions are typically executed under standardized or customized agreements, which include collateral requirements and, in the event of a default, would allow for the netting of positive and negative exposures associated with a single counterparty. Agreements that allow for the offsetting of positive and negative exposures associated with a single counterparty are considered master netting arrangements and are reported gross on the Comparative Balance Sheets.

We do not offset a counterparty’s current derivative contracts with the counterparty’s non-current derivative contracts, although our master netting arrangements would allow current and non-current positions to be offset in the event of a default. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, trade receivables and trade payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting tables presented below.

The following tables provide information about the fair value of our risk management activities reported on a gross basis and the impacts of offsetting relating to transactions executed under master netting arrangements. While certain amounts may be eligible for offsetting under master netting arrangements, for FERC reporting purposes we do not offset on the balance sheet. These amounts relate to commodity contracts and are located in the assets and liabilities from derivative instrument lines of our Comparative Balance Sheets.


As of June 30, 2023: (dollars in thousands)	Gross Recognized Derivatives (a)		Eligible for Offsetting				Net Derivatives After Impacts of Offsetting
			Derivatives		Cash Collateral/Other (b)
Current assets	$	22,876	$	(11,180)	$	—	$	11,696
Investments and other assets	20,857		(7,824)		—		13,033
Total assets	43,733		(19,004)		—		24,729

Current liabilities	(78,742)		11,180		—		(67,562)
Deferred credits and other	(32,179)		7,824		—		(24,355)
Total liabilities	(110,921)		19,004		—		(91,917)
Total	$	(67,188)	$	—	$	—	$	(67,188)

(a)All of our gross recognized derivative instruments were subject to master netting arrangements.

(b)No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting. We had total cash collateral received from counterparties of $6,271 thousand.


As of December 31, 2022: (dollars in thousands)	Gross Recognized Derivatives (a)		Eligible for Offsetting				Net Derivatives After Impacts of Offsetting
			Derivatives		Cash Collateral/Other (b)
Current assets	$	103,484	$	(15,808)	$	—	$	87,676
Investments and other assets	49,777		(5,383)		—		44,394
Total assets	153,261		(21,191)		—		132,070

Current liabilities	(47,670)		15,808		—		(31,862)
Deferred credits and other	(9,223)		5,383		—		(3,840)
Total liabilities	(56,893)		21,191		—		(35,702)
Total	$	96,368	$	—	$	—	$	96,368

(a)All of our gross recognized derivative instruments were subject to master netting arrangements.

Credit Risk and Credit Related Contingent Features

We are exposed to losses in the event of nonperformance or nonpayment by counterparties and have risk management contracts with many counterparties. As of June 30, 2023, we have one counterparty for which our exposure represents approximately 23% of $25 million of risk management assets. This exposure relates to a master agreement with the counterparty, and the counterparty is rated as investment grade. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of our trading counterparties’ debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these counterparties could default, resulting in a material impact on earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of

their financial condition. To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.

Certain of our derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross-default provisions, and adequate assurance provisions. Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions. For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s).

The following table provides information about our derivative instruments that have credit-risk-related contingent features (dollars in thousands):


	June 30, 2023
Aggregate fair value of derivative instruments in a net liability position	$	109,632

Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)	58,298

(a)This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.

We have energy-related non-derivative instrument contracts with investment grade credit-related contingent features, which could require us to post additional collateral of approximately $161 million if our debt credit ratings were to fall below investment grade.


10.			Commitments and Contingencies

Palo Verde Generating Station

Spent Nuclear Fuel and Waste Disposal

On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a second breach of contract lawsuit against DOE in the United States Court of Federal Claims (“Court of Federal Claims”). The lawsuit sought to recover damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste (“Standard Contract”) for failing to accept Palo Verde’s spent nuclear fuel and high level waste from January 1, 2007, through June 30, 2011, pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act. On August 18, 2014, APS and DOE entered into a settlement agreement, which required DOE to pay the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007, through June 30, 2011. In addition, the settlement agreement provided APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2016, which was extended to December 31, 2025.

October 31, 2022, APS filed its ninth claim pursuant to the terms of the August 18, 2014 settlement agreement. On March 16, 2023, the DOE approved a payment in the amount of $14.3 million (APS’s share is $4.2 million), and on April 6, 2023, APS received this payment.

Nuclear Insurance

Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act (“Price-Anderson Act”), which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial sources and an industry-wide retrospective payment plan. In accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident up to approximately $13.7 billion per occurrence. Palo Verde maintains the maximum available nuclear liability insurance in the amount of $450 million, which is provided by American Nuclear Insurers. The remaining balance of approximately $13.2 billion of liability coverage is provided through a mandatory, industry-wide retrospective premium program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be responsible for retrospective premiums. The maximum retrospective premium per reactor under the program for each nuclear liability incident is approximately $137.6 million, subject to a maximum annual premium of approximately $20.5 million per incident. Based on APS’s ownership interest in the three Palo Verde units, APS’s maximum retrospective premium per incident for all three units is approximately $120.1 million, with a maximum annual retrospective premium of approximately $17.9 million.

The Palo Verde participants maintain insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.8 billion. APS has also secured accidental outage insurance for a sudden and unforeseen accidental outage of any of the three units. The property damage, decontamination, and accidental outage insurance are provided by Nuclear Electric Insurance Limited (“NEIL”). APS is subject to retrospective premium adjustments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount APS could incur under the current NEIL policies totals approximately $22.4 million for each retrospective premium assessment declared by NEIL’s Board of Directors due to losses. Additionally, at the sole discretion of the NEIL Board of Directors, APS would be liable to provide approximately $62.6 million in deposit premium within 20 days of request as assurance to satisfy any site obligation of retrospective premium assessment. The insurance coverage discussed in this, and the previous paragraph is subject to certain policy conditions, sublimits, and exclusions.

Contractual Obligations

Superfund and Other Related Matters

The Comprehensive Environmental Response Compensation and Liability Act (“Superfund” or “CERCLA”) establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who released, generated, transported to or disposed of hazardous substances at a contaminated site are among the parties who are potentially responsible (each a “PRP”). PRPs may be strictly, jointly, and severally liable for clean-up. On September 3, 2003, EPA advised APS that EPA considers APS to be a PRP in the Motorola 52nd Street Superfund Site, Operable Unit 3 (“OU3”) in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS has agreed with EPA to perform certain investigative activities of the APS facilities within OU3. In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study (“RI/FS”). The RI/FS for OU3 was finalized and submitted to EPA at the end of 2022. APS cannot predict the EPA’s timing with respect to this matter. APS’s estimated costs related to this investigation and study is approximately $3 million. APS anticipates incurring additional expenditures in the future, but because the ultimate remediation requirements are not yet finalized by EPA, at the present time expenditures related to this matter cannot be reasonably estimated.

On August 6, 2013, the Roosevelt Irrigation District (“RID”) filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants. The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID. The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3. As part of a state governmental investigation into groundwater contamination in this area, on January 25, 2015, the ADEQ sent a letter to APS seeking information concerning the degree to which, if any, APS’s current and former ownership of these facilities may have contributed to groundwater contamination in this area. APS responded to ADEQ on May 4, 2015. On December 16, 2016, two RID environmental and engineering contractors filed an ancillary lawsuit for recovery of costs against APS and the other defendants in the RID litigation. That same day, another RID service provider filed an additional ancillary CERCLA lawsuit against certain of the defendants in the main RID litigation but excluded APS and certain other parties as named defendants. Because the ancillary lawsuits concern past costs allegedly incurred by these RID vendors, which were ruled unrecoverable directly by RID in November of 2016, the additional lawsuits do not increase APS’s exposure or risk related to these matters.

compounds at the Ocotillo power plant site in order to aid EPA’s investigation into actual or threatened releases of PFAS into groundwater within the South Indian Bend Wash (“SIBW”) Superfund site. The SIBW Superfund site includes the APS Ocotillo power plant site. APS filed its response to this information request on April 29, 2022. On January 17, 2023, EPA contacted APS to inform the Company that it would be commencing on-site investigations within the SIBW site, including the Ocotillo power plant, and performing a remedial investigation and feasibility study related to potential PFAS impacts to groundwater over the next two to three years. APS estimates that its costs to oversee and participate in the remedial investigation work will be approximately $1.7 million. At the present time, we are unable to predict the outcome of this matter and any further expenditures related to necessary remediation, if any, or further investigations cannot be reasonably estimated.

Four Corners SCR Cost Recovery

As part of APS’s 2019 Rate Case, APS included recovery of the deferral and rate base effects of the Four Corners SCR project. 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. On June 21, 2023, the ACC approved a joint settlement filed by APS and the ACC’s Legal Division that resolved all issues relating to the 2019 Rate Case decision, including recovery of the cost of the Four Corners SCRs. See Note 6 for additional information regarding the Four Corners SCR cost recovery and the 2019 Rate Case.

Environmental Matters

APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions of both conventional pollutants and greenhouse gases, water quality, wastewater discharges, solid waste, hazardous waste, and coal combustion residuals (“CCRs”). These laws and regulations can change from time to time, imposing new obligations on APS resulting in increased capital, operating, and other costs. Associated capital expenditures or operating costs could be material. APS intends to seek recovery of any such environmental compliance costs through our rates but cannot predict whether it will obtain such recovery. The following proposed and final rules involve material compliance costs to APS.

•With respect to APS’s Cholla facility, APS’s application for alternative closure was submitted to EPA on November 30, 2020. While EPA has deemed APS’s application administratively “complete,” the Agency’s approval remains pending. If granted, this application would allow the continued disposal of CCR within Cholla’s existing unlined CCR surface impoundments until the required date for ceasing coal-fired boiler operations in April 2025. This application will be subject to public comment and, potentially, judicial review. We expect to have a proposed decision from EPA regarding Cholla sometime in 2023.

APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners. APS estimates that its share of incremental costs to comply with the CCR rule for Four Corners is approximately $30 million and its share of incremental costs to comply with the CCR rule for Cholla is approximately $19 million. The Navajo Plant disposed of CCR only in a dry landfill storage area. To comply with the CCR rule for the Navajo Plant, APS’s share of incremental costs was approximately $1 million, which has been incurred. Additionally, the CCR rule requires ongoing, phased groundwater monitoring.

Corners will need to undergo corrective action. In addition, under the current regulations, all such disposal units must have ceased operating and initiated closure by April 11, 2021, at the latest (except for those disposal units subject to alternative closure). APS completed the assessments of corrective measures on June 14, 2019; however, additional investigations and engineering analyses that will support the remedy selection are still underway. In addition, APS will also solicit input from the public and host public hearings as part of this process. Based on the work performed to date, APS currently estimates that its share of corrective action and monitoring costs at Four Corners will likely range from $10 million to $15 million, which would be incurred over 30 years. As to Cholla, APS currently estimates that its share of corrective action and monitoring costs at this facility will likely range from $35 million to $40 million, which similarly would be incurred over 30 years. As APS continues to implement the CCR rule’s corrective action assessment process, the current cost estimates may change. Given uncertainties that may exist until we have fully completed the corrective action assessment and final remedy selection process, APS cannot predict any ultimate impacts to APS; however, at this time APS does not believe that any potential changes to the cost estimate for Four Corners or Cholla would have a material impact on its financial position, results of operations or cash flows.

outcome, the costs associated with APS’s operation of its current and future thermal power plants could materially increase, which could affect APS’s financial position, results of operations, or cash flows.

Four Corners National Pollutant Discharge Elimination System (“NPDES”) Permit

The latest NPDES permit for Four Corners was issued on September 30, 2019. Based upon a November 1, 2019, filing by several environmental groups, the Environmental Appeals Board (“EAB”) took up review of the Four Corners NPDES Permit. The EAB denied the environmental group petition on September 30, 2020. While on January 22, 2021, the environmental groups filed a petition for review of the EAB’s decision with the U.S. Court of Appeals for the Ninth Circuit, the parties to the litigation (including APS) finalized a settlement on May 2, 2022. This settlement requires investigation of thermal wastewater discharges from Four Corners, administratively closes the litigation filed in January of 2021, and is not expected to have a material impact on APS’s financial position, results of operations, or cash flows.

Financial Assurances


11.			Fair Value Measurements

We classify our assets and liabilities that are carried at fair value within the fair value hierarchy. This hierarchy ranks the quality and reliability of the inputs used to determine fair values, which are then classified and disclosed in one of three categories. The three levels of the fair value hierarchy are:

Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date

Level 2 — Other significant observable inputs, including quoted prices in active markets for similar assets or liabilities; quoted prices in markets that are not active, and model-derived valuations whose inputs are observable (such as yield curves).

Level 3 — Valuation models with significant unobservable inputs that are supported by little or no market activity. Instruments in this category may include long-dated derivative transactions where valuations are unobservable due to the length of the transaction, options, and transactions in locations where observable market data does not exist. The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable. We maximize the use of observable inputs and minimize the use of unobservable inputs. We rely primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities. If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use. Our assessment of the inputs and the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities as well as their placement within the fair value hierarchy levels. We assess whether a market is active by obtaining observable broker quotes, reviewing actual market activity, and assessing the volume of transactions. We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote with market activity, or we can determine that the inputs the broker used to arrive at the quoted price are observable.

Certain instruments have been valued using the concept of Net Asset Value (“NAV”) as a practical expedient. These instruments are typically structured as investment companies offering shares or units to multiple investors for the purpose of providing a return. These instruments are similar to mutual funds; however, their NAV is generally not published and publicly available, nor are these instruments traded on an exchange. Instruments valued using NAV as a practical expedient are included in our fair value disclosures; however, in accordance with GAAP are not classified within the fair value hierarchy levels.

Recurring Fair Value Measurements

We apply recurring fair value measurements to cash equivalents, derivative instruments, and investments held in the nuclear decommissioning trusts and other special use funds. On an annual basis, we apply fair value measurements to plan assets held in our retirement and other benefit plans. See Note 8 in the 2022 FERC Form 1 for fair value discussion of plan assets held in our retirement and other benefit plans.

Cash Equivalents

Cash equivalents represent certain investments in money market funds that are valued using quoted prices in active markets.

Risk Management Activities — Energy Derivative Instruments

Exchange traded commodity contracts are valued using unadjusted quoted prices. For non-exchange traded commodity contracts, we calculate fair value based on the average of the bid and offer price, discounted to reflect net present value. We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments. These include valuation adjustments for liquidity and credit risks. The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed out or hedged. The credit valuation adjustment represents estimated credit losses on our net exposure to counterparties, taking into account netting agreements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio. We maintain credit policies that management believes minimize overall credit risk.

Certain non-exchange traded commodity contracts are valued based on unobservable inputs due to the long-term nature of contracts, characteristics of the product, or the unique location of the transactions. Our long-dated energy transactions consist of observable valuations for the near-term portion and unobservable valuations for the long-term portions of the transaction. We rely primarily on broker quotes to value these instruments. When our valuations utilize broker quotes, we perform various control procedures to ensure the quote has been developed consistent with fair value accounting guidance. These controls include assessing the quote for reasonableness by comparison against other broker quotes, reviewing historical price relationships, and assessing market activity. When broker quotes are not available, the primary valuation technique used to calculate the fair value is the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at more illiquid delivery points.

When the unobservable portion is significant to the overall valuation of the transaction, the entire transaction is classified as Level 3.

Investments Held in Nuclear Decommissioning Trusts and Other Special Use Funds

The nuclear decommissioning trusts and other special use funds invest in fixed income and equity securities. Other special use funds include the coal reclamation escrow account and the active union employee medical account. See Note 12 for additional discussion about our investment accounts.

We value investments in fixed income and equity securities using information provided by our trustees and escrow agent. Our trustees and escrow agent use pricing services that utilize the valuation methodologies described below to determine fair market value. We have internal control procedures designed to ensure this information is consistent with fair value accounting guidance. These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustees’ and escrow agent’s internal operating controls and valuation processes.

Fixed Income Securities

Fixed income securities issued by the U.S. Treasury are valued using quoted active market prices and are typically classified as Level 1. Fixed income securities issued by corporations, municipalities, and other agencies, including mortgage-backed instruments, are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield curves and spreads relative to such yield curves. These fixed income instruments are classified

as Level 2. Whenever possible, multiple market quotes are obtained which enables a cross-check validation. A primary price source is identified based on asset type, class, or issue of securities.

Fixed income securities may also include short-term investments in certificates of deposit, variable rate notes, time deposit accounts, U.S. Treasury and Agency obligations, U.S. Treasury repurchase agreements, commercial paper, and other short-term instruments. These instruments are valued using active market prices or utilizing observable inputs described above.

Equity Securities

The nuclear decommissioning trusts’ equity security investments are held indirectly through commingled funds. The commingled funds are valued using the funds’ NAV as a practical expedient. The funds’ NAV is primarily derived from the quoted active market prices of the underlying equity securities held by the funds. We may transact in these commingled funds on a semi-monthly basis at the NAV. The commingled funds are maintained by a bank and hold investments in accordance with the stated objective of tracking the performance of the S&P 500 Index. Because the commingled funds’ shares are offered to a limited group of investors, they are not considered to be traded in an active market. As these instruments are valued using NAV, as a practical expedient, they have not been classified within the fair value hierarchy.

The nuclear decommissioning trusts and other special use funds may also hold equity securities that include exchange traded mutual funds and money market accounts for short-term liquidity purposes. These short-term, highly-liquid investments are valued using active market prices.

Fair Value Tables

The following table presents the fair value at June 30, 2023, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):


	Level 1		Level 2		Level 3		Other			Total
ASSETS

Risk management activities — derivative instruments:
Commodity contracts	$	—	$	28,692	$	13,753	$	1,288		$	43,733

Nuclear decommissioning trust:
Equity securities	19,895		—		—		(6,247)		(a)	13,648
U.S. commingled equity funds	—		—		—		499,204		(b)	499,204
U.S. Treasury debt	248,897		—		—		—			248,897
Corporate debt	—		167,372		—		—			167,372
Mortgage-backed securities	—		163,599		—		—			163,599
Municipal bonds	—		62,269		—		—			62,269
Other fixed income	—		7,408		—		—			7,408
Subtotal nuclear decommissioning trust	268,792		400,648		—		492,957			1,162,397

Other special use funds:
Equity securities	27,250		—		—		1,519		(a)	28,769
U.S. Treasury debt	319,279		—		—		—			319,279
Municipal bonds	—		3,950		—		—			3,950
Subtotal other special use funds	346,529		3,950		—		1,519			351,998

Total assets	$	615,321	$	433,290	$	13,753	$	495,764		$	1,558,128

LIABILITIES

Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(94,601)	$	(15,032)	$	(1,288)		$	(110,921)

Total liabilities	$	—	$	(94,601)	$	(15,032)	$	(1,288)		$	(110,921)

(a)Represents net pending securities sales and purchases.

(b)Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.

The following table presents the fair value at December 31, 2022, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):


	Level 1		Level 2		Level 3		Other			Total
ASSETS

Risk management activities — derivative instruments:
Commodity contracts	$	—	$	127,129	$	26,132	$	—		$	153,261
Nuclear decommissioning trust:
Equity securities	14,658		—		—		3,827		(a)	18,485
U.S. commingled equity funds	—		—		—		472,582		(b)	472,582
U.S. Treasury debt	211,923		—		—		—			211,923
Corporate debt	—		149,226		—		—			149,226
Mortgage-backed securities	—		147,938		—		—			147,938
Municipal bonds	—		64,881		—		—			64,881
Other fixed income	—		8,375		—		—			8,375
Subtotal nuclear decommissioning trust	226,581		370,420		—		476,409			1,073,410

Other special use funds:
Equity securities	66,974		—		—		963		(a)	67,937
U.S. Treasury debt	275,267		—		—		—			275,267
Municipal bonds	—		4,027		—		—			4,027
Subtotal other special use funds	342,241		4,027		—		963			347,231

Total assets	$	568,822	$	501,576	$	26,132	$	477,372		$	1,573,902
LIABILITIES
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(25,874)	$	(31,020)	$	1		$	(56,893)

Total liabilities	$	—	$	(25,874)	$	(31,020)	$	1		$	(56,893)

(a)Represents net pending securities sales and purchases.

(b)Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.

Fair Value Measurements Classified as Level 3

The significant unobservable inputs used in the fair value measurement of our energy derivative contracts include broker quotes that cannot be validated as an observable input primarily due to the long-term nature of the quote or other characteristics of the product. Significant changes in these inputs in isolation would result in significantly higher or lower fair value measurements. Changes in our derivative contract fair values, including changes relating to unobservable inputs, typically will not impact net income due to regulatory accounting treatment. See Note 6.

Because our forward commodity contracts classified as Level 3 are currently in a net purchase position, we would expect price increases of the underlying commodity to result in increases in the net fair value of the related contracts. Conversely, if the price of the underlying commodity decreases, the net fair value of the related contracts would likely decrease.

Other unobservable valuation inputs include credit and liquidity reserves which do not have a material impact on our valuations; however, significant changes in these inputs could also result in higher or lower fair value measurements.

The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at June 30, 2023 and December 31, 2022:


	June 30, 2023					Significant
	Fair Value (thousands)				Valuation	Unobservable						Weighted
Commodity Contracts	Assets		Liabilities		Technique	Input	Range					Average (b)
Electricity:
Forward Contracts (a)	$	13,753	$	10,859	Discounted cash flows	Electricity forward price (per MWh)	$	37.79	-	$	245.59	$	128.78
Natural Gas:
Forward Contracts (a)	—		4,173		Discounted cash flows	Natural gas forward price (per MMBtu)	$	(0.20)	-	$	—	$	(0.13)
Total	$	13,753	$	15,032

(a)Includes swaps and physical and financial contracts.

(b)Unobservable inputs were weighted by the relative fair value of the instrument.


	December 31, 2022					Significant
	Fair Value (thousands)				Valuation	Unobservable						Weighted
Commodity Contracts	Assets		Liabilities		Technique	Input	Range					Average (b)
Electricity:
Forward Contracts (a)	$	26,132	$	1,759	Discounted cash flows	Electricity forward price (per MWh)	$	37.79	-	$	310.69	$	163.92
Natural Gas:
Forward Contracts (a)	—		29,261		Discounted cash flows	Natural gas forward price (per MMBtu)	$	(11.81)	-	$	—	$	(5.08)
Total	$	26,132	$	31,020

(a)Includes swaps and physical and financial contracts.

(b)Unobservable inputs were weighted by the relative fair value of the instrument.

The following table shows the changes in fair value for our risk management activities’ assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs (dollars in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
Commodity Contracts	2023		2022		2023		2022
Net derivative balance at beginning of period	$	6,622	$	9,650	$	(4,888)	$	(2,738)
Total net gains (losses) realized/unrealized:
Deferred as a regulatory asset or liability	(26,859)		(7,514)		(57,286)		9,293
Settlements	8,641		2,032		50,578		(2,387)
Transfers into Level 3 from Level 2	(1,289)		185		(1,289)		185
Transfers from Level 3 into Level 2	11,606		193		11,606		193
Net derivative balance at end of period	$	(1,279)	$	4,546	$	(1,279)	$	4,546
Net unrealized gains included in earnings related to instruments still held at end of period	$	—	$	—	$	—	$	—

Transfers in or out of Level 3 are typically related to our long dated energy transactions that extend beyond available quoted periods.

Financial Instruments Not Carried at Fair Value

The carrying value of our short-term borrowings approximate fair value and are classified within Level 2 of the fair value hierarchy. See Note 5 for our long-term debt fair values.


12.			Investments in Nuclear Decommissioning Trusts and Other Special Use Funds

We have investments in debt and equity securities held in Nuclear Decommissioning Trusts, Coal Reclamation Escrow Account, and an Active Union Employee Medical Account. Investments in debt securities are classified as available-for-sale securities. We record both debt and equity security investments at their fair value on our Comparative Balance Sheets. See Note 11 for a discussion of how fair value is determined and the classification of the investments within the fair value hierarchy. The investments in each trust or account are restricted for use and are intended to fund specified costs and activities as further described for each fund below.

Nuclear Decommissioning Trusts — APS established external decommissioning trusts in accordance with NRC regulations to fund the future costs APS expects to incur to decommission Palo Verde. Third-party investment managers are authorized to buy and sell securities per stated investment guidelines. The trust funds are invested in fixed income securities and equity securities. Earnings and proceeds from sales and maturities of securities are reinvested in the trusts. Because of the ability of APS to recover decommissioning costs in rates, and in accordance with the regulatory treatment, APS has deferred realized and unrealized gains and losses (including credit losses) in other regulatory liabilities.

Coal Reclamation Escrow Account — APS has investments restricted for the future coal mine reclamation funding related to Four Corners. This escrow account is primarily invested in fixed income securities. Earnings and proceeds from sales of securities are reinvested in the escrow account. Because of the ability of APS to recover coal reclamation costs in rates, and in accordance with the regulatory treatment, APS has deferred realized and unrealized gains and losses (including credit losses) in other regulatory liabilities. Activities relating to APS coal mine reclamation escrow account investments are included within the other special use funds in the table below.

Active Union Employee Medical Account — APS has investments restricted for paying active union employee medical costs. These investments may be used to pay active union employee medical costs incurred in the current and future periods. In 2022, APS was reimbursed $15 million for prior year active union employee medical claims from the active union employee medical account. The account is invested primarily in fixed income securities. In accordance with the ratemaking treatment, APS has deferred the unrealized gains and losses (including credit losses) in other regulatory liabilities. Activities relating to active union employee medical account investments are included within the other special use funds in the table below.

APS

The following tables present the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trusts and other special use fund assets (dollars in thousands):


	June 30, 2023
	Fair Value
Investment Type:	Nuclear Decommissioning Trusts		Other Special Use Funds		Total			Total Unrealized Gains		Total Unrealized Losses
Equity securities	$	519,099	$	27,250	$	546,349		$	378,973	$	(5)
Available for sale-fixed income securities	649,545		323,229		972,774		(a)	2,830		(58,178)
Other	(6,247)		1,519		(4,728)		(b)	—		(4)
Total	$	1,162,397	$	351,998	$	1,514,395		$	381,803	$	(58,187)

(a)As of June 30, 2023, the amortized cost basis of these available-for-sale investments is $1,028 million.

(b) Represents net pending securities sales and purchases.


	December 31, 2022
	Fair Value
Investment Type:	Nuclear Decommissioning Trusts		Other Special Use Funds		Total			Total Unrealized Gains		Total Unrealized Losses
Equity securities	$	487,240	$	66,974	$	554,214		$	334,817	$	(267)
Available for sale-fixed income securities	582,343		279,294		861,637		(a)	3,177		(68,795)
Other	3,827		963		4,790		(b)	—		(29)
Total	$	1,073,410	$	347,231	$	1,420,641		$	337,994	$	(69,091)

(a)As of December 31, 2022, the amortized cost basis of these available-for-sale investments is $927 million.

(b)Represents net pending securities sales and purchases.

The following table sets forth APS’s realized gains and losses relating to the sale and maturity of available-for-sale debt securities and equity securities, and the proceeds from the sale and maturity of these investment securities (dollars in thousands):


	Three Months Ended June 30,
	Nuclear Decommissioning Trusts		Other Special Use Funds		Total
2023
Realized gains	$	35,231	$	—	$	35,231
Realized losses	(11,192)		—		(11,192)
Proceeds from the sale of securities (a)	298,761		42,141		340,902
2022
Realized gains	$	6,282	$	—	$	6,282
Realized losses	(12,439)		—		(12,439)
Proceeds from the sale of securities (a)	309,966		20,466		330,432

(a) Proceeds are reinvested in the nuclear decommissioning trusts and other special use funds, excluding amounts reimbursed to the Company for active union employee medical claims from the active union employee medical account.


	Six Months Ended June 30,
	Nuclear Decommissioning Trusts		Other Special Use Funds		Total
2023
Realized gains	$	36,441	$	—	$	36,441
Realized losses	(16,886)		—		(16,886)
Proceeds from the sale of securities (a)	434,946		132,582		567,528
2022
Realized gains	$	7,305	$	—	$	7,305
Realized losses	(19,674)		—		(19,674)
Proceeds from the sale of securities (a)	629,659		62,011		691,670

Fixed Income Securities Contractual Maturities

The fair value of APS’s fixed income securities, summarized by contractual maturities, at June 30, 2023, is as follows (dollars in thousands):


	Nuclear Decommissioning Trusts		Coal Reclamation Escrow Account		Active Union Employee Medical Account		Total
Less than one year	$	19,020	$	57,267	$	38,684	$	114,971
1 year – 5 years	175,774		35,020		144,630		355,424
5 years – 10 years	158,261		—		43,678		201,939
Greater than 10 years	296,490		3,950		—		300,440
Total	$	649,545	$	96,237	$	226,992	$	972,774


13.			Changes in Accumulated Other Comprehensive Loss

The following tables show the changes in APS’s accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component (dollars in thousands):


	Pension and Other Postretirement Benefits
Three Months Ended June 30,
Balance March 31, 2023	$	(15,139)
OCI (loss) before reclassifications	(839)
Amounts reclassified from accumulated other comprehensive loss	431		(a)
Balance June 30, 2023	$	(15,547)

Balance March 31, 2022	$	(34,060)
OCI (loss) before reclassifications	(3,160)
Amounts reclassified from accumulated other comprehensive loss	999		(a)

Balance June 30, 2022	$	(36,221)


	Pension and Other Postretirement Benefits
Six Months Ended June 30,
Balance December 31, 2022	$	(15,596)
OCI (loss) before reclassifications	(839)
Amounts reclassified from accumulated other comprehensive loss	888		(a)
Balance June 30, 2023	$	(15,547)

Balance December 31, 2021	$	(34,880)
OCI (loss) before reclassifications	(3,160)
Amounts reclassified from accumulated other comprehensive loss	1,819		(a)

Balance June 30, 2022	$	(36,221)

(a)These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 7.


14.			Leases

We lease certain land, buildings, vehicles, equipment, and other property through rental agreements with varying terms, provisions, and expiration dates. APS also has certain purchased power agreements and energy storage agreements that qualify as lease arrangements. Our leases have remaining terms that expire in 2023 through 2073.

In 1986, APS entered into agreements with three separate lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. See Note 8. For regulatory reporting purposes, APS accounts for the three Palo Verde Unit 2 leases as operating leases for income statement and cash flow statement purposes, and for balance sheet purposes they are classified as finance leases.

APS has purchased power lease agreements that allow APS the right to the generation capacity from certain natural-gas fueled generators during certain months of each year throughout the term of the arrangements. As APS only has rights to use the assets during certain periods of each year the leases have non-consecutive periods of use. APS does not operate or maintain these leased assets. APS controls the dispatch of these leased assets and is required to pay fixed monthly capacity payments during the periods of use. For these types of leased assets APS has elected to combine both the lease and non-lease payment components and accounts for the entire fixed payment as a lease obligation. These purchased power lease contracts are accounted for as operating leases. The contracts do not contain purchase options or term extension options. In addition to the fixed monthly capacity payment, APS must also pay variable charges based on the actual production volume of the asset. The variable consideration is not included in the measurement of our lease obligation.

In January 2023, APS modified two existing purchase power operating lease agreements. Among other changes, the modifications extend the expiration dates of these contracts from October 2027 to October 2032 for one of the leases, and from September 2026 to October 2034 for the other lease. These agreements previously commenced in 2020 and 2021.

The following tables provide information related to our lease costs (dollars in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Operating Lease Cost - Purchased Power Lease Contracts	$	35,655	$	29,140	$	35,655	$	29,140
Operating Lease Cost - Land, Property, and Other Equipment	4,845		4,439		9,315		8,899
Total Operating Lease Cost	40,500		33,579		44,970		38,039
Finance Lease Cost - Palo Verde Unit 2 Finance Leases (b)	5,314		5,314		10,628		10,628
Variable lease cost (a)	47,988		42,594		64,694		61,273
Short term lease cost	7,403		2,201		8,804		3,501
Total lease cost	$	101,205	$	83,688	$	129,096	$	113,441

(a)Primarily relates to purchased power lease contracts.

(b)For regulatory purposes the costs relating to these finance leases are reported as a component of operating expense.

Lease costs are primarily included as a component of operating expenses on our Comparative Statements of Income. Lease costs relating to purchased power lease contracts are recorded in fuel and purchased power on the Comparative Statements of Income and are subject to recovery under the PSA or RES (see Note 6). The tables above reflect the lease cost amounts before the effect of regulatory deferral under the PSA and RES. Variable lease costs are recognized in the period the costs are incurred, and primarily relate to renewable purchased power lease contracts. Payments under most renewable purchased power lease contracts are dependent upon environmental factors, and due to the inherent uncertainty associated with the reliability of the fuel source, the payments are considered variable and are excluded from the measurement of lease liabilities and right-of-use lease assets. Certain of our lease agreements have lease terms with non-consecutive periods of use. For these agreements we recognize lease costs during the periods of use. Leases with initial terms of 12 months or less are considered short-term leases and are not recorded on the balance sheet.

The following table provides information related to the maturity of our lease liabilities (dollars in thousands):


	June 30, 2023
	Finance Leases		Operating Leases
Year	Palo Verde Unit 2 Finance Lease		Purchased Power Lease Contract		Other Land, Property & Equipment Lease		Total Operating Lease		Total
2023 (remaining 6 months)	$	10,628	$	100,130	$	7,789	$	107,919	$	118,547
2024	21,255		104,315		12,935		117,250		138,505
2025	21,255		121,082		10,569		131,651		152,906
2026	21,255		134,806		8,340		143,146		164,401
2027	21,255		160,727		6,384		167,111		188,366
Thereafter	127,531		944,317		66,810		1,011,127		1,138,658
Total lease commitments	223,179		1,565,377		112,827		1,678,204		1,901,383
Less imputed interest	43,440		329,398		42,086		371,484		414,924
Total lease liabilities	$	179,739	$	1,235,979	$	70,741	$	1,306,720	$	1,486,459

We recognize lease assets and liabilities upon lease commencement. At June 30, 2023, we have various lease arrangements that have been executed, but have not yet commenced. These arrangements primarily relate to energy storage assets. The lease commencement dates for these agreements have experienced delays. APS continues to work with the lessors to determine revised commencement dates. We expect lease commencements dates ranging from August 2023 through June 2025, with lease terms expiring through May 2045. We expect the total fixed consideration paid for these arrangements, which includes both lease and non-lease payments, will approximate $6.3 billion over the terms of the agreements.

The following tables provide other additional information related to lease liabilities (dollars in thousands):


	Six Months Ended June 30, 2023			Six Months Ended June 30, 2022
Cash paid for amounts included in the measurement of lease liabilities — operating cash flows:	$	13,539		$	12,714
Cash paid for amounts included in the measurement of finance liabilities - operating cash flows:	10,628			10,628
Right-of-use operating lease assets obtained in exchange for operating lease liabilities:	553,665		(a)	7,588

June 30, 2023

December 31, 2022

Finance
Leases

Operating
Leases

Finance
Leases

Operating
Leases

Weighted average remaining lease

11 years

10 years

11 years

7 years

Weighted average discount rate (b)

4.14%

4.43%

4.14%

2.17%

(a)Primarily relates to the two purchased power operating lease agreements that were modified in January 2023.

(b)Most of our lease agreements do not contain an implicit rate that is readily determinable. For these agreements we use our incremental borrowing rate to measure the present value of lease liabilities. We determine our incremental borrowing rate at lease commencement based on the rate of interest that we would have to pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. We use the implicit rate when it is readily determinable.


15.			Asset Retirement Obligations

During the six months ended June 30, 2023, the Company revised its cost estimates for existing Asset Retirement Obligations ("ARO") at Cholla related to the closure of ponds and facilities, which resulted in an increase to the ARO of approximately $36 million. Additionally, an updated Four Corners coal-fired power plant decommissioning estimate was updated, which resulted in a decrease of approximately $13 million. See additional details in Notes 6 and 10.

The following schedule shows the change in our asset retirement obligations for the six months ended June 30, 2023 (dollars in thousands):


	2023
Asset retirement obligations at January 1, 2023	$	797,762
Changes attributable to:
Accretion expense	21,313
Settlements	(2,868)
Estimated cash flow revisions	22,912
Asset retirement obligations at June 30, 2023	$	839,119

In accordance with regulatory accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal. See detail of regulatory liabilities in Note 6.

Name of Respondent:

Arizona Public Service Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/24/2023

Year/Period of Report

End of:

2023

STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges. For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote. Report data on a year-to-date basis.
Line No.	Item (a)	Unrealized Gains and Losses on Available-For-Sale Securities (b)	Minimum Pension Liability Adjustment (net amount) (c)	Foreign Currency Hedges (d)	Other Adjustments (e)	Other Cash Flow Hedges Interest Rate Swaps (f)	Other Cash Flow Hedges [Specify] (g)	Totals for each category of items recorded in Account 219 (h)	Net Income (Carried Forward from Page 116, Line 78) (i)	Total Comprehensive Income (j)
1	Balance of Account 219 at Beginning of Preceding Year				34,880,454		68	34,880,386
2	Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income				1,819,186			1,819,186
3	Preceding Quarter/Year to Date Changes in Fair Value				3,160,160			3,160,160
4	Total (lines 2 and 3)				1,340,974			1,340,974	194,167,847	192,826,873
5	Balance of Account 219 at End of Preceding Quarter/Year				36,221,428		68	36,221,360
6	Balance of Account 219 at Beginning of Current Year				15,596,525		68	15,596,457
7	Current Quarter/Year to Date Reclassifications from Account 219 to Net Income				887,961			887,961
8	Current Quarter/Year to Date Changes in Fair Value				838,606			838,606
9	Total (lines 7 and 8)				49,355			49,355	129,598,136	129,647,491
10	Balance of Account 219 at End of Current Quarter/Year				15,547,170		68	15,547,102

Name of Respondent:

Arizona Public Service Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/24/2023

Year/Period of Report

End of:

2023

SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and in column (h) common function.
Line No.	Classification (a)	Total Company For the Current Year/Quarter Ended (b)	Electric (c)	Gas (d)	Other (Specify) (e)	Other (Specify) (f)	Other (Specify) (g)	Common (h)
1	UtilityPlantAbstract UTILITY PLANT
2	UtilityPlantInServiceAbstract In Service
3	UtilityPlantInServiceClassified Plant in Service (Classified)	22,085,776,465	22,085,776,465
4	UtilityPlantInServicePropertyUnderCapitalLeases Property Under Capital Leases	1,512,105,764	1,512,105,764
5	UtilityPlantInServicePlantPurchasedOrSold Plant Purchased or Sold
6	UtilityPlantInServiceCompletedConstructionNotClassified Completed Construction not Classified	2,434,047,440	2,434,047,440
7	UtilityPlantInServiceExperimentalPlantUnclassified Experimental Plant Unclassified
8	UtilityPlantInServiceClassifiedAndUnclassified Total (3 thru 7)	26,031,929,669	26,031,929,669
9	UtilityPlantLeasedToOthers Leased to Others
10	UtilityPlantHeldForFutureUse Held for Future Use	10,206,915	10,206,915
11	ConstructionWorkInProgress Construction Work in Progress	1,296,260,650	1,296,260,650
12	UtilityPlantAcquisitionAdjustment Acquisition Adjustments	255,525,921	255,525,921
13	UtilityPlantAndConstructionWorkInProgress Total Utility Plant (8 thru 12)	27,593,923,155	27,593,923,155
14	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Accumulated Provisions for Depreciation, Amortization, & Depletion	9,128,837,178	9,128,837,178
15	UtilityPlantNet Net Utility Plant (13 less 14)	18,465,085,977	18,465,085,977
16	DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17	AccumulatedProvisionForDepreciationAmortizationAndDepletionUtilityPlantInServiceAbstract In Service:
18	DepreciationUtilityPlantInService Depreciation	7,915,964,313	7,915,964,313
19	AmortizationAndDepletionOfProducingNaturalGasLandAndLandRightsutilityPlantInService Amortization and Depletion of Producing Natural Gas Land and Land Rights
20	AmortizationOfUndergroundStorageLandAndLandRightsutilityPlantInService Amortization of Underground Storage Land and Land Rights
21	AmortizationOfOtherUtilityPlantUtilityPlantInService Amortization of Other Utility Plant	1,119,995,535	1,119,995,535
22	DepreciationAmortizationAndDepletionUtilityPlantInService Total in Service (18 thru 21)	9,035,959,848	9,035,959,848
23	DepreciationAmortizationAndDepletionUtilityPlantLeasedToOthersAbstract Leased to Others
24	DepreciationUtilityPlantLeasedToOthers Depreciation
25	AmortizationAndDepletionUtilityPlantLeasedToOthers Amortization and Depletion
26	DepreciationAmortizationAndDepletionUtilityPlantLeasedToOthers Total Leased to Others (24 & 25)
27	DepreciationAndAmortizationUtilityPlantHeldForFutureUseAbstract Held for Future Use
28	DepreciationUtilityPlantHeldForFutureUse Depreciation
29	AmortizationUtilityPlantHeldForFutureUse Amortization
30	DepreciationAndAmortizationUtilityPlantHeldForFutureUse Total Held for Future Use (28 & 29)
31	AbandonmentOfLeases Abandonment of Leases (Natural Gas)
32	AmortizationOfPlantAcquisitionAdjustment Amortization of Plant Acquisition Adjustment	92,877,330	92,877,330
33	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Total Accum Prov (equals 14) (22,26,30,31,32)	9,128,837,178	9,128,837,178

Name of Respondent:

Arizona Public Service Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/24/2023

Year/Period of Report

End of:

2023

Electric Plant In Service and Accum Provision For Depr by Function
Report below the original cost of plant in service by function. In addition to Account 101, include Account 102, and Account 106. Report in column (b) the original cost of plant in service and in column(c) the accumulated provision for depreciation and amortization by function.
Line No.	Item (a)	Plant in Service Balance at End of Quarter (b)	Accumulated Depreciation And Amortization Balance at End of Quarter (c)
1	Intangible Plant	1,124,146,894	859,384,585
2	Steam Production Plant	2,331,265,313	1,208,469,700
3	Nuclear Production Plant	3,337,298,766	1,741,024,447
4	Hydraulic Production - Conventional
5	Hydraulic Production - Pumped Storage
6	Other Production	4,282,305,502	1,333,882,756
7	Transmission	3,703,535,559	1,102,575,191
8	Distribution	8,235,819,257	2,182,377,974
9	Regional Transmission and Market Operation
10	General	1,505,452,613	608,245,195
11	TOTAL (Total of lines 1 through 10)	24,519,823,904	9,035,959,848

Name of Respondent:

Arizona Public Service Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/24/2023

Year/Period of Report

End of:

2023

Transmission Service and Generation Interconnection Study Costs
Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and generator interconnection studies. List each study separately. In column (a) provide the name of the study. In column (b) report the cost incurred to perform the study at the end of period. In column (c) report the account charged with the cost of the study. In column (d) report the amounts received for reimbursement of the study costs at end of period. In column (e) report the account credited with the reimbursement received for performing the study.
Line No.	DescriptionOfStudyPerformed Description (a)	StudyCostsIncurred Costs Incurred During Period (b)	StudyCostsAccountCharged Account Charged (c)	StudyCostsReimbursements Reimbursements Received During the Period (d)	StudyCostsAccountReimbursed Account Credited With Reimbursement (e)
1	Transmission Studies
20	Total
21	Generation Studies
22	WA353816	663	143		143
23	WA377418	568	143		143
24	WA377611	655	143		143
25	WA377697	335	143		143
26	WA377818	647	143		143
27	WA402793	492	143		143
28	WA402826	437	143		143
29	WA425876	2,771	143		143
30	WA431805	665	143		143
31	WA431809	515	143		143
32	WA431939	613	143		143
33	WA432055	673	143		143
34	WA432060	192	143		143
35	WA444215	597	143		143
36	WA444217	1,367	143		143
37	WA459370	3,405	143		143
38	WA459429	2,783	143		143
39	WA459497	2,395	143		143
40	WA459537	789	143		143
41	WA459895	3,677	143		143
42	WA459896	604	143		143
43	WA488493	1,248	143		143
44	WA517285	654	143		143
45	WA602005	322	143		143
46	WA511627	321	143		143
47	WA517253	2,539	143		143
48	WA545531	1,535	143		143
49	WA545728	4,928	143		143
50	WA546664	933	143		143
51	WA574357	1,098	143		143
52	99-143-998	879,288	143		143
53	WA546774	293	143		143
54	WA611054	1,491	143		143
55	WA623223		143		143
56	WA669358	45,138	143		143
57	WA686220		143		143
58	WA701597		143		143
59	WA706720		143		143
60	WA707030		143		143
61	WA708250	55,182	143		143
62	WA715802		143		143
63	WA728495	3,141	143		143
64	WA738852	10,037	143	15,000	143
65	WA742205		143	500	143
66	WA743875	20	143	500	143
67	WA746492	29	143	500	143
68	WA746495	29	143	500	143
69	WA747390	29	143	5,000	143
70	99-143-996	10,203,341	143		143
71	02-3221A	25	143	25	143
72	02-8111A	2,548	143	1,867	143
73	02-8113A	290	143	7,690	143
74	02-8201A	734	143	560	143
75	02-8336A		143	535	143
76	02-8338A	3,759	143		143
77	02-8340A	1,114	143	428	143
78	02-8344A		143	31,438	143
79	02-8350A	167	143		143
80	02-8356A	8,055	143		143
81	02-8364A	1,193	143		143
82	ACEPC538	2,592	143	320,000	143
83	AMRC542	3,720	143	500,000	143
84	AMRC543	3,431	143	500,000	143
85	AZHALF534	543	143	160,000	143
86	CEDAR535	1,548	143	250,000	143
87	CEDAR541	3,849	143	500,000	143
88	CEDARPC533	3,949	143	500,000	143
89	CROSSOVER	2,049	143		143
90	EDFPC523	3,616	143	500,000	143
91	EDFPC524	3,669	143	500,000	143
92	EDFPC525	3,669	143	500,000	143
93	EDFPC527	3,669	143	500,000	143
94	EDFPC529	3,616	143	500,000	143
95	EDPRPC522	3,770	143	500,000	143
96	EDPRPC526	3,107	143	500,000	143
97	EDPRPC528	3,616	143	500,000	143
98	EDPRPC530	3,642	143	500,000	143
99	ELSOL	1,315	143		143
100	ENGIE552	3,247	143	500,000	143
101	EOLUS532	3,287	143	500,000	143
102	GOSOLAR	1,350	143	250,000	143
103	HECATE551	951	143	160,000	143
104	HOPI	2,056	143		143
105	HYDRO544	3,720	143	500,000	143
106	HYDRO545	3,188	143	500,000	143
107	LDC200	1,776	143		143
108	LDC400	1,775	143		143
109	MATRIX	4,030	143		143
110	NEXTERAOFF	4,109	143		143
111	NFQ338-FAS	481	143		143
112	NTUABB549	1,721	143	250,000	143
113	NTUAGM548	1,721	143	250,000	143
114	ORIGISDG	1,371	143	250,000	143
115	PREC531	789	143	250,000	143
116	PRIMERGYSH	4,112	143		143
117	PRIMERGYSS	4,107	143		143
118	APSFHBESS	1,199	143		143
119	APSREDROCK	761	143		143
120	APSTSMC	50	143		143
121	BRPCOPPER5	1,930	143		143
122	EDPRBCW	2,948	143		143
123	GILABEND	736	143		143
124	GILABEND2	1,159	143		143
125	HORUS	843	143		143
126	NEXTERA	3,960	143		143
127	PLOMOSA	250,675	143		143
128	PVKING	63	143		143
129	Q395MMA	85	143		143
130	Q493LGIA	1,843	143		143
131	SP102MMA	425	143		143
132	SP106	434	143		143
133	VERMA	955	143		143
134	PWDDOLAN	1,194	143	250,000	143
135	Q225MMA	27	143	10,000	143
136	Q266MMA	121	143	10,000	143
137	Q230-MMA	84	143		143
138	Q271-MMA	84	143		143
139	Q278EDFR	849	143	25,000	143
140	Q295LGIA		143	25,000	143
141	Q442-LGIA	2,087	143		143
142	Q443-LGIA	2,088	143		143
143	Q444-LGIA	11,080	143		143
144	Q445-LGIA	4,181	143		143
145	Q446-LGIA	4,178	143		143
146	Q447-LGIA	4,474	143		143
147	Q448-LGIA	4,178	143		143
148	Q449-LGIA	4,178	143		143
149	Q450-LGIA	4,179	143		143
150	Q451-LGIA	1,316	143		143
151	Q452-LGIA	4,174	143		143
152	Q454-LGIA	4,175	143		143
153	Q455-LGIA	4,179	143		143
154	Q456-LGIA	1,792	143		143
155	Q457-LGIA	12,772	143		143
156	Q458-LGIA	2,081	143		143
157	Q459-LGIA	4,174	143		143
158	Q460-LGIA	4,174	143		143
159	Q461-LGIA	2,670	143		143
160	Q462-LGIA	4,069	143		143
161	Q463-LGIA	26	143		143
162	Q464-LGIA	2,088	143		143
163	Q465-LGIA	4,176	143		143
164	Q466-LGIA	4,179	143		143
165	Q467-LGIA	2,086	143		143
166	Q468-LGIA	4,174	143		143
167	Q470-LGIA	2,057	143		143
168	Q471-LGIA	2,060	143		143
169	Q472-LGIA	27	143		143
170	Q473-LGIA		143		143
171	Q474-LGIA	4,179	143		143
172	Q475-LGIA	2,051	143		143
173	QBSNEXTERA	4,039	143		143
174	QWVNEXTERA	4,125	143		143
175	REDHAWK600	251,143	143		143
176	REV550	2,752	143	500,000	143
177	RWEHARRIOT	4,115	143		143
178	SBENERGY	3,363	143	500,000	143
179	SILICON546	3,351	143	500,000	143
180	SILICON547	2,941	143	500,000	143
181	SOLGRID	1,796	143		143
182	SP104	207	143		143
183	SP105	207	143		143
184	SP107Q196	681	143	25,000	143
185	SPPAAID	1,932	143		143
186	SUNDEVIL	2,052	143		143
187	SWBIOGAS	322	143		143
188	THELONIOUS	1,314	143		143
189	VALLEYWTW	36,362	143		143
190	WA662456		143		143
191	WA465205		143		143
192	WA539400		143		143
193	WA573994	5,244	143		143
194	WA597916	2,611	143		143
195	WA606497	1,044	143		143
196	WA632339	9,167	143		143
197	WA634317	130	143		143
198	WA383670	4,708	143		143
199	WA384886	678	143		143
200	WA402545		143		143
201	WA402547	87	143		143
202	WA425874	4,950	143		143
203	WA431719	100,856	143		143
204	WA431807	232	143		143
205	WA431944	3,448	143		143
206	WA431968	518	143		143
207	WA432059	1,270	143		143
208	WA450463	311	143		143
209	WA459431		143		143
210	WA459432	679	143		143
211	WA459433		143		143
212	WA459505	1,442	143		143
213	WA488489	71	143		143
214	WA488579	624	143		143
215	WA488582	630	143		143
216	WA503830	151	143		143
217	WA511475		143		143
218	WA511477	30	143		143
219	WA516333	1,153	143		143
220	WA516518	1,396	143		143
221	WA516741	1,828	143		143
222	WA517446	2,932	143		143
223	WA517447	2,899	143		143
224	WA517448	2,892	143		143
225	WA517449	569	143		143
226	WA532273	6	143		143
227	WA532276	15	143		143
228	WA534568	146	143		143
229	WA539190	155	143		143
230	WA544770	439	143		143
231	WA545423	346	143		143
232	WA545425	123	143		143
233	WA545722	1,189	143		143
234	WA545757	5,772	143		143
235	WA546276	1,014	143		143
236	WA546547	1,323	143		143
237	WA546548	2,381	143		143
238	WA546667	921	143		143
239	WA546767	493	143		143
240	WA546770	260	143		143
241	WA551476	1,297	143		143
242	WA556959		143		143
243	WA571836	1,737	143		143
244	WA571837	1,649	143		143
245	WA574418	1,677	143		143
246	WA574485	3,104	143		143
247	WA574522	2,425	143		143
248	WA574523	18,783	143		143
249	WA574525	6,413	143		143
250	WA574690	9	143		143
251	WA574721	813	143		143
252	WA574748		143		143
253	WA574749	955	143		143
254	WA574775	4,982	143		143
255	WA574782	3,492	143		143
256	WA574791		143		143
257	WA574816	825	143		143
258	WA574818	2,078	143		143
259	WA574838	2,841	143		143
260	WA574842	3,251	143		143
261	WA594256	6,349	143		143
262	WA594257	3,205	143		143
263	WA604606	7,122	143		143
264	WA606554	3,282	143		143
265	WA606616	3,841	143		143
266	WA606634	6,410	143		143
267	WA606635	4,929	143		143
268	WA606636	4,945	143		143
269	WA606637	4,888	143		143
270	WA606835	2,100	143		143
271	WA606863	3,800	143		143
272	WA606864	2,532	143		143
273	WA606865	5,356	143		143
274	WA606866	6,993	143		143
275	WA606867	1,374	143		143
276	WA606868	15,640	143		143
277	WA606869	3,158	143		143
278	WA606871	3,202	143		143
279	WA606872	339	143		143
280	WA606891	6,474	143		143
281	WA606892	1,987	143		143
282	WA606894	2,990	143		143
283	WA606909	3,035	143		143
284	WA606911	3,816	143		143
285	WA606912	2,790	143		143
286	WA606914	3,157	143		143
287	WA606915	6,457	143		143
288	WA618021	18,170	143		143
289	WA630428	2,498	143		143
290	WA634246	1,876	143		143
291	WA634254	1	143		143
292	WA634257	3,038	143		143
293	WA636515	6,413	143		143
294	WA636518	6,411	143		143
295	WA636520	3,086	143		143
296	WA636581	250,030	143		143
297	WA636699	5,352	143		143
298	WA636707	2,250	143		143
299	WA636708	5,383	143		143
300	WA636711	5,381	143		143
301	WA636716	3,176	143		143
302	WA636722	3,162	143		143
303	WA636731	3,247	143		143
304	WA636732	3,834	143		143
305	WA636749	3,228	143		143
306	WA636750	3,231	143		143
307	WA636751	3,233	143		143
308	WA636755	3,233	143		143
309	WA636760	17	143		143
310	WA636761	5,227	143		143
311	WA636830	5,361	143		143
312	WA636842	4,221	143		143
313	WA636844	5,329	143		143
314	WA636863	88	143		143
315	WA636864	88	143		143
316	WA636865	6,443	143		143
317	WA636872	732	143		143
318	WA636873	732	143		143
319	WA636874	11,611	143		143
320	WA636883	3,236	143		143
321	WA636904	6,465	143		143
322	WA636920	6,476	143		143
323	WA636929	5,325	143		143
324	WA636934	6,472	143		143
325	WA636935	3,233	143		143
326	WA636938	6,472	143		143
327	WA637059	356	143		143
328	WA637061	3,231	143		143
329	WA637064	5,335	143		143
330	WA637065	6,289	143		143
331	WA637066	4,502	143		143
332	WA637067	2,600	143	13,770	143
333	WA637068	6,382	143		143
334	WA637071		143		143
335	WA637538	308	143		143
336	WA488486	339	143		143
337	WA517323	335	143		143
39	Total	9,962,361		13,034,653
40	Grand Total	9,962,361		13,034,653

Name of Respondent:

Arizona Public Service Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/24/2023

Year/Period of Report

End of:

2023

OTHER REGULATORY ASSETS (Account 182.3)
Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes. For Regulatory Assets being amortized, show period of amortization.
				CREDITS
Line No.	DescriptionAndPurposeOfOtherRegulatoryAssets Description and Purpose of Other Regulatory Assets (a)	OtherRegulatoryAssets Balance at Beginning of Current Quarter/Year (b)	IncreaseDecreaseInOtherRegulatoryAssets Debits (c)	OtherRegulatoryAssetsWrittenOffAccountCharged Written off During Quarter/Year Account Charged (d)	OtherRegulatoryAssetsWrittenOffRecovered Written off During the Period Amount (e)	OtherRegulatoryAssets Balance at end of Current Quarter/Year (f)
1	Deferred Compensation Amortize through 2036	34,492,067				34,492,067
2	Capital Contribution on Phoenix-Mead Transmission U-1345-90-269 Amortize through 2050	8,965,104		108	83,010	8,882,094
3	Income Taxes - ACUDC Equity E-01345A-03-0437 Amortize through 2053	179,817,987	3,853,172	283,410.1	1,811,728	181,859,431
4	Deferred Fuel and Purchased Power E-01345A-03-0437, E-01345A-05-0816, -0826, -0827 Amortize through 2024	469,962,112	100,998,892	411.8,555,547,502,411.9	137,681,793	433,279,211
5	Deferred Fuel and Purchased Power - Interest E-01345A-03-0437, E-01345A-05-0816, -0826, -0827 Amortize through 2024	3,095,595	4,075,356			7,170,951
6	Navajo Coal Reclamation E-01345A-08-0172 Amortize through 2026	13,116,972		501	744,593	12,372,379
7	Pension and Other Postretirement Benefits E-01345A-08-0172	628,727,462	20,174,569	128, 228.3, 926	8,753,775	640,148,256
8	Income Taxes - Change in Rates Amortize through 2051	85,553	8,575			76,978
9	Income Taxes - Medicare Subsidy Amortize through 2024	2,440,393		283,410.1	275,452	2,164,941
10	Income Taxes - Investment Tax Credit Basis Adjustment E-01345A-16-0036 Amortize through 2056	24,094,995	5,816,806	283,410.1	257,327	29,654,474
11	Property Tax Deferral E-01345A-11-0224 Amortize thorugh 2027	38,914,754		408	2,142,342	36,772,412
12	Retired Power Plant Costs Amortize through 2033	94,903,346		403, 404, 407	3,789,012	91,114,334
13	Four Corners Cost Deferral Amortize through 2024	13,979,375		407	2,019,146	11,960,229
14	SCR Deferral E-01345A-16-0036 Amortize though 2031	95,587,540		407	2,036,738	93,550,802
15	TCA Balancing account E-01345A-16-0036 Amortize through 2025		3,502,138	400	2,310,918	1,191,220
16	Deficient Deferred Income Taxes Tax Cuts & Jobs Act-ACC Portion to be amortized through 2046	2,656,363		283/410.1	(a) 25,244	2,631,119
17	Deficient Deferred Income Taxes Tax Cuts & Jobs Act-FERC Amortize through 2058	7,982,511		283/410.1	(b) 118,913	7,863,598
18	Tax Expense Adjustor Mechanism Amortize through 2031	5,681,456		400	163,888	5,517,568
19	Ocotillo Deferral E-01345A-16-0036 Amortize though 2031	135,766,370		407	2,376,814	133,389,556
20	Demand Side Management Amortize through 2023	606,019	202,418	908	808,437
21	Customer bill relief deferral E-00000A-19-128	1,800,000				1,800,000
22	Active Union Medical Trust E-01345A-19-0236	15,009,782	2,664,968			17,674,750
23	E3/E4 CC Fees Deferral E-01345A-19-0236	515,650	119,967			635,617
24	Deferred Fuel and Purchased Power - Mark-to-Market E-01345A-03-0437, E-01345A-05-0816, -0826, -0827 Amortize through 2026	61,858,255	5,329,979			67,188,234
25	FERC Transmission True up Amortize through 2025		1,544,737			1,544,737
44	TOTAL	1,839,888,555	148,291,577		165,399,130	1,822,781,002

Name of Respondent:

Arizona Public Service Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/24/2023

Year/Period of Report

End of:

2023

FOOTNOTE DATA

(a) Concept: OtherRegulatoryAssetsWrittenOffRecovered

Deficient Deferred Income Taxes – Tax Cuts and Jobs Act-ACC: Amount Amortized to Income Tax Expense Account 410.1: $19,003

(b) Concept: OtherRegulatoryAssetsWrittenOffRecovered

Deficient Deferred Income Taxes – Tax Cuts and Jobs Act-FERC: Amount Amortized to Income Tax Expense Account 410.1: $89,519

Name of Respondent:

Arizona Public Service Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/24/2023

Year/Period of Report

End of:

2023

OTHER REGULATORY LIABILITIES (Account 254)
Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if applicable. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes. For Regulatory Liabilities being amortized, show period of amortization.
			DEBITS
Line No.	Description and Purpose of Other Regulatory Liabilities (a)	Balance at Beginning of Current Quarter/Year (b)	Account Credited (c)	Amount (d)	Credits (e)	Balance at End of Current Quarter/Year (f)
1	Asset Retirement Obligations FERC Order# 552 Amortize through 2057	396,106,747			10,921,159	407,027,906
2	Spent Nuclear Fuel Storage E-01345A-03-0437, E-01345A-05-0816, -0826, -0827 Amortize through 2027	37,312,690	518	1,640,477	388,575	36,060,788
3	Income Taxes - Unamortized Investment Tax Credit E-01345A-05-0816, -0826, -0827 Amortize through 2056	49,031,414	190	516,617	10,844,221	59,359,018
4	Sundance Maintenance E-01345A-05-0816, -0826, -0827 Amortize through 2031	17,667,259			774,045	18,441,304
5	Income Tax - Change in Rates Amortize through 2051	64,653,452	190/410.1	632,163		64,021,289
6	Renewable Energy Standard E-01345A-03-0437, E-01345A-05-0816, -0826, -0827 Amortize through 2024	30,188,177	549	22,360,606	21,696,249	29,523,820
7	Demand Side Management E-01345A-03-0437, E-01345A-05-0816, -0826, -0827 Amortize through 2023	14,207,278	908	9,040,261	17,068,986	22,236,003
8	Other Postretirement Benefits E-01345A-08-0172	258,955,011	926.1	12,375,368		246,579,643
9	Removal costs Cholla	16,363,271			233,038	16,596,309
10	Removal costs Saguaro	11,493,549				11,493,549
11	Property Tax Deferral E01345A-11-0224 Amortize though 2024	14,353,303	408	1,167,768		13,185,535
12	Four Corners Coal Reclamation E-013454A-05-0816, -0826, -0827 Amortize through 2038	53,348,445	501	537,574	578,919	53,389,790
13	Deferred Gain on Sale of Property E-01345A-09-0357 Amortize through 2024	47,501			1,866	49,367
14	Excess Deferred Income Taxes Tax Cuts & Jobs Act-ACC Portion to be amortized through 2046	973,234,561	190/411.1	(a) 9,244,847		963,989,714
15	Excess Deferred Income Taxes Tax Cuts & Jobs Act-FERC Amortize through 2058	229,690,623	190/411.1	(b) 1,733,903		227,956,720
16	Tax Expense Adjustor Mechanism E-01345A-18-0003	4,835,048				4,835,048
17	EIS Balancing Account Amortize through 2025	1,469,319	400	488,201		981,118
18	FERC Transmission True up Amortize through 2024	12,597,156	400	6,727,133		5,870,023
19	Deferred Fuel and Purchased Power - Mark-to-Market E-01345A-03-0437, E-01345A-05-0816, -0826, -0827 Amortize through 2026	3,396,270	547,555	3,396,270		0
20	TCA Balancing Account Amortize through 2024	5,852,503	400	1,935,120	2,310,918	6,228,301
41	TOTAL	2,194,803,577		71,796,308	64,817,976	2,187,825,245

Name of Respondent:

Arizona Public Service Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/24/2023

Year/Period of Report

End of:

2023

FOOTNOTE DATA

(a) Concept: DecreaseInOtherRegulatoryLiabilities

Excess Deferred Income Taxes – Tax Cuts & Jobs Act-ACC: Amount Amortized to Income Tax Expense Account 411.1: $6,959,520

(b) Concept: DecreaseInOtherRegulatoryLiabilities

Excess Deferred Income Taxes – Tax Cuts & Jobs Act-FERC: Amount Amortized to Income Tax Expense Account 411.1: $1,305,282

Name of Respondent:

Arizona Public Service Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/24/2023

Year/Period of Report

End of:

2023

Electric Operating Revenues
The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (f), and (g). Unbilled revenues and MWH related to unbilled revenues need not be reported separately as required in the annual version of these pages. Report below operating revenues for each prescribed account, and manufactured gas revenues in total. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accounts; except that where separate meter readings are added for billing purposes, one customer should be counted for each group of meters added. The average number of customers means the average of twelve figures at the close of each month. If increases or decreases from previous period (columns (c),(e), and (g)), are not derived from previously reported figures, explain any inconsistencies in a footnote. Disclose amounts of $250,000 or greater in a footnote for accounts 451, 456, and 457.2. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by the respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of classification in a footnote.) See page 108, Important Changes During Period, for important new territory added and important rate increase or decreases. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbilled revenue by accounts. Include unmetered sales. Provide details of such Sales in a footnote.
Line No.	Title of Account (a)	Operating Revenues Year to Date Quarterly/Annual (b)	Operating Revenues Previous year (no Quarterly) (c)	MEGAWATT HOURS SOLD Year to Date Quarterly/Annual (d)	MEGAWATT HOURS SOLD Amount Previous year (no Quarterly) (e)	AVG.NO. CUSTOMERS PER MONTH Current Year (no Quarterly) (f)	AVG.NO. CUSTOMERS PER MONTH Previous Year (no Quarterly) (g)
1	SalesOfElectricityHeadingAbstract Sales of Electricity
2	ResidentialSalesAbstract (440) Residential Sales	952,039,158	2,046,110,746	6,252,132	14,756,798	1,222,612	1,202,975
3	CommercialAndIndustrialSalesAbstract (442) Commercial and Industrial Sales
4	CommercialSalesAbstract Small (or Comm.) (See Instr. 4)	(a) 807,498,519	(e) 1,551,090,439	6,403,156	13,535,799	138,346	137,112
5	IndustrialSalesAbstract Large (or Ind.) (See Instr. 4)	(b) 104,599,690	(f) 195,592,871	1,026,184	2,121,332	2,734	2,825
6	PublicStreetAndHighwayLightingAbstract (444) Public Street and Highway Lighting	10,647,193	20,780,644	50,672	106,149	1,216	1,310
7	OtherSalesToPublicAuthoritiesAbstract (445) Other Sales to Public Authorities	103,659	152,956	1,156	1,879	136	137
8	SalesToRailroadsAndRailwaysAbstract (446) Sales to Railroads and Railways
9	InterdepartmentalSalesAbstract (448) Interdepartmental Sales
10	SalesToUltimateConsumersAbstract TOTAL Sales to Ultimate Consumers	1,874,888,219	3,813,727,656	13,733,300	30,521,957	1,365,044	1,344,359
11	SalesForResaleAbstract (447) Sales for Resale	120,647,408	397,994,174	2,005,031	4,076,971	54	55
12	SalesOfElectricityAbstract TOTAL Sales of Electricity	1,995,535,627	4,211,721,830	15,738,331	34,598,928	1,365,098	1,344,414
13	ProvisionForRateRefundsAbstract (Less) (449.1) Provision for Rate Refunds
14	RevenuesNetOfProvisionForRefundsAbstract TOTAL Revenues Before Prov. for Refunds	1,995,535,627	4,211,721,830	15,738,331	34,598,928	1,365,098	1,344,414
15	OtherOperatingRevenuesAbstract Other Operating Revenues
16	ForfeitedDiscounts (450) Forfeited Discounts	1,054,370	1,241,171
17	MiscellaneousServiceRevenues (451) Miscellaneous Service Revenues	(c) 35,875	(g) 829,103
18	SalesOfWaterAndWaterPower (453) Sales of Water and Water Power
19	RentFromElectricProperty (454) Rent from Electric Property	425,171	1,695,334
20	InterdepartmentalRents (455) Interdepartmental Rents
21	OtherElectricRevenue (456) Other Electric Revenues	(d) 1,162,980	(h) 3,912,238
22	RevenuesFromTransmissionOfElectricityOfOthers (456.1) Revenues from Transmission of Electricity of Others	64,980,890	116,696,279
23	RegionalTransmissionServiceRevenues (457.1) Regional Control Service Revenues
24	MiscellaneousRevenue (457.2) Miscellaneous Revenues
25	OtherMiscellaneousOperatingRevenues Other Miscellaneous Operating Revenues
26	OtherOperatingRevenues TOTAL Other Operating Revenues	67,587,536	122,715,919
27	ElectricOperatingRevenues TOTAL Electric Operating Revenues	2,063,123,163	4,334,437,749
Line12, column (b) includes $ (i) 51,418,567 of unbilled revenues.
Line12, column (d) includes (j) 211,719 MWH relating to unbilled revenues

Name of Respondent:

Arizona Public Service Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/24/2023

Year/Period of Report

End of:

2023

FOOTNOTE DATA

(a) Concept: SmallOrCommercialSalesElectricOperatingRevenue

Basis of classification for small or large commercial and industrial sales is customer's NAICS code.Includes unmetered sales such as traffic lights, bus stop lighting, and public irrigation systems.

(b) Concept: LargeOrIndustrialSalesElectricOperatingRevenue

Basis of classification for small or large commercial and industrial sales is customer's NAICS code.




Other	$	(35,875)
Total	$	(35,875)

(d) Concept: OtherElectricRevenue


(456) - PCS Project	$	1,065,044
(456) - Fuel Loading	578,972
(456) - Facility Charges	165,307
(456) - Management/Administration Fees	303,862
(456) - Participant Station Power Revenue	78,904
(456) - Other	150,720
(456) - Surepay and Autopay Discount	(1,179,829)
Total	$	1,162,980

(e) Concept: SmallOrCommercialSalesElectricOperatingRevenue

Basis of classification for small or large commercial and industrial sales is customer's NAICS code.Includes unmetered sales such as traffic lights, bus stop lighting, and public irrigation systems.

(f) Concept: LargeOrIndustrialSalesElectricOperatingRevenue

Basis of classification for small or large commercial and industrial sales is customer's NAICS code.

(g) Concept: MiscellaneousServiceRevenues


Sturgeon Project Temp Power	$	(485,097)
Garfield & 6th High Rise	(113,787)
Other	(230,219)
Total	$	(829,103)

(h) Concept: OtherElectricRevenue


(456) - PCS Project	$	2,688,939
(456) - Fuel Loading	1,215,209
(456) - Bid Fee Proceeds	860,000
(456) - Management/Administration Fees	791,306
(456) - Participant Station Power Revenue	177,496
(456) - Other	227,513
(456) - Facility Charges	288,097
(456) - Surepay and Autopay Discount	(2,336,322)
Total	$	3,912,238

(i) Concept: RevenueFromSalesOfElectricityUnbilled


Unbilled Revenue
1440-100 Residential	$	29,862,797
1442-100 Commercial	20,710,259
1442-102 Industrial	807,962
1442-104 Irrigation	57,704
1440-100 Hwy lighting	(20,155)
	$	51,418,567

(j) Concept: MegawattHoursOfElectricitySoldUnbilled


Unbilled Revenue
1440-100 Residential						140,239
1442-100 Commercial						76,283
1442-102 Industrial						(5,135)
1442-104 Irrigation						472
1440-100 Hwy lighting						(140)
						211,719

Name of Respondent:

Arizona Public Service Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/24/2023

Year/Period of Report

End of:

2023

REGIONAL TRANSMISSION SERVICE REVENUES (Account 457.1)
The respondent shall report below the revenue collected for each service (i.e., control area administration, market administration, etc.) performed pursuant to a Commission approved tariff. All amounts separately billed must be detailed below.
Line No.	Description of Service (a)	Balance at End of Quarter 1 (b)	Balance at End of Quarter 2 (c)	Balance at End of Quarter 3 (d)	Balance at End of Year (e)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46	TOTAL

Name of Respondent:

Arizona Public Service Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/24/2023

Year/Period of Report

End of:

2023

ELECTRIC PRODUCTION, OTHER POWER SUPPLY EXPENSES, TRANSMISSION AND DISTRIBUTION EXPENSES

Report Electric production, other power supply expenses, transmission, regional market, and distribution expenses through the reporting period.
Line No.	Account (a)	Year to Date Quarter (b)
1	PowerProductionExpensesAbstract 1. POWER PRODUCTION AND OTHER SUPPLY EXPENSES
2	SteamPowerGenerationOperationsExpense Steam Power Generation - Operation (500-509)	160,147,682
3	SteamPowerGenerationMaintenanceExpense Steam Power Generation – Maintenance (510-515)	33,968,686
4	PowerProductionExpensesSteamPower Total Power Production Expenses - Steam Power	194,116,368
5	NuclearPowerGenerationOperationsExpense Nuclear Power Generation – Operation (517-525)	85,324,473
6	NuclearPowerGenerationMaintenanceExpense Nuclear Power Generation – Maintenance (528-532)	19,350,804
7	PowerProductionExpensesNuclearPower Total Power Production Expenses - Nuclear Power	104,675,277
8	HydraulicPowerGenerationOperationsExpense Hydraulic Power Generation – Operation (535-540.1)
9	HydraulicPowerGenerationMaintenanceExpense Hydraulic Power Generation – Maintenance (541-545.1)
10	PowerProductionExpensesHydraulicPower Total Power Production Expenses - Hydraulic Power
11	RentsOtherPowerGeneration Other Power Generation – Operation (546-550.1)	321,656,739
12	MaintenanceOfEnergyStorageEquipmentOtherPowerGeneration Other Power Generation – Maintenance (551-554.1)	28,597,356
13	MaintenanceOfMiscellaneousOtherPowerGenerationPlant Total Power Production Expenses - Other Power	350,254,095
14	OtherPowerSuplyExpensesAbstract Other Power Supply Expenses
15	PurchasedPower (555) Purchased Power	373,680,736
15.1	PowerPurchasedForStorageOperations (555.1) Power Purchased for Storage Operations	1,505,625
16	SystemControlAndLoadDispatchingElectric (556) System Control and Load Dispatching	1,838,115
17	OtherExpensesOtherPowerSupplyExpenses (557) Other Expenses	25,801,899
18	OtherPowerSupplyExpense Total Other Power Supply Expenses (line 15-17)	344,535,097
19	PowerProductionExpenses Total Power Production Expenses (Total of lines 4, 7, 10, 13 and 18)	993,580,837
20	TransmissionExpensesAbstract 2. TRANSMISSION EXPENSES
21	TransmissionExpensesOperationAbstract Transmission Operation Expenses
22	OperationSupervisionAndEngineeringElectricTransmissionExpenses (560) Operation Supervision and Engineering	705,276
24	LoadDispatchReliability (561.1) Load Dispatch-Reliability	1,736,416
25	LoadDispatchMonitorAndOperateTransmissionSystem (561.2) Load Dispatch-Monitor and Operate Transmission System	1,595,419
26	LoadDispatchTransmissionServiceAndScheduling (561.3) Load Dispatch-Transmission Service and Scheduling	471,410
27	SchedulingSystemControlAndDispatchServices (561.4) Scheduling, System Control and Dispatch Services	1,380,270
28	ReliabilityPlanningAndStandardsDevelopment (561.5) Reliability, Planning and Standards Development	1,226,468
29	TransmissionServiceStudies (561.6) Transmission Service Studies
30	GenerationInterconnectionStudies (561.7) Generation Interconnection Studies	44,194
31	ReliabilityPlanningAndStandardsDevelopmentServices (561.8) Reliability, Planning and Standards Development Services	498,979
32	StationExpensesTransmissionExpense (562) Station Expenses	436,320
32.1	OperationOfEnergyStorageEquipmentTransmissionExpense (562.1) Operation of Energy Storage Equipment
33	OverheadLineExpense (563) Overhead Lines Expenses	1,123,450
34	UndergroundLineExpensesTransmissionExpense (564) Underground Lines Expenses	16,097
35	TransmissionOfElectricityByOthers (565) Transmission of Electricity by Others	23,748,633
36	MiscellaneousTransmissionExpenses (566) Miscellaneous Transmission Expenses	8,455,659
37	RentsTransmissionElectricExpense (567) Rents	4,708,923
38	OperationSuppliesAndExpensesTransmissionExpense (567.1) Operation Supplies and Expenses (Non-Major)
39	TransmissionOperationExpense TOTAL Transmission Operation Expenses (Lines 22 - 38)	46,147,514
40	TransmissionMaintenanceAbstract Transmission Maintenance Expenses
41	MaintenanceSupervisionAndEngineeringElectricTransmissionExpenses (568) Maintenance Supervision and Engineering	286,549
42	MaintenanceOfStructuresTransmissionExpense (569) Maintenance of Structures	554,261
43	MaintenanceOfComputerHardwareTransmission (569.1) Maintenance of Computer Hardware
44	MaintenanceOfComputerSoftwareTransmission (569.2) Maintenance of Computer Software
45	MaintenanceOfCommunicationEquipmentElectricTransmission (569.3) Maintenance of Communication Equipment	115,571
46	MaintenanceOfMiscellaneousRegionalTransmissionPlant (569.4) Maintenance of Miscellaneous Regional Transmission Plant
47	MaintenanceOfStationEquipmentTransmission (570) Maintenance of Station Equipment	1,890,465
47.1	MaintenanceOfEnergyStorageEquipmentTransmission (570.1) Maintenance of Energy Storage Equipment
48	MaintenanceOfOverheadLinesTransmission (571) Maintenance of Overhead Lines	930,143
49	MaintenanceOfUndergroundLinesTransmission (572) Maintenance of Underground Lines	369,909
50	MaintenanceOfMiscellaneousTransmissionPlant (573) Maintenance of Miscellaneous Transmission Plant	1,173
51	MaintenanceOfTransmissionPlant (574) Maintenance of Transmission Plant
52	TransmissionMaintenanceExpenseElectric TOTAL Transmission Maintenance Expenses (Lines 41 – 51)	4,148,071
53	TransmissionExpenses Total Transmission Expenses (Lines 39 and 52)	50,295,585
54	RegionalMarketExpensesAbstract 3. REGIONAL MARKET EXPENSES
55	RegionalMarketExpensesOperationAbstract Regional Market Operation Expenses
56	OperationSupervision (575.1) Operation Supervision
57	DayAheadAndRealTimeMarketAdministration (575.2) Day-Ahead and Real-Time Market Facilitation	1,859,045
58	TransmissionRightsMarketAdministration (575.3) Transmission Rights Market Facilitation
59	CapacityMarketAdministration (575.4) Capacity Market Facilitation
60	AncillaryServicesMarketAdministration (575.5) Ancillary Services Market Facilitation
61	MarketMonitoringAndCompliance (575.6) Market Monitoring and Compliance
62	MarketFacilitationMonitoringAndComplianceServices (575.7) Market Facilitation, Monitoring and Compliance Services
63	RegionalMarketOperationExpense Regional Market Operation Expenses (Lines 55 - 62)	1,859,045
64	RegionalMarketExpensesMaintenanceAbstract Regional Market Maintenance Expenses
65	MaintenanceOfStructuresAndImprovementsRegionalMarketExpenses (576.1) Maintenance of Structures and Improvements
66	MaintenanceOfComputerHardware (576.2) Maintenance of Computer Hardware
67	MaintenanceOfComputerSoftware (576.3) Maintenance of Computer Software
68	MaintenanceOfCommunicationEquipmentRegionalMarketExpenses (576.4) Maintenance of Communication Equipment
69	MaintenanceOfMiscellaneousMarketOperationPlant (576.5) Maintenance of Miscellaneous Market Operation Plant
70	RegionalMarketMaintenanceExpense Regional Market Maintenance Expenses (Lines 65-69)
71	RegionalMarketExpenses TOTAL Regional Control and Market Operation Expenses (Lines 63,70)	1,859,045
72	DistributionExpensesAbstract 4. DISTRIBUTION EXPENSES
73	DistributionOperationExpensesElectric Distribution Operation Expenses (580-589)	33,159,940
74	DistributionMaintenanceExpenseElectric Distribution Maintenance Expenses (590-598)	20,316,992
75	DistributionExpenses Total Distribution Expenses (Lines 73 and 74)	53,476,932

Name of Respondent:

Arizona Public Service Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/24/2023

Year/Period of Report

End of:

2023

Electric Customer Accts, Service, Sales, Admin and General Expenses
Report the amount of expenses for customer accounts, service, sales, and administrative and general expenses year to date.
Line No.	Account (a)	Year to Date Quarter (b)
-	CustomerAccountsExpensesOperationsAbstract Operation
1	CustomerAccountExpenses (901-905) Customer Accounts Expenses	36,770,219
2	CustomerServiceAndInformationExpenses (907-910) Customer Service and Information Expenses	38,956,560
3	SalesExpenses (911-917) Sales Expenses	6,071,828
4	AdministrativeAndGeneralExpensesAbstract 8. ADMINISTRATIVE AND GENERAL EXPENSES
5	AdministrativeAndGeneralExpensesOperationAbstract Operation
6	AdministrativeAndGeneralSalaries (920) Administrative and General Salaries	52,879,015
7	OfficeSuppliesAndExpenses (921) Office Supplies and Expenses	4,179,271
8	AdministrativeExpensesTransferredCredit (Less) (922) Administrative Expenses Transferred-Credit	15,400,000
9	OutsideServicesEmployed (923) Outside Services Employed	26,593,920
10	PropertyInsurance (924) Property Insurance	2,603,907
11	InjuriesAndDamages (925) Injuries and Damages	13,413,503
12	EmployeePensionsAndBenefits (926) Employee Pensions and Benefits	18,166,331
13	FranchiseRequirements (927) Franchise Requirements
14	RegulatoryCommissionExpenses (928) Regulatory Commission Expenses	11,498,759
15	DuplicateChargesCredit (929) (Less) Duplicate Charges-Cr.
16	GeneralAdvertisingExpenses (930.1) General Advertising Expenses	3,944,760
17	MiscellaneousGeneralExpenses (930.2) Miscellaneous General Expenses	18,308,498
18	RentsAdministrativeAndGeneralExpense (931) Rents	3,463,412
19	AdministrativeAndGeneralOperationExpense TOTAL Operation (Total of lines 6 thru 18)	103,034,380
20	AdministrativeAndGeneralExpensesMaintenanceAbstract Maintenance
21	MaintenanceOfGeneralPlant (935) Maintenance of General Plant	6,903,747
22	AdministrativeAndGeneralExpenses TOTAL Administrative and General Expenses (Total of lines 19 and 21)	109,938,127

Name of Respondent:

Arizona Public Service Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/24/2023

Year/Period of Report

End of:

2023

TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")

Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to. Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c).
In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes.
In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (d), is provided.
Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column (g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the contract.
Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
Report in column (i) and (j) the total megawatthours received and delivered.
In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (0) in column (n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report purposes only on Page 401, Lines 16 and 17, respectively.
Footnote entries and provide explanations following all required data.

TRANSFER OF ENERGY

REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS

Line No.

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

(k)

(l)

(m)

(n)

Arizona Public Service Company

FNS

OATT

Various

(z)

6,711,916

Arizona Public Service Company

FNS

OATT

(aa)

57,609,337

Arizona Public Service Company

FNO

OATT

(ab)

57,609,337

Ajo Improvement Company

Not Available

(a)

FNO

OATT

Various

2,411

21,237

1,106

(ar)

22,335

City of Williams

Not Available

(b)

FNO

OATT

Various

13,040

61,814

3,580

(as)

20,337

85,731

Navajo Tribal Utility Authority

Not Available

(c)

FNO

OATT

Various

7,413

67,027

1,756

(at)

13,265

82,048

Navopache Electric Cooperative, Inc.

Tucson Electric Power

Navajo Tribal Utility Authority

(d)

FNO

OATT

Various

20,261

413,937

(au)

350

413,587

Southwest Public Power Agency

Not Available

(e)

FNO

OATT

Various

148

191,821

1,168,843

61,731

(av)

1,458,621

2,689,195

TOUA

Not Available

(f)

FNO

OATT

Various

15,790

97,956

5,642

(aw)

1,626

105,224

Broadview Energy JN LLC

Not Available

(g)

LFP

OATT

Various

167

193,108

1,393,251

(ax)

5,267

1,398,518

Broadview Energy KW- LLC

Not Available

(h)

LFP

OATT

Various

130

109,455

1,084,566

(ay)

15,330

1,099,896

Brookfield Renewable Trading and Marketing LP

Not Available

(i)

LFP

OATT

Various

12,060

208,570

(az)

208,537

Clines Corners Wind Farm LLC

Not Available

(j)

LFP

OATT

Various

120

156,829

1,001,138

(ba)

661

1,000,477

Duran Mesa Wind LLC

Not Available

(k)

LFP

OATT

Various

82,560

425,484

(bb)

134

425,350

El Cabo Wind

Not Available

(l)

LFP

OATT

Various

298

329,848

2,486,160

(bc)

1,247

2,484,913

Electrical District 3

Not Available

(m)

LFP

OATT

Various

23,612

750,967

(bd)

234

750,733

Grady Wind Energy Center- LLC

Not Available

(n)

LFP

OATT

Various

200

241,311

1,668,564

(be)

3,627

1,672,191

NOVO BioPower LLC

Not Available

(o)

LFP

OATT

Various

17,430

116,817

(bf)

116,722

Pattern New Mexico Wind LLC

Not Available

(p)

LFP

OATT

Various

100

834,282

Public Service Company of New Mexico

Not Available

(q)

LFP

OATT

Various

34,249

809,253

(bg)

121

809,132

Salt River Project

Not Available

(r)

LFP

OATT

Various

534

324,233

4,455,065

(bh)

641

4,454,424

Southwest BioGas

Not Available

(s)

LFP

OATT

Various

8,343

195

(bi)

4,172

12,710

Tecolote Wind LLC

Not Available

(t)

LFP

OATT

Various

132

197,808

1,101,252

(bj)

606

1,100,646

Tenaska Power Services Co.

Not Available

(u)

LFP

OATT

Various

100

15,535

834,408

Trico Electric Cooperative Inc.

Not Available

(v)

LFP

OATT

Various

4,084

16,686

(bk)

16,674

Tucson Electric Power Company

Not Available

(w)

LFP

OATT

Various

110

127,577

917,849

(bl)

242

917,607

Imperial Irrigation District Marketing

Not Available

SFP

OATT

Various

9,270

197,477

(bm)

197,455

PacifiCorp

Not Available

SFP

OATT

Various

146,673

1,112,544

Shell Energy North America LP

Not Available

SFP

OATT

Various

164,037

962,351

TGP Development Company,LLC

Not Available

SFP

OATT

Various

137,774

Arizona Electric Power Cooperative, Inc

Not Available

SFP

OATT

Various

3,351

13,468

(bn)

13,461

Mag Energy Solutions, Inc

Not Available

SFP

OATT

Various

UNIPER GLOBAL COMMODITIES NORTH AMERICA LLC

Not Available

SFP

OATT

Various

18,854

96,197

Vitol Inc.

Not Available

SFP

OATT

Various

(bo)

Arizona Electric Power Cooperative, Inc

Not Available

SFP

OATT

Various

747

3,444

Arizona Public Service Company

Not Available

SFP

OATT

Various

693

8,730

City of Glendale

Not Available

SFP

OATT

Various

112

5,020

(bp)

5,018

Clines Corners Wind Farm LLC

Not Available

SFP

OATT

Various

653

3,056

Exelon Generation Company, LLC

Not Available

SFP

OATT

Various

655

Imperial Irrigation District Marketing

Not Available

SFP

OATT

Various

3,216

44,852

(bq)

44,846

Macquarie Energy LLC

Not Available

SFP

OATT

Various

5,695

31,974

Mercuria Energy America LLC

Not Available

SFP

OATT

Various

845

8,185

Morgan Stanley

Not Available

SFP

OATT

Various

2,400

10,039

PacifiCorp

Not Available

SFP

OATT

Various

29,490

133,899

Powerex

Not Available

SFP

OATT

Various

11,992

56,963

Red Cloud Wind Farm

Not Available

SFP

OATT

Various

247

2,510

Shell Energy North America LP

Not Available

SFP

OATT

Various

2,480

13,497

(br)

220

13,277

Tenaska Power Services Co.

Not Available

SFP

OATT

Various

16,808

88,568

Trico Electric Cooperative Inc.

Not Available

SFP

OATT

Various

144

655

(bs)

627

UNIPER GLOBAL COMMODITIES NORTH AMERICA LLC

Not Available

SFP

OATT

Various

13,590

70,127

(bt)

118

70,009

Vitol Inc.

Not Available

SFP

OATT

Various

184

2,510

Arizona Electric Power Cooperative, Inc

Not Available

SFP

OATT

Various

216

1,220

(bu)

1,219

Avangrid Renewables, LLC

Not Available

SFP

OATT

Various

155

Broadview Energy JN LLC

Not Available

SFP

OATT

Various

(ac)

89,685

Broadview Energy KW- LLC

Not Available

SFP

OATT

Various

(ad)

43,749

Brookfield Renewable Trading and Marketing LP

Not Available

SFP

OATT

Various

167

2,093

Citigroup Energy Service Inc

Not Available

SFP

OATT

Various

18,268

121,250

(bv)

121,199

Clines Corners Wind Farm LLC

Not Available

SFP

OATT

Various

72,552

(ae)

578,401

Duran Mesa Wind LLC

Not Available

SFP

OATT

Various

20,059

(af)

193,532

Dynasty Power Inc

Not Available

SFP

OATT

Various

6,307

(ag)

51,455

(bw)

51,452

Grady Wind Energy Center- LLC

Not Available

SFP

OATT

Various

(ah)

118,560

Guzman Power Markets LLC

Not Available

SFP

OATT

Various

13,514

91,416

Imperial Irrigation District Marketing

Not Available

SFP

OATT

Various

4,426

56,494

Macquarie Energy LLC

Not Available

SFP

OATT

Various

6,487

43,009

(bx)

42,993

Mercuria Energy America LLC

Not Available

SFP

OATT

Various

4,888

(ai)

79,706

Morgan Stanley

Not Available

SFP

OATT

Various

2,452

16,354

PacifiCorp

Not Available

SFP

OATT

Various

73,038

375,792

(by)

347

375,445

Pattern New Mexico Wind LLC

Not Available

SFP

OATT

Various

(aj)

834,432

Powerex

Not Available

SFP

OATT

Various

21,744

132,257

Public Service Company of New Mexico

Not Available

SFP

OATT

Various

6,819

42,515

(bz)

42,486

Rainbow Energy Marketing

Not Available

SFP

OATT

Various

19,796

130,688

Red Cloud Wind Farm

Not Available

SFP

OATT

Various

185,814

(ak)

1,371,477

(ca)

2,096

1,373,573

Salt River Project

Not Available

SFP

OATT

Various

14,277

121,049

Shell Energy North America LP

Not Available

SFP

OATT

Various

5,687

35,447

(cb)

217

35,230

Tecolote Wind LLC

Not Available

SFP

OATT

Various

25,302

(al)

520,707

Tenaska Power Services Co.

Not Available

SFP

OATT

Various

7,381

46,097

The Energy Authority Inc.

Not Available

SFP

OATT

Various

5,158

36,545

(cc)

36,533

TransAlta Energy Marketing U.S. Inc.

Not Available

SFP

OATT

Various

22,550

162,177

(cd)

112

162,065

Trico Electric Cooperative Inc.

Not Available

SFP

OATT

Various

4,243

21,442

(ce)

21,429

Tri-State Generation and Transmission Assoc, Inc.

Not Available

SFP

OATT

Various

1,308

8,907

Tucson Electric Power Company

Not Available

SFP

OATT

Various

6,571

59,696

UNIPER GLOBAL COMMODITIES NORTH AMERICA LLC

Not Available

SFP

OATT

Various

4,629

24,825

(cf)

24,822

Vitol Inc.

Not Available

SFP

OATT

Various

200

762

Macquarie Energy LLC

Not Available

OATT

Various

2,728

Mercuria Energy America LLC

Not Available

OATT

Various

382

1,964

PacifiCorp

Not Available

OATT

Various

3,440

23,463

Tenaska Power Services Co.

Not Available

OATT

Various

190

838

(cg)

108

730

ALTOP Energy Trading LLC

Not Available

OATT

Various

1,870

Arizona Public Service Company

Not Available

OATT

Various

3,099

(ch)

10,811

13,910

Avangrid Renewables, LLC

Not Available

OATT

Various

Avista Corporation

Not Available

OATT

Various

Black Hills Power Inc

Not Available

OATT

Various

Brookfield Renewable Trading and Marketing LP

Not Available

OATT

Various

1,282

(ci)

1,243

City of Glendale

Not Available

OATT

Various

Clines Corners Wind Farm LLC

Not Available

OATT

Various

8,449

69,253

ConocoPhillips- Inc.

Not Available

OATT

Various

CP Energy Marketing

Not Available

OATT

Various

DTE Energy Trading Inc

Not Available

OATT

Various

Duran Mesa Wind LLC

Not Available

OATT

Various

686

5,365

(cj)

6,380

11,745

100

Dynasty Power Inc

Not Available

OATT

Various

4,994

34,120

(ck)

34,081

101

EDF Trading North America, LLC

Not Available

OATT

Various

102

Guzman Power Markets LLC

Not Available

OATT

Various

13,444

94,943

(cl)

106

94,837

103

Guzman Renewable Energy Partners

Not Available

OATT

Various

104

Los Angeles Wholesale Marketing

Not Available

OATT

Various

(cm)

105

Macquarie Energy LLC

Not Available

OATT

Various

689

4,217

(cn)

4,167

106

Mag Energy Solutions, Inc

Not Available

OATT

Various

107

Mercuria Energy America LLC

Not Available

OATT

Various

1,284

15,216

(co)

15,194

108

Morgan Stanley

Not Available

OATT

Various

1,140

6,777

(cp)

6,756

109

Nevada Power Company

Not Available

OATT

Various

110

PacifiCorp

Not Available

OATT

Various

250

952

(cq)

540

412

111

Portland General Electric Company

Not Available

OATT

Various

112

Powerex

Not Available

OATT

Various

1,791

11,758

(cr)

123

11,635

113

Public Service Company of Colorado

Not Available

OATT

Various

114

Public Service Company of New Mexico

Not Available

OATT

Various

1,387

10,721

(cs)

10,714

115

Rainbow Energy Marketing

Not Available

OATT

Various

13,287

75,491

(ct)

75,403

116

Salt River Project

Not Available

OATT

Various

2,973

18,433

(cu)

749

17,684

117

Shell Energy North America LP

Not Available

OATT

Various

175

2,938

(cv)

159

2,779

118

Southern California Edison Company

Not Available

OATT

Various

119

TEC Energy

Not Available

OATT

Various

120

Tecolote Wind LLC

Not Available

OATT

Various

639

10,454

121

Tenaska Power Services Co.

Not Available

OATT

Various

7,308

41,943

(cw)

162

41,781

122

The Energy Authority Inc.

Not Available

OATT

Various

4,268

26,987

(cx)

26,959

123

TransAlta Energy Marketing U.S. Inc.

Not Available

OATT

Various

31,271

206,933

(cy)

166

206,767

124

Tri-State Generation and Transmission Assoc, Inc.

Not Available

OATT

Various

345

2,352

(cz)

2,349

125

Tucson Electric Power Company

Not Available

OATT

Various

524

2,935

(da)

317

2,618

126

WestConnect

Not Available

OATT

Various

4,861

10,920

127

Western Area Power Administration (DSW)

Not Available

OATT

Various

128

Yuma Cogeneration Associates

Not Available

OATT

Various

328

11,911

(db)

11,909

129

Arizona Public Service Company

Not Available

(x)

OLF

RS 183

N/A

106,898

130

PacifiCorp

Not Available

(y)

OLF

RS 183

N/A

131

Public Service Company of New Mexico

Not Available

OLF

RS 73

Palo Verde

Four Corners

130

235,231

353,758

132

Yuma Cogeneration Associates

Yuma Cogeneration Assoc.

San Diego Gas and Elect.

OLF

RS 198

Riverside Substation

North Gila Sub

425,548

133

Imperial Irrigation District

Not Available

OATT

N/A

(dc)

13,249

134

Luke AFB Main Field

DOE WAPA Lower

Luke Air Force Base

RS 162

Pinnacle Peak Sub

Luke Substation

(am)

43,362

253

43,615

135

Marine Corps. Air Station

DOE WAPA Lower

Marine Corps Air Station

RS 166

Gila Substation

Marine Corps Air Stn

(an)

19,413

136

NOVO BioPower LLC

Not Available

OATT

N/A

(dd)

679

137

Salt River Project (Schedule F)

Not Available

RS 3

N/A

(ao)

3,911

138

Salt River Project (Schedule Q)

Pinnacle Peak

Ocotillo 230

RS 3

Pinnacle Peak

Ocotillo 230

(de)

233,996

139

Unit B Irrigation and Drainage District

Not Available

RS 181

Gila Substation

District Customer

(ap)

135

140

Yuma Mesa Irrigation and Drainage District

DOE WAPA Lower

Yuma-Mesa Irrigation Dist

RS 31

Gila Substation

Yuma Mesa Load

(aq)

1,125

141

Navajo Transitional Energy Company, LLC

Not Available

RS 291

N/A

114,247

(df)

7,776

122,023

142

Other

Not Available

(dg)

3,463,036

TOTAL

2,580

10,264,011

27,734,128

188,510

5,251,916

33,174,554

Name of Respondent:

Arizona Public Service Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

08/24/2023

Year/Period of Report

End of:

2023

FOOTNOTE DATA

(a) Concept: StatisticalClassificationCode

Network Integration Transmission Service

(b) Concept: StatisticalClassificationCode

Network Integration Transmission Service

(d) Concept: StatisticalClassificationCode

Network Integration Transmission Service

(e) Concept: StatisticalClassificationCode

Network Integration Transmission Service

(f) Concept: StatisticalClassificationCode

Network Integration Transmission Service

(g) Concept: StatisticalClassificationCode

Firm Transmission Service Contract for 167MW, expires on 5/1/2047

(h) Concept: StatisticalClassificationCode

Firm Transmission Service Contracts for 72MW and 58MW, expires on 1/1/2048 and 5/1/2047, respectively

(i) Concept: StatisticalClassificationCode

Firm Transmission Service Contract for 25MW, expires on 12/1/2027

(j) Concept: StatisticalClassificationCode

Firm Transmission Service Contract for 120MW, expires 11/15/2051

(k) Concept: StatisticalClassificationCode

Firm Transmission Service Contract for 51MW, expires 12/1/2051

(l) Concept: StatisticalClassificationCode

Firm Transmission Service Contract for 298MW, expires 1/1/2028

(m) Concept: StatisticalClassificationCode

Firm Transmission Service Contract for 90MW, expires 5/31/2025

(n) Concept: StatisticalClassificationCode

Firm Transmission Service Contract for 200MW, expires 4/1/2049

(o) Concept: StatisticalClassificationCode

Firm Transmission Service Contract for 10MW and 4MW, expires 1/1/2028 and 10/19/2031, respectively

(p) Concept: StatisticalClassificationCode

Firm Transmission Service Contract for 100MW, expires 6/1/2052

(q) Concept: StatisticalClassificationCode

Firm Transmission Service Contract for 22MW, 65MW and 10MW, expires 1/1/2028 and 1/1/2029 respectively

(r) Concept: StatisticalClassificationCode

Firm Transmission Service Contract for 54MW, 9MW, 64MW and 407MW, expires 1/1/2025, 1/1/2027 and 1/1/2024 respectively

(s) Concept: StatisticalClassificationCode

Firm Transmission Service Contract for 1MW, expires on 5/15/2031

(t) Concept: StatisticalClassificationCode

Firm Transmission Service Contract for 132MW, expiring 12/1/2051

(u) Concept: StatisticalClassificationCode

Firm Transmission Service Contract for 100MW, expires 10/1/2023

(v) Concept: StatisticalClassificationCode

Firm Transmission Service Contract for 2MW, expiring 9/1/2027

(w) Concept: StatisticalClassificationCode

Firm Transmission Service Contract for 110MW, expriring 8/1/2026

(x) Concept: StatisticalClassificationCode

Exchange agreement pursuant to Pre888 contract

(y) Concept: StatisticalClassificationCode

Exchange agreement pursuant to Pre888 contract

(z) Concept: BillingDemand

Service to Arizona Public Service Company pursuant to Part III of the OATT

(aa) Concept: BillingDemand

Service to Arizona Public Service Company pursuant to Part III of the OATT

(ab) Concept: BillingDemand

Service to Arizona Public Service Company pursuant to Part III of the OATT

(ac) Concept: DemandChargesRevenueTransmissionOfElectricityForOthers

Resale Activity

(ad) Concept: DemandChargesRevenueTransmissionOfElectricityForOthers

Resale Activity

(ae) Concept: DemandChargesRevenueTransmissionOfElectricityForOthers

Resale Activity

(af) Concept: DemandChargesRevenueTransmissionOfElectricityForOthers

Resale Activity

(ag) Concept: DemandChargesRevenueTransmissionOfElectricityForOthers

Resale Activity

(ah) Concept: DemandChargesRevenueTransmissionOfElectricityForOthers

Resale Activity

(ai) Concept: DemandChargesRevenueTransmissionOfElectricityForOthers

Resale Activity

(aj) Concept: DemandChargesRevenueTransmissionOfElectricityForOthers

Resale Activity

(ak) Concept: DemandChargesRevenueTransmissionOfElectricityForOthers

Resale Activity

(al) Concept: DemandChargesRevenueTransmissionOfElectricityForOthers

Resale Activity

(am) Concept: DemandChargesRevenueTransmissionOfElectricityForOthers

Part of APS NITS load - recovery of transmission cost contract

(an) Concept: DemandChargesRevenueTransmissionOfElectricityForOthers

Part of APS NITS load - recovery of transmission cost contract

(ao) Concept: DemandChargesRevenueTransmissionOfElectricityForOthers

Part of APS NITS load - recovery of transmission cost contract

(ap) Concept: DemandChargesRevenueTransmissionOfElectricityForOthers

Part of APS NITS load - recovery of transmission cost contract

(aq) Concept: DemandChargesRevenueTransmissionOfElectricityForOthers

Part of APS NITS load - recovery of transmission cost contract

(ar) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(as) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Direct Assignment and Unreserved Use Credit

(at) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Direct Assignment and Unreserved Use Credit

(au) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(av) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Direct Assignment, Unreserved Use Penalty and Unreserved Use Credit

(aw) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Direct Assignment, Unreserved Use Penalty and Unreserved Use Credit

(ax) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Penalty and Unreserved Use Credit

(ay) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Penalty

(az) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(ba) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(bb) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(bc) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(bd) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(be) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Penalty

(bf) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(bg) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(bh) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(bi) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Direct Assignment and Unreserved Use Credit

(bj) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(bk) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(bl) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(bm) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(bn) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(bo) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(bp) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(bq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(br) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(bs) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(bt) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(bu) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(bv) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(bw) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(bx) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(by) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(bz) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(ca) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Penalty and Unreserved Use Credit

(cb) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(cc) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(cd) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(ce) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(cf) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(cg) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(ch) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Penalty and Unreserved Use Credit

(ci) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(cj) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Penalty and Unreserved Use Credit

(ck) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(cl) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(cm) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(cn) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(co) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(cp) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(cq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(cr) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(cs) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(ct) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(cu) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(cv) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(cw) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(cx) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(cy) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(cz) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(da) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(db) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Unreserved Use Credit

(dc) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Direct Assignment Charges

(dd) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Direct Assignment Charges

(de) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Direct Assignment Charges

(df) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

BA Services Administrative Fees

(dg) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

FERC Transmission rate true up, change in estimate, and timing difference

Schedules	Pages
Comparative Balance Sheet	110-113
Statement of Income	114-117
Statement of Retained Earnings	118-119
Statement of Cash Flows	120-121
Notes to Financial Statements	122-123

TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public authorities, qualifying facilities, and others for the quarter. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company, abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided transmission service for the quarter reported. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered. Enter ""TOTAL"" in column (a) as the last line. Footnote entries and provide explanations following all required data.
			TRANSFER OF ENERGY		EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
Line No.	NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers Name of Company or Public Authority (Footnote Affiliations) (a)	StatisticalClassificationCode Statistical Classification (b)	TransmissionOfElectricityByOthersEnergyReceived MegaWatt Hours Received (c)	TransmissionOfElectricityByOthersEnergyDelivered MegaWatt Hours Delivered (d)	DemandChargesTransmissionOfElectricityByOthers Demand Charges ($) (e)	EnergyChargesTransmissionOfElectricityByOthers Energy Charges ($) (f)	OtherChargesTransmissionOfElectricityByOthers Other Charges ($) (g)	ChargesForTransmissionOfElectricityByOthers Total Cost of Transmission ($) (h)
1	(a) Arizona Public Service Co	LFP			22,639			22,639
2	Bureau of Indian Affairs	(b) OLF			38,400			38,400
3	Department of Energy	(c) OS	4,169	4,169		230,262	(o) 102,546	127,716
4	Department of Energy	NF	617	617	4,508	267		4,241
5	Department of Energy	FNS	89,486	89,486	326,066	55,551	(p) 139,103	520,720
6	Department of Energy	FNS	255,188	255,188	1,324,942	371,189	(q) 81,356	1,777,487
7	Department of Energy	(d) LFP	68,717	68,717		109,818	(r) 3,522	106,296
8	Department of Energy	(e) LFP	174,732	174,732	2,438,098	342,188	(s) 22,013	2,802,299
9	Department of Energy	(f) OS			22,992		(t) 52	23,044
10	Department of Energy	SFP	208	208	760	19		779
11	Electric District # 3	LFP	625	625	21,004		(u) 5,588	15,416
12	Electric District # 4	(g) OLF	496	496	14,931		(v) 991	13,940
13	Salt River Project	(h) FNS	7,089	7,089	46,357	11,244	(w) 14,093	43,508
14	Salt River Project	(i) OLF	69,109	69,109	434,359	101,727	(x) 101,727	434,359
15	Salt River Project	(j) LFP	34,560	34,560	534,477	56,050	(y) 144,735	735,262
16	Salt River Project	FNS	102,174	102,174	756,104	165,855	(z) 87,543	(af) 834,416
17	Salt River Project	(k) OLF	23,333	23,333	62,170	37,570	(aa) 37,570	62,170
18	Salt River Project	(l) OS	361,481	361,481		123,573	(ab) 90,177	213,750
19	Salt River Project	FNS	87,154	87,154	575,969	89,562		665,531
20	Salt River Project	OS	4,085	4,085		51,720	(ac) 51,720
21	Southern California Edison	(m) LFP	27,768	27,768	49,747		(ad) 1,191	50,938
22	Southwest Transmission Cooperative Inc.	SFP	182	182	4,022			4,022
23	Tucson Electric Power	NF	289	289	9,023			9,023
24	SRP Misc Accounts Receivable	OS	306	306	886	981		1,867
25	Navopache Electric Cooperative	(n) OS			80,688			80,688
26	Navopache Electric Cooperative	OS	5,510	5,510		222,033	(ae) 117,846	104,187
	TOTAL		1,317,278	1,317,278	6,759,126	1,969,609	44,519	8,684,216

Deprec, Depl and Amort of Elec Plant (403,403.1,404,and 405) (except Amortization of Acquisition Adjustments)
Report the year to date amounts of depreciation expense, asset retirement cost depreciation, depletion and amortization, except amortization of acquisition adjustments for the accounts indicated and classified according to the plant functional groups described.
Line No.	FunctionalClassificationAxis Functional Classification (a)	DepreciationExpenseExcludingAmortizationOfAcquisitionAdjustments Depreciation Expense (Account 403) (b)	DepreciationExpenseForAssetRetirementCostsExcludingAmortizationgOfAcquisitionAdjustments Depreciation Expense for Asset Retirement Costs (Account 403.1) (c)	AmortizationOfLimitedTermPlantOrProperty Amortization of Limited Term Electric Plant (Account 404) (d)	AmortizationOfOtherElectricPlant Amortization of Other Electric Plant (Acc 405) (e)	DepreciationAndAmortization Total (f)
1	Intangible Plant			45,173,417		45,173,417
2	Steam Production Plant	54,081,237	5,402,215	5,919		59,489,371
3	Nuclear Production Plant	6,842,355	376,144	2,055,518		8,521,729
4	Hydraulic Production Plant-Conventional
5	Hydraulic Production Plant-Pumped Storage
6	Other Production Plant	72,967,196	503,241			73,470,437
7	Transmission Plant	33,435,400		4,249,773		37,685,173
8	Distribution Plant	98,380,249		647,063		99,027,312
9	General Plant	34,094,197		7,834,385		41,928,582
10	Common Plant-Electric
11	TOTAL	299,800,634	5,529,312	59,966,075		365,296,021

AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS
The respondent shall report below the details called for concerning amounts it recorded in Account 555, Purchase Power, and Account 447, Sales for Resale, for items shown on ISO/RTO Settlement Statements. Transactions should be separately netted for each ISO/RTO administered energy market for purposes of determining whether an entity is a net seller or purchaser in a given hour. Net megawatt hours are to be used as the basis for determining whether a net purchase or sale has occurred. In each monthly reporting period, the hourly sale and purchase net amounts are to be aggregated and separately reported in Account 447, Sales for Resale, or Account 555, Purchased Power, respectively.
Line No.	Description of Item(s) (a)	Balance at End of Quarter 1 (b)	Balance at End of Quarter 2 (c)	Balance at End of Quarter 3 (d)	Balance at End of Year (e)
1	Energy
2	Net Purchases (Account 555)	1,507,230	9,613,943
2.1	Net Purchases (Account 555.1)
3	Net Sales (Account 447)	35,726,158	46,469,146
4	Transmission Rights
5	Ancillary Services
6	Other Items (list separately)
7	CAISO Non Purchases (Account 555)	4,191,214	9,440,372
46	TOTAL	33,042,174	27,414,831

Monthly Peak Loads and Energy Output
Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the required information for each non- integrated system. Report in column (b) by month the system’s output in Megawatt hours for each month. Report in column (c) by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales. Report in column (d) by month the system’s monthly maximum megawatt load (60 minute integration) associated with the system. Report in column (e) and (f) the specified information for each monthly peak load reported in column (d).
Line No.	MonthAxis Month (a)	Total Monthly Energy (MWH) (b)	Monthly Non-Requirements Sales for Resale & Associated Losses (c)	MonthlyPeakLoad Monthly Peak Megawatts (See Instr. 4) (d)	DayOfMonthlyPeak Monthly Peak Day of Month (e)	HourOfMonthlyPeak Monthly Peak Hour (f)
	NAME OF SYSTEM: Arizona Public Service Company
1	January	2,770,932	280,005	4,748	24	8
2	February	2,497,488	400,507	4,612	16	8
3	March	2,552,650	431,292	4,442	2	8
4	Total for Quarter 1	7,821,070	1,111,804
5	April	2,479,708	238,117	4,927	29	18
6	May	2,812,677	197,235	5,485	17	18
7	June	3,498,055	562,763	6,542	30	18
8	Total for Quarter 2	8,790,440	998,115
9	July
10	August
11	September
12	Total for Quarter 3
41	Total

FERC FINANCIAL REPORT
FERC FORM No. 1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report

INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-Q

GENERAL INFORMATION

Purpose

Who Must Submit

What and Where to Submit

When to Submit

Where to Send Comments on Public Reporting Burden.

GENERAL INSTRUCTIONS

EXCERPTS FROM THE LAW

GENERAL PENALTIES




FERC FINANCIAL REPORT FERC FORM No. 1: Annual Report of Major Electric Utilities, Licensees and Others and Supplemental Form 3-Q: Quarterly Financial Report

These reports are mandatory under the Federal Power Act, Sections 3, 4(a), 304 and 309, and 18 CFR 141.1 and 141.400. Failure to report may result in criminal fines, civil penalties and other sanctions as provided by law. The Federal Energy Regulatory Commission does not consider these reports to be of confidential nature

List of Schedules
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line No.	Title of Schedule (a)	Reference Page No. (b)	Remarks (c)
	ScheduleIdentificationAbstract Identification	1
	ScheduleListOfSchedulesAbstract List of Schedules (Electric Utility)	2
1	ScheduleImportantChangesDuringTheQuarterYearAbstract Important Changes During the Quarter	108
2	ScheduleComparativeBalanceSheetAbstract Comparative Balance Sheet	110
3	ScheduleStatementOfIncomeAbstract Statement of Income for the Quarter	114
4	ScheduleRetainedEarningsAbstract Statement of Retained Earnings for the Quarter	118
5	ScheduleStatementOfCashFlowsAbstract Statement of Cash Flows	120
6	ScheduleNotesToFinancialStatementsAbstract Notes to Financial Statements	122
7	ScheduleStatementOfAccumulatedOtherComprehensiveIncomeAndHedgingActivitiesAbstract Statement of Accum Comp Income, Comp Income, and Hedging Activities	122a
8	ScheduleSummaryOfUtilityPlantAndAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep	200
9	ScheduleElectricPlantInServiceAndAccumulatedProvisionForDepreciationByFunctionAbstract Electric Plant In Service and Accum Provision For Depr by Function	208
10	ScheduleTransmissionServiceAndGenerationInterconnectionStudyCostsAbstract Transmission Service and Generation Interconnection Study Costs	231
11	ScheduleOtherRegulatoryAssetsAbstract Other Regulatory Assets	232
12	ScheduleOtherRegulatoryLiabilitiesAbstract Other Regulatory Liabilities	278
13	ScheduleElectricOperatingRevenuesAbstract Elec Operating Revenues (Individual Schedule Lines 300-301)	300
14	ScheduleRegionalTransmissionServiceRevenuesAbstract Regional Transmission Service Revenues (Account 457.1)	302	None
15	ScheduleElectricProductionOtherPowerTransmissionRegionalExpensesAbstract Electric Prod, Other Power Supply Exp, Trans and Distrib Exp	324
16	ScheduleElectricCustomerAccountServiceSalesAdministrativeAndGeneralExpensesAbstract Electric Customer Accts, Service, Sales, Admin and General Expenses	325
17	ScheduleTransmissionOfElectricityForOthersAbstract Transmission of Electricity for Others	328
18	ScheduleTransmissionOfElectricityByIsoOrRtoAbstract Transmission of Electricity by ISO/RTOs	331	None
19	ScheduleTransmissionOfElectricityByOthersAbstract Transmission of Electricity by Others	332
20	ScheduleDepreciationDepletionAndAmortizationsAbstract Deprec, Depl and Amort of Elec Plant (403,403.1,404,and 405) (except Amortization of Acquisition Adjustments)	338
21	ScheduleAmountsIncludedInIsoOrRtoSettlementAbstract Amounts Included in ISO/RTO Settlement Statements	397
22	ScheduleMonthlyPeaksAndOutputAbstract Monthly Peak Loads and Energy Output	399
23	ScheduleMonthlyTransmissionSystemPeakLoadAbstract Monthly Transmission System Peak Load	400
24	ScheduleMonthlyIsoOrRtoTransmissionSystemPeakLoadAbstract Monthly ISO/RTO Transmission System Peak Load	400a	None

TRANSMISSION OF ELECTRICITY BY ISO/RTOs
Report in Column (a) the Transmission Owner receiving revenue for the transmission of electricity by the ISO/RTO. Use a separate line of data for each distinct type of transmission service involving the entities listed in Column (a). In Column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO – Firm Network Service for Others, FNS – Firm Network Transmission Service for Self, LFP – Long-Term Firm Point-to-Point Transmission Service, OLF – Other Long-Term Firm Transmission Service, SFP – Short-Term Firm Point-to-Point Transmission Reservation, NF – Non-Firm Transmission Service, OS – Other Transmission Service and AD- Out-of-Period Adjustments. Use this code for any accounting adjustments or “true-ups” for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes. In column (c) identify the FERC Rate Schedule or tariff Number, on separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (b) was provided. In column (d) report the revenue amounts as shown on bills or vouchers. Report in column (e) the total revenues distributed to the entity listed in column (a).
Line No.	Payment Received by (Transmission Owner Name) (a)	Statistical Classification (b)	FERC Rate Schedule or Tariff Number (c)	Total Revenue by Rate Schedule or Tariff (d)	Total Revenue (e)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
40	TOTAL

MONTHLY TRANSMISSION SYSTEM PEAK LOAD
Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system. Report on Column (b) by month the transmission system's peak load. Report on Columns (c ) and (d) the specified information for each monthly transmission - system peak load reported on Column (b). Report on Columns (e) through (j) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for the definition of each statistical classification.
Line No.	Month (a)	Monthly Peak MW - Total (b)	Day of Monthly Peak (c)	Hour of Monthly Peak (d)	Firm Network Service for Self (e)	Firm Network Service for Others (f)	Long-Term Firm Point-to-point Reservations (g)	Other Long-Term Firm Service (h)	Short-Term Firm Point-to-point Reservation (i)	Other Service (j)
	NAME OF SYSTEM: Arizona Public Service Company
1	January	7,312	24	8	4,802	158	2,171	181
2	February	7,194	16	8	4,679	163	2,171	181
3	March	6,876	2	8	4,379	145	2,171	181
4	Total for Quarter 1				13,860	466	6,513	543
5	April	7,327	29	18	4,799	176	2,171	181
6	May	7,885	17	18	5,338	195	2,171	181
7	June	9,073	30	18	6,388	233	2,271	181
8	Total for Quarter 2				16,525	604	6,613	543
9	July
10	August
11	September
12	Total for Quarter 3
13	October
14	November
15	December
16	Total for Quarter 4
17	Total				30,385	1,070	13,126	1,086

Monthly ISO/RTO Transmission System Peak Load
Report the monthly peak load on the respondent's transmission system. If the Respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system. Report on Column (b) by month the transmission system's peak load. Report on Column (c) and (d) the specified information for each monthly transmission - system peak load reported on Column (b). Report on Columns (e) through (i) by month the system’s transmission usage by classification. Amounts reported as Through and Out Service in Column (g) are to be excluded from those amounts reported in Columns (e) and (f). Amounts reported in Column (j) for Total Usage is the sum of Columns (h) and (i).
Line No.	Month (a)	Monthly Peak MW - Total (b)	Day of Monthly Peak (c)	Hour of Monthly Peak (d)	Import into ISO/RTO (e)	Exports from ISO/RTO (f)	Through and Out Service (g)	Network Service Usage (h)	Point-to-Point Service Usage (i)	Total Usage (j)
	NAME OF SYSTEM: Arizona Public Service Company
1	January
2	February
3	March
4	Total for Quarter 1				0	0	0	0	0	0
5	April
6	May
7	June
8	Total for Quarter 2				0	0	0	0	0	0
9	July
10	August
11	September
12	Total for Quarter 3				0	0	0	0	0	0
13	October
14	November
15	December
16	Total for Quarter 4				0	0	0	0	0	0
17	Total Year to Date/Year				0	0	0	0	0	0

FERC FINANCIAL REPORT FERC FORM No. 1: Annual Report of Major Electric Utilities, Licensees and Others and Supplemental Form 3-Q: Quarterly Financial Report

INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-Q

GENERAL INFORMATION

Purpose

Who Must Submit

What and Where to Submit

When to Submit

Where to Send Comments on Public Reporting Burden.

GENERAL INSTRUCTIONS

EXCERPTS FROM THE LAW

GENERAL PENALTIES

FERC FINANCIAL REPORT
FERC FORM No. 1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report