What changed in this filing

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Item 8. Financial Statements and Supplementary Data

2023-02-27 compared with 2022-02-25 · 592 added, 462 removed, 2534 unchanged (29% of the section changed)

18 unchanged sentences

Summary of Significant Accounting Policies

New Accounting Standards

Regulatory Matters

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• We evaluated the Company’s disclosures related to regulatory accounting, specifically the impact of rate regulation on the financial statements, including the balances recorded and regulatory developments.

• We read relevant regulatory rate orders issued by the ACC for APS and other public utilities in Arizona, regulatory statutes, interpretations, procedural memorandums, filings made by interveners, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the ACC’s treatment of similar costs under similar circumstances.

• We read relevant regulatory rate orders issued by the ACC for APS and other public utilities in Arizona, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the ACC’s treatment of similar costs under similar circumstances.

We evaluated the external information and compared to management’s recorded regulatory assets and liabilities for completeness.

◦ We observed the ACC open meetings for the APS 2019 Retail Rate Case.

We read the ACC approved decision regarding the 2019 Retail Rate Case.

◦ We obtained the Company’s internally prepared memo regarding impacts of the ACC decision to rates and recorded balances.

◦ We tested that new rates were implemented within the system effective December 1, 2021.

• We read APS’s 2022 rate application submitted to the ACC on October 28, 2022.

• We evaluated management’s assessment of the probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities based on applicable regulatory orders or precedents set by the ACC under similar circumstances.

For certain regulatory assets or liabilities where management’s assessment is based on precedents established by the ACC under similar circumstances and not specifically addressed in a regulatory order, we also obtained a letter from internal legal counsel regarding their assessment.

We read the minutes of the Boards of Directors of the Company for discussions of changes in legal, regulatory, or business factors which could impact management’s assessment.

We read the minutes of the Boards of Directors

of the Company for discussions of changes in legal, regulatory, or business factors which could impact management’s assessment.

• We evaluated management’s assessment that the SCR plant investment is not probable of a partial disallowance and that the SCR deferred costs are probable of recovery.

We read the Notice of Direct Appeal filed with the Arizona Court of Appeals and Petition for Special Action filed with the Arizona Supreme Court, reviewed the Company's internally prepared memo, and reviewed a legal letter from the Company's external counsel to assess the likelihood of recovery in future rates or of a future reduction in rates based on the ACC decision.

We read the Notice of Direct Appeal filed with the Arizona Court of Appeals and Petition for Special Action filed with the Arizona Supreme Court, read APS’s opening brief submitted to the Arizona Court of Appeals, read the ACC’s Answering Brief, read the Intervenors’ briefs, read APS’s reply brief, and observed the Appeal Oral Arguments, reviewed the Company’s internally prepared memo, and reviewed a legal letter from the Company’s external counsel to assess the likelihood of recovery in future rates or of a future reduction in rates based on the ACC decision.

/s/ Deloitte & Touche LLP

Phoenix, Arizona

Tempe, Arizona

February 27, 2023

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Assets from risk management activities (Note 15)

87,835 63,481

Deferred fuel and purchased power regulatory asset (Note 3)

5 unchanged sentences

INVESTMENTS AND OTHER ASSETS

Nuclear decommissioning trust (Notes 13 and 19)

Nuclear decommissioning trusts (Notes 12 and 18)

1,073,410 1,294,757

2 unchanged sentences

Assets from risk management activities (Note 15)

44,394 46,908

Other assets 125,672 97,884

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Current maturities of long-term debt (Note 6)

50,685 150,000

Customer deposits 41,769 42,293

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116,286 152,865

Liabilities from risk management activities (Note 16)

Customer advances 422,103 257,151

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Treasury stock at cost;

87,608 shares at end of 2021 and 72,006 shares at end of 2020

73,613 and 87,608 shares at respective dates

( 5,005 ) ( 6,401 )

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Deferred investment tax credit ( 5,893 ) ( 4,802 ) ( 5,096 )

Change in derivative instruments fair value 777 — —

Stock compensation 15,942 18,460 18,292

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Balance, December 31, 2019

112,540,126 $ 2,659,561 ( 103,546 ) $ ( 9,427 ) $ 2,837,610 $ ( 57,096 ) $ 122,540 $ 5,553,188

Net income — — 550,559 — 19,493 570,052

Other comprehensive loss

— — — ( 5,700 ) — ( 5,700 )

Dividends on common stock ($ 3.23 per share)

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Balance, December 31, 2020

112,760,051 2,677,482 ( 72,006 ) ( 6,289 ) 3,025,106 ( 62,796 ) 119,290 5,752,793

Net income — — 618,720 — 17,224 635,944

Other comprehensive loss — — — ( 5,700 ) — ( 5,700 )

Other comprehensive income

— — — 7,935 — 7,935

Dividends on common stock ($ 3.36 per share)

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Capital activities by noncontrolling interests — — — — ( 21,255 ) ( 21,255 )

Other — — 1 — 1 2

Balance, December 31, 2021

113,014,528 2,702,743 ( 87,608 ) ( 6,401 ) 3,264,719 ( 54,861 ) 115,260 6,021,460

Net income — — 483,602 — 17,224 500,826

Other comprehensive income

— — — 23,426 — 23,426

Dividends on common stock ($ 3.43 per share)

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Balance, December 31, 2022

113,247,189 $ 2,724,740 ( 73,613 ) $ ( 5,005 ) $ 3,360,347 $ ( 31,435 ) $ 111,229 $ 6,159,876

(a) Primarily represents shares of common stock withheld from certain stock awards for tax purposes.

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• We read relevant regulatory rate orders issued by the ACC for APS and other public utilities in Arizona, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the ACC’s treatment of similar costs under similar circumstances.

We evaluated the external information and compared to management’s recorded regulatory assets and liabilities for completeness.

◦ We observed the ACC open meetings for the APS 2019 Retail Rate Case.

We read the ACC approved decision regarding the 2019 Retail Rate Case.

◦ We obtained the Company’s internally prepared memo regarding impacts of the ACC decision to rates and recorded balances.

◦ We tested that new rates were implemented within the system effective December 1, 2021.

• We read the Company’s 2022 rate application submitted to the ACC on October 28, 2022.

We read the minutes of the Boards of Directors of the Company for discussions of changes in legal, regulatory, or business factors which could impact management’s assessment.

We read the minutes of the Boards of Directors

of the Company for discussions of changes in legal, regulatory, or business factors which could impact management’s assessment.

• We evaluated management’s assessment that the SCR plant investment is not probable of a partial disallowance and that the SCR deferred costs are probable of recovery.

We read the Notice of Direct Appeal filed with the Arizona Court of Appeals and Petition for Special Action filed with the Arizona Supreme Court, reviewed the Company’s internally prepared memo, and reviewed a legal letter from the Company’s external counsel to assess the likelihood of recovery in future rates or of a future reduction in rates based on the ACC decision.

We read the Notice of Direct Appeal filed with the Arizona Court of Appeals and Petition for Special Action filed with the Arizona Supreme Court, read the Company’s opening brief submitted to the Arizona Court of Appeals, read the ACC’s Answering Brief, read the Intervenors’ briefs, read the Company’s reply brief, and observed the Appeal Oral Arguments, reviewed the Company’s internally prepared memo, and reviewed a legal letter from the Company’s external counsel to assess the likelihood of recovery in future rates or of a future reduction in rates based on the ACC decision.

/s/ Deloitte & Touche LLP

Phoenix, Arizona

Tempe, Arizona

February 27, 2023

72 unchanged sentences

INVESTMENTS AND OTHER ASSETS

Nuclear decommissioning trust (Notes 13 and 19)

Nuclear decommissioning trusts (Notes 12 and 18)

1,073,410 1,294,757

2 unchanged sentences

Assets from risk management activities (Note 15)

44,394 46,908

Other assets 43,344 42,440

10 unchanged sentences

Assets from risk management activities (Note 15)

87,704 63,481

Deferred fuel and purchased power regulatory asset (Note 3)

34 unchanged sentences

Short-term borrowings (Note 5)

325,000 278,700

Accounts payable 417,732 389,365

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108,068 138,328

Liabilities from risk management activities (Note 16)

Customer advances 422,103 257,151

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Balance, December 31, 2019

71,264,947 $ 178,162 $ 2,721,696 $ 3,011,927 $ ( 35,522 ) $ 122,540 $ 5,998,803

Equity infusion from Pinnacle West — 150,000 — — — 150,000

Net income — — 568,028 — 19,493 587,521

Other comprehensive loss

— — — ( 5,396 ) — ( 5,396 )

Dividends on common stock — — ( 363,000 ) — — ( 363,000 )

1 unchanged sentence

Balance, December 31, 2020

71,264,947 178,162 2,871,696 3,216,955 ( 40,918 ) 119,290 6,345,185

Equity infusion from Pinnacle West — 150,000 — — — 150,000

Net income — — 632,279 — 17,224 649,503

Other comprehensive loss — — — ( 5,396 ) — ( 5,396 )

Other comprehensive income

— — — 6,038 — 6,038

Dividends on common stock — — ( 379,000 ) — — ( 379,000 )

Capital activities by noncontrolling interests — — — — ( 21,255 ) ( 21,255 )

Other — — 1 — 1 2

Balance, December 31, 2021

71,264,947 178,162 3,021,696 3,470,235 ( 34,880 ) 115,260 6,750,473

Equity infusion from Pinnacle West — 150,000 — — — 150,000

1 unchanged sentence

Other comprehensive income

— — — 19,284 — 19,284

Dividends on common stock — — ( 387,700 ) — — ( 387,700 )

Capital activities by noncontrolling interests — — — — ( 21,255 ) ( 21,255 )

Other — — 1 — 1 2

Balance, December 31, 2022

71,264,947 $ 178,162 $ 3,171,696 $ 3,607,464 $ ( 15,596 ) $ 111,229 $ 7,052,955

The accompanying notes are an integral part of the financial statements.

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We net these book-outs, which reduces both wholesale revenues and fuel and purchased power costs.

Some of our cost recovery mechanisms are alternative revenue programs.

Certain cost recovery mechanisms may qualify as alternative revenue programs.

For alternative revenue programs that meet specified accounting criteria, we recognize revenues when the specific events permitting billing of the additional revenues have been completed.

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On September 21, 2021, it was further extended until March 21, 2022.

The order provides 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 has 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 has left all other aspects of the AFUDC formula composite rate calculation unchanged.

This change impacts the AFUDC composite rate in 2020 and 2021 but does not impact prior years.

Furthermore, the change in the composite rate calculation does not impact our accounting treatment for these costs.

The order provided a simplified approach that companies may have elected to implement in order to minimize the significant distorted effect on the AFUDC formula which resulted 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 2020 and 2021 but did not impact prior years or 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.

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APS values materials, supplies and fossil fuel inventory using a weighted-average cost method.

APS materials, supplies and fossil fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered.

APS materials, supplies and fossil fuel inventories are carried at the lower of weighted-average cost or net realizable value, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered.

Fair Value Measurements

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We manage risks associated with market volatility by utilizing various physical and financial 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.

As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and natural gas as well as interest rate risk.

The changes in market value of such contracts have a high correlation to price changes in the hedged transactions.

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$ 0.001 per kWh of nuclear generation through May 2014, at which point the DOE reduced the fee to zero.

In accordance with a settlement agreement with the DOE in August 2014 for interim storage, we now accrue a receivable and an offsetting regulatory liability through the settlement period ending December of 2022.

In accordance with a settlement agreement with the DOE in August 2014 for interim storage, we accrued a receivable and an offsetting regulatory liability through the settlement period which ended December of 2022.

See Note 10 for information on spent nuclear fuel disposal costs.

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2022 2021 2020

Cash paid (received) during the period for:

Cash paid during the period for:

Income taxes, net of refunds $ 95,985 $ 19,783 $ 41,176

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(a) Residential revenues for the year ended December 31, 2020, reflect a $ 24 million reduction related to the Arizona Attorney General matter.

See Note 10 .

Retail Electric Revenue.

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Revenues from contracts with customers also include wholesale and transmission activities.

Our revenues from contracts with customers for the year ended December 31, 2021, 2020 and 2019 were $ 3,760 million, $ 3,533 million.

and $ 3,415 million, respectively.

Our revenues from contracts with customers for the year ended December 31, 2022, 2021 and 2020 were $ 4,302 million, $ 3,760 million, and $ 3,533 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 year ended December 31, 2022, 2021 and 2020, our revenues that do not qualify as revenue from contracts with customers were $ 22 million, $ 44 million and $ 54 million, respectively.

This relates primarily to certain regulatory cost recovery mechanisms that are considered alternative revenue programs.

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.

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Allowance for Doubtful Accounts

On March 13, 2020, due to the COVID-19 pandemic we voluntarily suspended disconnections of customers for nonpayment.

The suspension of customer disconnections was extended from March 13, 2020, through December 31, 2020.

The suspension of disconnection of customers for nonpayment ended on January 1, 2021, and certain customers with past due balances were placed on eight-month payment arrangements.

During this time, our disconnection policies were also impacted by the Summer Disconnection Moratorium.

These circumstances and the on-going COVID-19 pandemic continue to impact our allowance for doubtful accounts including our write-off factor.

We continue to monitor the impacts of COVID-19, our disconnection policies, summer moratorium, payment arrangements, among other considerations impacting our estimated write-off factor and allowance for doubtful accounts.

See Note 1 for our accounting policies on allowance for doubtful accounts.

See Note 4 for additional discussion on the COVID-19 pandemic and the Summer Disconnection Moratorium.

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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5 unchanged sentences

Allowance for doubtful accounts, balance at end of period $ 23,778 $ 25,354 $ 19,782

New Accounting Standards

ASU 2021-05, Leases:

Certain Leases with Variable Lease Payments

In July 2021, a new accounting standard was issued that amends the lease accounting guidance.

The amended guidance will require lessors to account for certain lease transactions, that contain variable lease payments, as operating leases.

The amendments are intended to eliminate the recognition of any day-one loss associated with certain sales-type and direct-financing lease transactions.

The changes do not impact lessee accounting.

The standard may be adopted using either a prospective or modified retrospective approach.

We adopted this standard on January 1, 2022, using a prospective approach.

The adoption of this standard did not impact our financial statements.

Regulatory Matters

COVID-19 Pandemic

During 2020 and 2021, APS implemented several programs and initiatives to help our customers deal with the economic and other impacts of the COVID-19 pandemic, including but not limited to the following:

• Suspension of Disconnections;

Waiver of Late Payment Fees .

APS voluntarily suspended disconnections of customers for nonpayment beginning March 13, 2020, until December 31, 2020.

The suspension of disconnection of customers for nonpayment ended on January 1, 2021, and customers with past due balances of $ 75 or greater as of that date were automatically placed on eight-month payment arrangements.

APS voluntarily began waiving late payment fees of its customers on March 13, 2020 and is continuing to waive late payment fees.

APS has experienced and is continuing to experience an increase in bad debt expense associated with the COVID-19 pandemic, the Summer Disconnection Moratorium (defined below) and the related write-offs of customer delinquent accounts.

• COVID-19 Emergency Relief Package.

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.

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 and collect costs through base rates,

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

▪ maintain as inactive the Tax Expense Adjustor Mechanism,

▪ maintain the Transmission Cost Adjustment mechanism,

▪ modify the performance incentive in the DSMAC, and

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

• COVID Customer Support Fund .

In 2020, APS spent more than $ 15 million to assist customers and local non-profits and community organizations to help with the impact of the COVID-19 pandemic, with $ 12.4 million of these dollars directly committed to bill assistance programs (the “COVID Customer Support Fund”).

The COVID Customer Support Fund was comprised of (i) approximately $ 8.8 million in funds that are not recoverable through rates, and (ii) an additional $ 3.6 million in bill credits for limited income customers ordered by the ACC in December 2020, of which 50 %, up to a maximum of $ 2.5 million, was committed to be funds that are not recoverable through rates, with the remaining bill credits being deferred for potential future recovery in rates.

Included in the COVID Customer Support Fund were programs that assisted customers with a delinquency of two or more months, providing a one-time credit of $ 100 , an expanded credit of $ 300 for limited income customers, programs to assist extra small and small non-residential customers with a one-time credit of $ 1,000 , and other targeted programs allocated to assist with other COVID-19 needs in support of utility bill assistance.

The December 2020 ACC order further assisted delinquent limited income customers with an additional bill credit of up to $ 250 or their delinquent balance, whichever was less.

APS has distributed all funds for all COVID Customer Support Fund programs combined.

Beyond the COVID Customer Support Fund, APS has also provided $ 2.7 million to assist local non-profits and community organizations working to mitigate the impacts of the COVID-19 pandemic.

• Deferral of PSA Rate Increase .

In February 2021, APS delayed the annual reset of the PSA, with 50 % of the PSA rate increase taking effect in April 2021 and the remaining 50 % taking effect in November 2021.

See below for discussion of the PSA.

▪ modify the Renewable Energy Adjustment Charge 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;

• 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.

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

APS filed an application with the ACC on October 31, 2019 (the “2019 Rate Case”) seeking an increase in annual retail base rates of $ 69 million.

This amount includes recovery of the deferral and rate base effects of the Four Corners selective catalytic reduction (“SCR”) project that was the subject of a separate proceeding.

This amount includes recovery of the deferral and rate base effects of the Four Corners Power Plant (“Four Corners”) selective catalytic reduction (“SCR”) project that was the subject of a separate proceeding.

See “Four Corners SCR Cost Recovery” below.

It also reflects a net credit to base rates of approximately $ 115 million primarily due to the prospective inclusion of rate refunds currently provided through the TEAM.

It also reflects a net credit to base rates of approximately $ 115 million primarily due to the prospective inclusion of rate refunds currently provided through the Tax Expense Adjustment Mechanism (“TEAM”).

The proposed total annual revenue increase in APS’s application is $ 184 million.

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• the following proposed capital structure and costs of capital:

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Capital Structure Cost of Capital

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• 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 $ 0.030168 per kWh for the portion of APS’s retail base rates attributable to fuel and purchased power costs (“Base Fuel Rate”);

• a rate of $ 0.030168 per kWh for the Base Fuel Rate;

• authorization to defer until APS’s next general rate case the increase or decrease in its Arizona property taxes attributable to tax rate changes after the date the rate application is adjudicated;

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▪ a flat bill/subscription rate pilot program;

• proposed rate design changes for commercial customers, including an experimental program designed to provide access to market pricing for up to 200 MW of medium and large commercial customers;

• proposed rate design changes for commercial customers, including an experimental program designed to provide access to market pricing for up to 200 megawatt (“MW”) of medium and large commercial customers;

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

• recovery of the deferral and rate base effects of the construction and operating costs of the Ocotillo modernization project (see discussion below of the 2017 Settlement Agreement);

• continued recovery of the remaining investment and other costs related to the retirement and closure of the Navajo Plant.

See “Navajo Plant” below.

• continued recovery of the remaining investment and other costs related to the retirement and closure of the Navajo Generating Station (the “Navajo Plant”) (see “Navajo Plant” below).

On October 2, 2020, the ACC Staff, the Residential Utility Consumer Office (“RUCO”) and other intervenors filed their initial written testimony with the ACC.

The ACC Staff recommended, among other things, (i) a $ 89.7 million revenue increase, (ii) an average annual customer bill increase of 2.7 %, (iii) a return on equity of 9.4 %, (iv) a 0.3 % or, as an alternative, a 0 % return on the increment of fair value rate base greater than original cost, (v) the recovery of the deferral and rate base effects of the construction and operating costs of the Four Corners SCR project and (vi) the recovery of the rate base effects of the construction and ongoing consideration of the deferral of the Ocotillo modernization project.

The ACC Staff recommended, among other things, (i) an $ 89.7 million revenue increase, (ii) an average annual customer bill increase of 2.7 %, (iii) a return on equity of 9.4 %, (iv) a 0.3 % or, as an alternative, a 0 % return on the increment of fair value rate base greater than original cost , (v) the recovery of the deferral and rate base effects of the construction and operating costs of the Four Corners SCR project and (vi) the recovery of the rate base effects of the construction and ongoing consideration of the deferral of the Ocotillo modernization project.

RUCO recommended, among other things, (i) a $ 20.8 million revenue decrease, (ii) an average annual customer bill decrease of 0.63 %, (iii) a return on equity of 8.74 %, (iv) a 0 % return on the increment of fair value rate base, (v) the nonrecovery of the deferral and rate base effects of the construction and operating costs of the Four Corners SCR project pending further consideration, and (vi) the recovery of the deferral and rate base effects of the construction and operating costs of the Ocotillo modernization project.

The filed ACC Staff and intervenor testimony include additional recommendations, some of which materially differ from APS’s filed application.

On November 6, 2020, APS filed its rebuttal testimony and the principal provisions which differ from its initial application include, among other things, a (i) $ 169 million revenue increase, (ii) average annual customer bill increase of 5.14 %, (iii) return on equity of 10 %, (iv) return on the increment of fair value rate base of 0.8 %, (v) new cost recovery adjustor mechanism, the Advanced Energy Mechanism, to enable more timely recovery of clean investments as APS pursues its clean energy commitment, (vi) recognition that securitization is a potentially useful financing tool to recover the remaining book value of retiring assets and effectuate a transition to a cleaner energy future that APS intends to pursue, provided legislative hurdles are addressed, and (vii) a Coal Community Transition (“CCT”) plan related to the closure or future closure of coal-fired generation

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

facilities, of which $ 25 million would be funds that are not recoverable through rates with a proposal that the remainder be funded by customers over 10 years.

On November 6, 2020, APS filed its rebuttal testimony and the principal provisions which differ from its initial application include, among other things, (i) a $ 169 million revenue increase, (ii) average annual customer bill increase of 5.14 %, (iii) return on equity of 10 %, (iv) return on the increment of fair value rate base of 0.8 %, (v) new cost recovery adjustor mechanism, the Advanced Energy Mechanism (“AEM”), to enable more timely recovery of clean investments as APS pursues its clean energy commitment, (vi) recognition that securitization is a potentially useful financing tool to recover the remaining book value of retiring assets and effectuate a transition to a cleaner energy future that APS intends to pursue, provided legislative hurdles are addressed, and (vii) a Coal Community Transition (“CCT”) plan related to the closure or future closure of coal-fired generation facilities, of which $ 25 million would be funds that are not recoverable through rates with a proposal that the remainder be funded by customers over 10 years.

The CCT plan includes the following proposed components:

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The commitment of funds that would not be recoverable through rates of $ 25 million were recognized in our December 31, 2020 financials.

In 2021, APS committed an additional $ 900,000 to be paid to the Hopi Tribe related to APS’s ownership interests in the Navajo Plant, and this amount was recognized in our December 31, 2021 financials.

In 2021, APS committed an additional $ 0.9 million to be paid to the Hopi Tribe related to APS’s ownership interests in the Navajo Plant, and this amount was recognized in its December 31, 2021 financials.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On December 4, 2020, the ACC Staff and intervenors filed surrebuttal testimony.

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On August 2, 2021, the 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.

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 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 Navajo Plant regulatory asset recovery, (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 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 SCR project (see “Four Corners SCR Cost Recovery” below for additional in formation), (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 Navajo Plant regulatory asset recovery, (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 include the following components:

(i) $ 50 million that will be paid over 10 years to the Navajo Nation, (ii) $ 5 million that will be paid over five years to the Navajo County Communities surrounding Cholla Power Plant, and (iii) $ 1.675 million that will be paid to the Hopi Tribe related to APS’s ownership interests in the Navajo Plant.

These amounts would be recoverable from APS’s customers through the RES adjustment mechanism.

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.

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On October 6, 2021 and October 27, 2021, the ACC voted on various amendments to the 2019 Rate Case ROO that would result in, among other things, (i) a return on equity of 8.70 %, (ii) the recovery of the deferral and rate base effects of the operating costs and construction of the Four Corners SCR project, with the exception of $ 215.5 million (see “Four Corners SCR Cost Recovery” below), (iii) that the CCT plan include the following components:

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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 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.

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Corners SCR plant investments and deferrals (see “Four Corners SCR Cost Recovery” below for additional information) and the 20 basis point penalty reduction to the return on equity.

On February 8, 2022, the Arizona Supreme Court declined to accept jurisdiction on APS’s Petition for Special Action.

The Arizona Court of Appeals heard oral arguments on November 30, 2022.

The Court took the matter under advisement and will issue its decision in due course.

APS cannot predict the outcome of this proceeding.

Consistent with the 2019 Rate Case decision, APS implemented the new rates effective as of December 1, 2021.

On December 3, 2021, ACC Staff notified the ACC of a discrepancy between the written decision, which approved the change in time-of-use on-peak hours to 4 p.m.

to 7 p.m., but did not explicitly approve the 10 months contemplated in APS’s verbal testimony to implement the new time-of-use hours.

On December 16, 2021, the ACC ordered APS to complete the implementation of the time-of-use peak period by April 1, 2022.

On January 12, 2022, the ACC voted to extend the deadline until September 1, 2022, to complete the implementation of the new on-peak hours for residential customers.

In addition, the ACC ordered extensive compliance and reporting obligations and will be continuing to explore whether penalties or rebates would be owed to certain customers.

APS cannot predict the outcome of this matter.

APS expects to file an application with the ACC for its next general retail rate case by mid-year 2022 but is continuing to evaluate the timing of such filing.

APS completed the implementation of the new on-peak hours for residential customers before the September 1, 2022 deadline.

APS cannot predict if the ACC will take any further action on this matter.

Additionally, consistent with the 2019 Rate Case decision, as of April 2022, APS has completed the following payments that will be recoverable through rates related to the CCT:

(i) $ 3.33 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) $ 0.5 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.

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.

APS cannot predict if the ACC will take any further action on this matter.

Information Technology ACC Investigation

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APS is cooperating with the investigation.

The ACC Staff has been directed to report to the ACC on the investigation in April 2022.

APS cannot predict the outcome of this matter.

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2016 Retail Rate Case Filing

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, the 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 a net retail base rate increase of $ 94.6 million, excluding the transfer of adjustor balances, consisting of:

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;

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and (3) a base rate increase of $ 61.0 million due to changes in depreciation schedules.

Other key provisions of the 2017 Settlement Agreement include the following:

• an authorized return on common equity of 10.0 %;

• a capital structure comprised of 44.2 % debt and 55.8 % common equity;

• a cost deferral order for potential future recovery in APS’s next general retail rate case for the construction and operating costs APS incurs for its Ocotillo modernization project;

• a cost deferral and procedure to allow APS to request rate adjustments prior to its next general retail rate case related to its share of the construction costs associated with installing SCR equipment at Four Corners;

• a deferral for future recovery (or credit to customers) of the Arizona property tax expense above or below a specified test year level caused by changes to the applicable Arizona property tax rate;

• an expansion of the PSA to include certain environmental chemical costs and third-party energy storage costs;

• a new AZ Sun II program (now known as APS Solar Communities) for utility-owned solar distributed generation (“DG”) with the purpose of expanding access to rooftop solar for low- and moderate-income Arizonans, recoverable through the RES, to be no less than $ 10 million per year in capital costs, and not more than $ 15 million per year in capital costs;

• an increase to the per kWh cap for the environmental improvement surcharge from $ 0.00016 to $ 0.00050 and the addition of a balancing account;

• rate design changes, including:

▪ a change in the on-peak time-of-use period from noon to 7 p.m.

Monday through Friday, excluding holidays;

▪ non-grandfathered DG customers would be required to select a rate option that has time-of-use rates and either a new grid access charge or demand component;

▪ a Resource Comparison Proxy (“RCP”) for exported energy of 12.9 cents per kWh in year one;

• an agreement by APS not to pursue any new self-build generation (with certain exceptions) having an in-service date prior to January 1, 2022 (extended to December 31, 2027, for combined-cycle generating units), unless expressly authorized by the ACC.

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.

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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.

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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 .

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APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the RES residential distributed energy requirement for 2020.

On September 23, 2020, the ACC approved the 2020 RES Implementation Plan, including APS’s requested waiver of the residential distributed energy requirements for 2020.

On September 23, 2020, the ACC approved the 2020 RES Implementation Plan, including APS’s requested

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waiver of the residential distributed energy requirements for 2020.

In addition, the ACC approved the implementation of a new pilot program that incentivizes Arizona households to install at-home battery systems.

Recovery of the costs associated with the pilot will be addressed in the 2021 DSM Plan.

Recovery of the costs associated with the pilot will be addressed in the 2021 Demand Side Management Implementation Plan (“DSM Plan”).

On July 1, 2020, APS filed its 2021 RES Implementation Plan and proposed a budget of approximately $ 84.7 million.

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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

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substantially from the original Recommended Order and Opinion, supplemental rulemaking procedures were required before the rules could become effective.

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.

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This budget includes funding for programs to comply with the decision in the 2019 Rate Case, including the ACC authorizing spending $ 20 million to $ 30 million in capital costs for the APS Solar Communities program each year for a period of three years from the effective date of the 2019 Rate Case decision.

APS’s budget proposal supports existing approved projects and commitments and requests a permanent waiver of the RES residential and non-residential distributed energy requirements for 2022.

The ACC has not yet ruled on the 2022 RES Implementation Plan.

APS’s budget proposal supports existing approved projects and commitments and requests a waiver of the RES residential and non-residential distributed energy requirements for 2022.

On May 18, 2022, the ACC approved the 2022 RES Implementation Plan, including an amendment requiring a stakeholder working group convene to develop a community solar program for the Commission’s consideration at a future date.

On September 23, 2022, APS filed a community solar proposal in compliance with the ACC order that was informed by a stakeholder working group.

APS is proposing a small, pilot-scale program size of up to 140 MW that would be selected through a competitive RFP.

The ACC has not yet ruled on the proposal.

However, on November 10, 2022, the ACC approved a bifurcated community solar process, directing ACC Staff to develop a statewide policy through additional stakeholder involvement and establishing a separate evidentiary hearing to define other policy components.

The community solar program was deferred to the ACC’s Hearing Division so that a formal evidentiary hearing could be held to consider issues of substance related to community solar.

APS cannot predict the outcomes of these future activities.

On July 1, 2022, APS filed its 2023 RES Implementation Plan and proposed a budget of approximately $ 86.2 million, excluding any funding offsets.

This budget contains funding for programs to comply with Commission-approved initiatives, including the 2019 Rate Case decision.

APS’s budget proposal supports existing approved projects and commitments and requests a waiver of the RES

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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.

In response to an ACC inquiry, the ACC Staff filed a report providing the history of APS’s long-term purchased power contract of the 280 MW Concentrating Solar Power Plant.

This report outlines alternative options that the ACC could pursue to address the costs of this contract, which was executed in February 2008.

On July 13, 2022, the ACC approved an option to take no action at this time.

Demand Side Management Adjustor Charge .

The ACC EES requires APS to submit a Demand Side Management Implementation Plan (“DSM Plan”) annually for review and approval by the ACC.

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.

On September 1, 2017, APS filed its 2018 DSM Plan, which proposed modifications to the DSM portfolio to better meet system and customer needs by focusing on peak demand reductions, storage, load shifting and demand response programs in addition to traditional energy savings measures.

The 2018 DSM Plan sought a requested budget of $ 52.6 million and requested a waiver of the Electric Energy Efficiency Standard for 2018.

On November 14, 2017, APS filed an amended 2018 DSM Plan, which revised the allocations between budget items to address customer participation levels but kept the overall budget at $ 52.6 million.

On December 31, 2018, APS filed its 2019 DSM Plan, which requested a budget of $ 34.1 million and focused on DSM strategies to better meet system and customer needs, such as peak demand reduction, load shifting, storage and electrification strategies.

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.

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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

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current DSM programs, directly to customers through a bill credit in June 2020.

APS has refunded approximately $ 43 million to customers.

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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 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 Plan that proposed an additional performance 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 Plan.

On April 20, 2021, APS filed a request to extend the June 1, 2021 deadline to file its 2022 DSM Plan until 120 days after the ACC has taken action on APS’s amended 2021 DSM Plan.

The ACC approved the request, granting an extension until 120 days after the ACC action on the 2021 DSM Plan, or December 31, 2021, whichever is later.

On December 17, 2021, APS filed its 2022 DSM Plan which requested a budget of $ 78.4 million and represents an increase of approximately $ 14 million in DSM spending above 2021.

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 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,

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APS filed its 2023 DSM Implementation Plan, which requested a budget of $ 88 million.

The ACC has not yet ruled on the 2023 DSM Implementation Plan.

Power Supply Adjustor Mechanism and Balance.

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

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The following table shows the changes in the deferred fuel and purchased power regulatory asset for 2022 and 2021 (dollars in thousands):

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Deferred fuel and purchased power costs — current period 291,992 256,871

Amounts refunded/(charged) to customers ( 44,558 ) 12,047

Amounts charged to customers ( 219,579 ) ( 44,558 )

Ending balance $ 460,561 $ 388,148

The PSA rate for the PSA year beginning February 1, 2019, was $ 0.001658 per kWh, as compared to the $ 0.004555 per kWh for the prior year.

This rate was comprised of a forward component of $ 0.000536 per kWh and a historical component of $ 0.001122 per kWh.

This represented a $ 0.002897 per kWh decrease compared to 2018.

These rates went into effect as filed on February 1, 2019.

On November 27, 2019, APS filed its PSA rate for the PSA year beginning February 1, 2020.

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The 2021 PSA rate is a $ 0.004 per kWh increase compared to the 2020 PSA year, which is the maximum permitted under the Plan of Administration for the PSA.

This left $ 215.9 million of fuel and purchased power costs above this annual cap which will be reflected in future year resets of the PSA.

This left $ 215.9 million of fuel and purchased power costs above this annual cap which will be reflected in

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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 PSA rate increase taking effect in April 2021 and the remaining 50 % taking effect in November 2021.

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 PSA rate of $ 0.003544 per kWh, which 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, which is currently underway, to better understand the factors that contributed to the increase in fuel costs.

APS cannot predict the outcome of this audit.

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 the 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.

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These rates went into effect as filed on February 1, 2022.

At the time of the compliance filing, the amount remaining over the annual cap was approximately $ 365 million of fuel and purchased power costs which will be reflected in future year resets of the PSA.

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.

As of October 31, 2022, the amount in the PSA balancing account was approximately $ 456 million of fuel and purchased power costs.

On February 23, 2023, the ACC approved a rate of $ 0.019074 per kWh that will continue until further notice of the ACC.

The rate will become 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 will also be required to notify the ACC when the PSA balancing account approaches $ 500,000 .

On March 15, 2019, APS filed an application with the ACC requesting approval to recover the costs related to two energy storage power purchase tolling agreements through the PSA, and on January 12, 2021, the ACC approved this application.

On October 28, 2021, APS filed an application requesting approval to recover costs related to three additional energy storage projects through the PSA once the systems are in service, and on December 16, 2021, the ACC approved this application.

On February 22, 2022, APS filed an application requesting similar recovery through the PSA for a solar plus energy storage project, and on April 13, 2022, the ACC approved this application.

On December 21, 2022, APS filed an application requesting similar recovery through the PSA for a solar plus energy storage project, and on February 22, 2023, the ACC approved this application.

For the applications that were approved by the ACC, the ACC has not yet ruled on prudency.

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On March 15, 2019, APS filed an application with the ACC requesting approval to recover the costs related to two energy storage power purchase tolling agreements through the PSA.

On December 29, 2020, the ACC Staff filed its report and recommended the storage costs be included in the PSA once the systems are in-service.

On January 12, 2021, the ACC approved this application but did not rule on the prudency.

On October 28, 2021, APS filed an application requesting approval to recover costs related to three additional energy storage projects through the PSA once the systems are in service.

On December 16, 2021, the ACC approved this application but did not rule on the prudency.

APS cannot predict the outcome of this matter.

Environmental Improvement Surcharge (“EIS”).

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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, and it will become effective with the first billing cycle in April 2023 absent the ACC taking action.

Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters .

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.

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The resolution of proposed adjustments can result in significant volatility in the revenues to be collected.

On March 17, 2020, APS made a filing to make modifications to its annual transmission formula to provide additional transparency for excess and deficient accumulated deferred income taxes resulting from the Tax Act, as well as for future local, state, and federal statutory tax rate changes.

On March 17, 2020, APS made a filing to make modifications to its annual transmission formula to provide additional transparency for excess and deficient accumulated deferred income taxes resulting from the Tax Cuts and Job Act (the “Tax Act”), as well as for future local, state, and federal statutory tax rate changes.

APS amended its March 17, 2020 filing on April 28, 2020, September 29, 2021, and October 27, 2021.

In January 2022, FERC approved APS’s modifications to its annual transmission formula.

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Effective June 1, 2019, APS’s annual wholesale transmission revenue requirement for all users of its transmission system increased by approximately $ 25.8 million for the 12-month period beginning June 1, 2019, in accordance with the FERC-approved formula.

Of this amount, wholesale customer rates increased by $ 21.1 million and retail customer rates would have increased by approximately $ 4.7 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 TCA balancing account, the retail revenue requirement increased by a total of $ 4.9 million, resulting in a decrease to residential rates and an increase to commercial rates.

An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2019.

Effective June 1, 2020, APS’s annual wholesale transmission revenue requirement for all users of its transmission system decreased by approximately $ 6.1 million for the 12-month period beginning June 1, 2020, in accordance with the FERC-approved formula.

Of this net amount, wholesale customer rates increased by $ 4.8 million and retail customer rates would have decreased by approximately $ 10.9 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 a total of $ 7.4 million, resulting in reductions to both residential and commercial rates.

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An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2020.

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An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2021.

Effective June 1, 2022, APS’s annual wholesale transmission revenue requirement for all users of its transmission system decreased by approximately $ 33 million for the 12-month period beginning June 1, 2022, in accordance with the FERC-approved formula.

Of this net amount, wholesale customer rates decreased by approximately $ 6.4 million and retail customer rates would have decreased by approximately $ 26.6 million.

However, since changes in Retail Transmission Charges are reflected through the TCA after consideration of transmission recovery in retail base rates and the ACC approved balancing account, the retail revenue requirement decreased by $ 2.4 million, resulting in a reduction to the residential rate and increases to commercial rates.

An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2022.

Lost Fixed Cost Recovery Mechanism .

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The fixed costs recoverable by the LFCR mechanism were 2.5 cents for both lost residential and non-residential kWh as set forth in the 2017 Settlement Agreement.

The fixed costs recoverable by the LFCR mechanism are currently 2.56 cents for lost residential and 2.68 cents non-residential kWh as set forth in the 2019 Rate Case decision.

The fixed costs recoverable by the LFCR mechanism are currently 2.56 cents for lost residential 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.

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On February 14, 2020, APS filed its 2020 annual LFCR adjustment, requesting that effective May 1, 2020, the annual LFCR recovery amount be reduced to $ 26.6 million (a $ 9.6 million decrease from previous levels).

On July 10, 2019, the ACC approved APS’s 2019 LFCR adjustment as filed, effective with the next billing cycle of July 2019.

On April 14, 2020, the ACC approved the 2020

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LFCR adjustment as filed, effective with the first billing cycle in May 2020.

On April 14, 2020, the ACC approved the 2020 LFCR adjustment as filed, effective with the first billing cycle in May 2020.

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 continue to remain intact.

The $ 11.8 million will continue to be maintained in the LFCR regulatory asset balancing account and will be included in APS’s next LFCR application filing in accordance with the compliance requirements.

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 did not materially impact its results of operations and financial statements for the year ended December 31, 2021.

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).

The ACC’s final determination of APS’s 2022 annual LFCR adjustment filing and related earnings test may materially impact the timing and amounts of future LFCR revenue recognition.

See Note 2 for a discussion of alternative revenue program accounting treatment related to certain regulatory cost recovery mechanisms and see the Regulatory Assets and Liabilities table below.

APS cannot predict the outcome or timing of the ACC’s consideration and final determination of its 2022 annual LFCR adjustment filing.

If the actual rate of return is higher than the authorized rate of return, the LFCR

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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 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.

APS does not believe further ACC approval is needed to move the filing date, and APS intends to file its 2023 annual LFCR adjustment later in 2023 in accordance with the July 31 deadline.

Tax Expense Adjustor Mechanism .

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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 will be recorded as a part of the balancing account and will be 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 are recognized based upon our seasonal kWh sales pattern.

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 will provide an additional

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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 are recognized based upon APS’s seasonal kWh sales pattern.

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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 APS’s next rate case.

APS’s 2017 Rate Case Decision provides that payments by utilities for energy exported to the grid from DG solar facilities will be determined using a RCP methodology, a method that is based on the most recent five-year rolling average price that APS pays for utility-scale solar projects, while a forecasted avoided cost methodology is being developed.

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.

APS’s 2017 Rate Case Decision provides that payments by utilities for energy exported to the grid from residential DG solar facilities will be determined using a RCP methodology as determined in the ACC’s generic Value and Cost of Distributed Generation docket.

RCP is a method that is based on the most recent five-year rolling average price that APS incurs for utility-scale solar 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.

Once the avoided cost methodology is developed, the ACC will determine in APS’s subsequent rate cases which method (or a combination of methods) is appropriate to determine the actual price to be paid by APS for exported distributed energy.

In addition, the ACC made the following determinations:

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

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;

• once an export price is set for APS, 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.

• 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.

In accordance with the 2017 Rate Case Decision, APS filed its request for an export energy price of 10.5 cents per kWh on May 1, 2019.

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.

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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.

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APS and the ACC filed responses to Burns’ petition on July 14, 2021, requesting that the petition be denied.

The Arizona Supreme Court granted Burns' petition and oral argument is scheduled for March 8, 2022.

Pinnacle West and APS cannot predict the outcome of this matter.

The Arizona Supreme Court granted Burns’ petition and heard oral argument on March 8, 2022.

On September 27, 2022, the Arizona Supreme Court issued a decision in favor of Burns reversing the Court of Appeals’ decision.

The Court held that the ACC acting by a majority of its commissioners may not prevent an individual commissioner from exercising investigatory powers pursuant to certain provisions of the Arizona Constitution and that a commissioner aggrieved by such action may seek judicial recourse by way of declaratory judgment.

Pinnacle West and APS do not believe there will be any immediate implications given the underlying issues at hand are moot, but the Company cannot predict if or how this authority may be used by commissioners in the future.

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 such as energy storage, biomass, energy efficiency, electric vehicles, and expanded energy planning through the integrated resource plan (“IRP”) process.

On April 25, 2019, the ACC Staff issued an initial set of draft energy rules and subsequent drafts were filed by ACC Staff in July 2019, February 2020, and July 2020.

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.

These rules would have required utilities to file a Clean Energy Implementation Plan and Energy Efficiency Report as part of their IRP every three years beginning in 2023.

In addition, these rules would have changed the IRP planning horizon from 15 years to 10 years.

The proposed rules also required 50% of

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retail energy served be renewable by the end of 2035.

A new Energy Efficiency Standard (“EES”) was not included in the proposed rules.

The ACC discussed the final draft energy rules at several different meetings in 2020 and 2021.

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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 clean energy rules based on a series of ACC amendments.

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:

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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.

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In February 2022, the ACC acknowledged APS’s IRP.

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 2030 and authorizing future rate base treatment of qualifying demand-side resources as proposed in future rate cases.

APS intends to file its next IRP later in 2023.

See “Energy Modernization Plan” above for information regarding proposed changes to the IRP filings.

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The final rule went into effect on December 31, 2020.

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Residential Electric Utility Customer Service Disconnections

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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

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charge late fees and interest on amounts that were past due from customers.

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 and customers will have four months to pay back their deposit and any remaining delinquent amounts.

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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.

Although the rules are not yet final, APS intends to employ the calendar method for its disconnection moratorium.

This is consistent with APS’s existing disconnection moratorium processes since 2019.

The new rules became effective on April 18, 2022, and APS has employed the calendar method for its disconnection moratorium.

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 beginning 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.

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Retail Electric Competition Rules

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The ACC continues to discuss matters related to retail electric competition, including the potential for additional buy-through programs or other pilot programs.

At the same time, the Arizona legislature is considering a bill that would nullify, if approved, a 20-year-old electric deregulation law that has been in place since 1998.

The bill has several procedural steps in the legislative process before becoming law.

APS cannot predict whether these efforts will result in any changes and, if changes to the rules results, what impact these rules would have on APS.

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.

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APS opposes Green Mountain Energy’s application and intends to intervene to contest it.

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 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.

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On October 28, 2021, an ACC Commissioner docketed a letter directing ACC Staff and interested stakeholders to design a 200-300 MW pilot program that would allow residential and small commercial customers of APS to elect a competitive electricity supplier.

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.

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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.

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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.

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Also, as provided for in the 2017 Rate Case Decision, APS requested that the adjustment become effective no later than January 1, 2019.

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hearing for this matter occurred in September 2018.

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.

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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 argument on November 30, 2022.

The Court took the matter under advisement and will issue its decision in due course.

Based on the partial recovery of these investments and cost deferrals in current rates and the uncertainty of the outcome of the legal appeals process, APS has not recorded an impairment or write-off relating to the SCR plant investments or deferrals as of December 31, 2022.

If the 2019 Rate Case decision to disallow $ 215.5 million of the SCRs is ultimately upheld, APS will be required to record a charge to its results of operations, net of tax, of approximately $ 154.4 million.

We cannot predict the outcome of the legal challenges nor the timing of when this matter will be resolved.

We cannot predict the outcome of the legal

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challenges nor the timing of when this matter will be resolved.

See above for further discussion on the 2019 Rate Case decision.

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 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.

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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

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net book value of its interest in the Navajo Plant was reclassified from property, plant and equipment to a regulatory asset.

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.

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The detail of regulatory assets is as follows (dollars in thousands):

S December 31, 2021 December 31, 2020

Amortization Through Current Non-Current Current Non-Current

S December 31,

Amortization Through 2022 2021

Pension (a) $ 637,656 $ 509,751

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SCR deferral (e) (f) 2031 97,624 105,771

Lost fixed cost recovery (b) 2022 63,889 — 41,807 —

Deferred property taxes 2027 41,057 49,626

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Income taxes — investment tax credit basis adjustment 2056 23,977 24,768

Four Corners cost deferral 2024 8,077 15,998 8,077 24,075

Palo Verde VIEs (Note 17)

Coal reclamation 2026 2,978 13,862 1,068 16,999

2046 20,933 21,094

Active union medical trust (g) 18,226 1,175

Four Corners cost deferral 2024 15,999 24,075

Navajo coal reclamation 2026 13,862 16,840

Lost fixed cost recovery (b) 2023 9,547 63,889

Loss on reacquired debt 2038 9,468 11,020

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Tax expense adjustor mechanism (b) 2031 5,845 6,501

TCA balancing account (b) 2023 170 3,663 — —

Tax expense of Medicare subsidy 2024 1,235 2,469 1,235 3,704

Demand side management (b) 2022 919 — — 7,268

PSA interest 2022 335 — 4,355 —

Deferred fuel and purchased power — mark-to-market (Note 16) 2024 — — 3,341 9,244

Other Various 8,171 10,592

Total regulatory assets (d) $ 1,822,100 $ 1,711,511

current regulatory assets $ 538,879 $ 518,524

Total noncurrent regulatory assets $ 1,283,221 $ 1,192,987

(a) This asset represents the future recovery of pension benefit obligations and expense through retail rates.

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(f) See “Four Corners SCR Cost Recovery” discussion above.

(g) Collected in retail rates.

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The detail of regulatory liabilities is as follows (dollars in thousands):

December 31, 2021 December 31, 2020

Amortization Through Current Non-Current Current Non-Current

Amortization Through 2022 2021

Excess deferred income taxes - ACC — Tax Cuts and Jobs Act (a) 2046 $ 971,545 $ 1,012,448

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Deferred fuel and purchased power — mark-to-market (Note 15)

2024 96,367 107,601

Income taxes — change in rates 2051 64,806 67,678

Four Corners coal reclamation 2038 52,592 55,392

Spent nuclear fuel 2027 6,701 38,581 6,768 44,221

Income taxes — deferred investment tax credit 2056 48,035 49,601

Spent nuclear fuel 2027 39,217 45,282

Renewable energy standard (b) 2024 35,720 38,640

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Tax expense adjustor mechanism (b) (e) N/A 4,835 4,835

Deferred gains on utility property 2022 1,301 551 2,423 1,544

TCA balancing account (b) 2022 — — 2,902 4,672

Active union medical trust N/A — — — 6,057

Other Various 3,092 2,103

Total regulatory liabilities $ 2,333,351 $ 2,795,484

current regulatory liabilities $ 271,575 $ 296,271

Total noncurrent regulatory liabilities $ 2,061,776 $ 2,499,213

(a) For purposes of presentation on the Statement of Cash Flows, amortization of the regulatory liabilities for excess deferred income taxes are reflected as “Deferred income taxes” under Cash Flows From Operating Activities.

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(e) Balance includes amounts for future regulatory consideration and amortization period determination.

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Certain assets and liabilities are reported differently for income tax purposes than they are for financial statement purposes.

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APS has recorded regulatory assets and regulatory liabilities related to income taxes on its Consolidated Balance Sheets in accordance with accounting guidance for regulated operations.

The regulatory assets are for certain temporary differences, primarily the allowance for equity funds used during construction, investment tax credit (“ITC”) basis adjustment and tax expense of Medicare subsidy.

The regulatory assets are for certain temporary differences, primarily the allowance for equity funds used

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during construction, investment tax credit (“ITC”) basis adjustment and tax expense of Medicare subsidy.

The regulatory liabilities primarily relate to the change in income tax rates and deferred taxes resulting from ITCs.

The Tax Act reduced the corporate tax rate to 21% effective January 1, 2018.

As a result of this rate reduction, the Company recognized a $ 1.14 billion reduction in its net deferred income tax liabilities as of December 31, 2017.

In accordance with accounting for regulated companies, the effect of this rate reduction was substantially offset by a net regulatory liability.

Federal income tax laws require the amortization of a majority of the balance over the remaining regulatory life of the related property.

As a result of the modifications made to the annual transmission formula rate during the second quarter of 2018, the Company began amortization of FERC jurisdictional net excess deferred tax liabilities in 2018.

On March 13, 2019, the ACC approved the Company’s proposal to amortize non-depreciation related net excess deferred tax liabilities subject to its jurisdiction over a twelve-month period.

As a result, the Company began amortization in March 2019.

The Company recorded $ 14 million of income tax benefit related to the amortization of these non-depreciation related net excess deferred tax liabilities as of March 31, 2020, with these non-depreciation related net excess deferred tax liabilities being fully amortized as of March 31, 2020.

On October 29, 2019, the ACC approved the Company’s proposal to amortize depreciation related net excess deferred tax liabilities subject to its jurisdiction over a 28.5 -year period with amortization to retroactively begin as of January 1, 2018.

The Company recorded $ 31 million of income tax benefit related to amortization of these depreciation related net excess deferred tax liabilities for the periods ending December 31, 2021, and December 31, 2020.

See Note 4 for more details.

In accordance with regulatory requirements, APS ITCs are deferred and are amortized over the life of the related property with such amortization applied as a credit to reduce current income tax expense in the Statements of Income.

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See Note 17 for additional details related to the Palo Verde sale leaseback VIEs.

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The following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year that are included in accrued taxes and unrecognized tax benefits (dollars in thousands):

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With a few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 2018.

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We reflect interest and penalties, if any, on unrecognized tax benefits in the Pinnacle West Consolidated and APS Consolidated Statements of Income as income tax expense.

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Additionally, as of December 31, 2022, we have recognized less than $ 1 million of interest expense to be paid on the underpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.

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The components of income tax expense are as follows (dollars in thousands):

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Income tax expense/(benefit) $ 74,827 $ 110,086 $ 78,173 $ 90,800 $ 125,553 $ 88,764

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The following chart compares pretax income at the 21% statutory federal income tax rate to income tax expense (dollars in thousands):

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Allowance for equity funds used during construction (see Note 1)

( 4,629 ) ( 4,180 ) ( 2,747 ) ( 4,629 ) ( 4,180 ) ( 2,747 )

Palo Verde VIE noncontrolling interest (see Note 17)

( 3,617 ) ( 3,617 ) ( 4,094 ) ( 3,617 ) ( 3,617 ) ( 4,094 )

Investment tax credit amortization ( 5,608 ) ( 7,620 ) ( 7,510 ) ( 5,608 ) ( 7,620 ) ( 7,510 )

Other federal income tax credits ( 10,867 ) ( 6,976 ) ( 4,616 ) ( 7,721 ) ( 3,912 ) ( 3,035 )

Other 2,644 2,645 1,361 440 616 1,762

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Deferred income taxes — net $ ( 2,384,421 ) $ ( 2,311,862 ) $ ( 2,385,647 ) $ ( 2,331,701 )

As of December 31, 2021, PNW Consolidated deferred tax assets for credit and loss carryforwards relate to federal general business credits of approximately $ 51 million, which first begin to expire in 2036, state credit carryforwards net of federal benefit of $ 42 million, which first begin to expire in 2023, and Arizona net operating loss net of federal benefit of $ 6 million, which will expire in 2041.

As of December 31, 2022, PNW consolidated deferred tax assets for credit and loss carryforwards relate to state credit carryforwards net of federal benefit of $ 43 million, which first begin to expire in 2024.

PNW consolidated credit and loss carryforwards amount above has been reduced by $ 5 million of unrecognized tax benefits.

As of December 31, 2021, APS Consolidated deferred tax assets for credit and loss carryforwards relate to state credit carryforwards net of federal benefit of $ 24 million, which first begin to expire in 2024 and Arizona net operating loss net of federal benefit of $ 4 million, which will expire in 2041.

As of December 31, 2022, APS consolidated deferred tax assets for credit and loss carryforwards relate to state credit carryforwards net of federal benefit of $ 19 million, which first begin to expire in 2025.

APS consolidated credit and loss carryforwards amount above has been reduced by $ 5 million of unrecognized tax benefits.

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Consolidated credit and loss carryforwards amount above has been reduced by $ 9 million of unrecognized tax benefits.

Lines of Credit and Short-Term Borrowings

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Pinnacle West

On May 5, 2020, Pinnacle West refinanced its 364-day $ 50 million term loan agreement with a new 364-day $ 31 million term loan facility that would have matured May 4, 2021 .

Borrowings under the facility bore interest at Eurodollar Rate plus 1.40 % per annum.

Pinnacle West repaid this facility on April 27, 2021.

On May 28, 2021, Pinnacle West replaced its $ 200 million revolving credit facility that would have matured on July 11, 2023, with a new $ 200 million revolving credit facility that matures on May 28, 2026.

At December 31, 2022, Pinnacle West had a $ 200 million revolving credit facility that matures on May 28, 2026.

Pinnacle West has the option to increase the amount of the facility up to a maximum of $ 300 million upon the satisfaction of certain conditions and with the consent of the lenders.

Interest rates are based on Pinnacle West’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.

The facility is available to support Pinnacle West’s general corporate purposes, including support for Pinnacle West's $ 200 million commercial paper program, for bank borrowings or for issuances of letters of credits.

At December 31, 2021, Pinnacle West had no outstanding borrowings under its revolving credit facility, no letters of credit outstanding under the credit facility and $ 13 million of commercial paper borrowings.

On May 28, 2021, APS replaced its two $ 500 million revolving credit facilities that would have matured on June 29, 2022 and July 11, 2023, respectively, with two new $ 500 million revolving credit facilities that total $ 1 billion and that mature on May 28, 2026.

APS may increase the amount of each facility up to a maximum of $ 700 million, for a total of $ 1.4 billion, upon the satisfaction of certain

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conditions and with the consent of the lenders.

The facility is available to support Pinnacle West’s general corporate purposes, including support for Pinnacle West’s $ 200 million commercial paper program, for bank borrowings or for issuances of letters of credit.

At December 31, 2022, Pinnacle West had no outstanding borrowings under its revolving credit facility, no letters of credit outstanding under t he credit facility, and $ 16 million of outstanding commercial paper borrowings.

At December 31, 2022, APS had two $ 500 million revolving credit facilities that total $ 1 billion and that mature on May 28, 2026.

APS may increase the amount of each facility up to a maximum of $ 700 million, for a total of $ 1.4 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 agreements include 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.

These facilities are available to support APS’s general corporate purposes, including support for APS’s $ 750 million commercial paper program, for bank borrowings or for issuances of letters of credit.

At December 31, 2021, APS had no outstanding borrowings under its revolving credit facilities, no letters of credit outstanding under the credit facilities and $ 279 million of outstanding commercial paper borrowings.

At December 31, 2022, APS ha d no outstanding borrowings under its revolving credit facilities, no letters of credit outstanding under the credit facilities and $ 325 million of outstanding commercial paper b orrowings.

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

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Debt Provisions

On December 17, 2020, the ACC issued a financing order 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).

On December 17, 2020, the ACC issued a financing order in which, subject to specified parameters and procedures, it approved APS’s short-term debt authorization equal to the sum of (i) 7 % of APS’s capitaliza tion, and (ii) $ 500 million (which is required to be used for costs relating to purchases of natural gas and power).

On December 15, 2022, the ACC issued a financing order that, among other things, reaffirmed the short-term debt authorization from the 2020 financing order.

See Note 6 for additional long-term debt provisions.

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Total APS long-term debt less current maturities 6,793,529 6,266,693

Los Alamitos equity bridge loan (d) (d) 27,575 —

Los Alamitos construction facility (e) (e) 23,110 —

Unamortized debt issuance cost ( 135 ) —

Total BCE long-term debt 50,550 —

Less current maturities 50,685 —

Total BCE long-term debt less current maturities ( 135 ) —

Pinnacle West

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(a) This schedule does not reflect the timing of redemptions that may occur prior to maturities.

(b) The weighted-average rate for the variable rate pollution control bonds was 0.22 % at December 31, 2021, and 0.18 % at December 31, 2020.

(b) The weighted-average interest rate for the variable rate pollution control bonds was 3.96 % at December 31, 2022, and 0.22 % at December 31, 2021.

See additional details below.

The following table shows principal payments due on Pinnacle West’s and APS’s total long-term debt (dollars in thousands):

See additional details below.

(d) The weighted-average interest rate for the variable rate equity bridge loan is 5.18 % at December 31, 2022 and will mature on the project’s commercial operation date, expected on or before August 15, 2023.

See additional details below.

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(e) The weighted-average interest rate for the variable rate construction facility is 5.71 % at December 31, 2022 and will mature on the project’s commercial operation date, expected on or before August 15, 2023.

See additional details below.

The following table shows principal payments due on Pinnacle West’s, APS’s and BCE’s total long-term debt (dollars in thousands):

Year Consolidated

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2026 250,000 250,000 —

2027 300,000 300,000 —

Thereafter 5,743,975 5,743,975 —

Total $ 7,844,660 $ 6,843,975 $ 50,685

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Debt Fair Value

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APS 6,793,529 5,629,491 6,266,693 6,933,619

BCE 50,550 50,685 — —

Total $ 7,791,971 $ 6,585,701 $ 7,063,735 $ 7,726,354

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The proceeds were used for general corporate purposes.

On December 23, 2020, Pinnacle West entered into a $ 150 million term loan facility that matures June 30, 2022.

On December 23, 2020, Pinnacle West entered into a $ 150 million term loan facility that was set to mature June 30, 2022.

The proceeds were received on January 4, 2021, and used for general corporate purposes.

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On January 6, 2022, Pinnacle West repaid this term loan facility early.

On August 16, 2021, APS issued $ 450 million of 2.2 % unsecured senior notes that mature December 15, 2031.

The net proceeds from the sale were used to repay short-term indebtedness consisting of commercial paper, replenish cash used to fund capital expenditures, and for general corporate purposes.

On December 21, 2021, Pinnacle West contributed $ 150 million into APS in the form of an equity infusion.

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On December 16, 2022, Pinnacle West entered into a $ 175 million term loan facility that matures December 16, 2024.

The proceeds were received on January 6, 2023 and used for general corporate purposes.

We recognized the term loan facility as long-term debt upon settlement on January 6, 2023.

On January 6, 2022, Pinnacle West contributed $ 150 million into APS in the form of an equity infusion.

APS used this contribution to repay short-term indebtedness.

On September 15, 2022, APS remarketed $ 128 million of the Maricopa County, Arizona Pollution Control Corporation Revenue Refunding Bonds, 2009 Series B, C, D and E, due May 1, 2029 (the “Bonds”).

The Bonds were originally issued on June 26, 2009, and prior to this remarketing were held as treasury bonds.

Each series of the Bonds has a principal amount of $ 32 million.

All series of the Bonds have been remarketed and issued in weekly variable interest rate modes and are classified as long-term debt on our Consolidated Balance Sheets.

On November 8, 2022, APS issued $ 400 million of 6.35 % unsecured senior notes that mature December 15, 2032.

The net proceeds from the sale were used to repay short-term indebtedness consisting of commercial paper, replenish cash used to fund capital expenditures, and for general corporate purposes.

On January 6, 2023, Pinnacle West contributed $ 150 million into APS in the form of an equity infusion.

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See “Lines of Credit and Short-Term Borrowings” in Note 5 and “Financial Assurances” in Note 10 for discussion of APS’s separate outstanding letters of credit.

On February 11, 2022, a special purpose subsidiary of BCE entered into a credit agreement to finance capital expenditures and related costs for a microgrid project in California under development by the subsidiary.

The credit facilities consist of an approximately $ 33 million equity bridge loan facility, an

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approximately $ 42 million non-recourse construction to term loan facility, and an approximately $ 5 million letter of credit.

In connection with the credit agreement, Pinnacle West has guaranteed the full amount of the equity bridge loan.

On February 11, 2022, $ 12 million was drawn from the equity bridge loan.

On February 11, 2022, a special purpose subsidiary of BCE entered into a credit agreement to finance capital expenditures and related costs for a 31 MW solar and battery storage project in Los Alamitos, California (“Los Alamitos”) that is under development by the subsidiary.

The credit agreement consists of an approximately $ 33 million equity bridge loan facility, an approximately $ 42 million non-recourse construction facility, and an approximately $ 5 million letter of credit facility.

In connection with the credit agreement, Pinnacle West has issued a guarantee of up to $ 42 million primarily relating to the equity bridge loan.

As of December 31, 2022, $ 28 million has been drawn from the equity bridge loan and there is a $ 23 million outstanding balance for the construction facility and $ 2.5 million letters of credit outstanding under the credit facility.

The equity bridge loan and construction facility mature and are due on the project’s commercial operation date, expected on or before August 15, 2023.

BCE expects to convert the construction facility into a term loan upon the project’s commercial operation date.

On October 19, 2022, BCE executed an interest rate swap to hedge the variable interest rate exposure of this credit facility.

Debt Provisions

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Pinnacle West and APS comply with this covenant.

For both Pinnacle West and APS, this covenant requires that the ratio of consolidated debt to total consolidated capitalization not exceed 65 %.

For both Pinnacle West and APS, this covenant requires that the ratio of consolidated debt to total consolidated

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capitalization not exceed 65 %.

At December 31, 2022, the ratio was approximately 57.7 % for Pinnacle West and 50.8 % for APS.

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Although provisions in APS’s articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements.

On December 17, 2020, the ACC issued a financing order in which, subject to specified parameters and procedures, it approved APS’s long-term debt authorization from $ 5.9 billion to $ 7.5 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs.

On December 17, 2020, the ACC issued a financing order in which, subject to specified parameters and procedures, it approved APS’s long-term debt authorization of $ 7.5 billion.

On December 15, 2022, the ACC issued a financing order approving APS’s application filed on April 6, 2022 requesting to increase the long-term debt limit from $ 7.5 billion to $ 8.0 billion and to exclude financing lease PPAs from the definition of long-term indebtedness for purposes of the ACC financing orders.

See Note 5 for additional short-term debt provisions.

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The supplemental excess benefit retirement plan covers officers of the Company and highly compensated employees designated for participation by the Board of Directors.

Our employees do not contribute to the plans.

Our employees do not contribute directly to the plans.

We calculate the benefits based on age, years of service and pay.

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Pinnacle West also sponsors other postretirement benefit plans (Pinnacle West Capital Corporation Group Life and Medical Plan and Pinnacle West Capital Corporation Post-65 Retiree Health Reimbursement Arrangement “HRA”) for the employees of Pinnacle West and its subsidiaries.

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We retain the right to change or eliminate these benefits.

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Pinnacle West uses a December 31 measurement date each year for its pension and other postretirement benefit plans.

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Accordingly, these changes are recorded as a regulatory asset or regulatory liability.

Our retail rates provide for the inclusion of annual benefit costs, which allows for recovery or return of this regulatory asset/liability.

Our retail rates provide for the inclusion of annual benefit expense, which allows for recovery or return of this regulatory asset/liability.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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The overall strategy of the pension plan’s IPS is to achieve an adequate level of trust assets relative to the benefit obligations.

To achieve this objective, the plan’s investment policy provides for mixes of investments including long-term fixed income assets and return-generating assets.

The target allocation between return-generating and long-term fixed income assets is defined in the IPS and is a function of the plan’s funded status.

To achieve this objective, the plan’s investment policy provides for mixes of investments including long-term fixed income assets and return-seeking assets.

The target allocation between return-seeking and long-term fixed income assets is defined in the IPS and is a function of the plan’s funded status.

The plan’s funded status is reviewed on at least a monthly basis.

Changes in the value of long-term fixed income assets, also known as liability-hedging assets, are intended to offset changes in the benefit obligations due to changes in interest rates.

Long-term fixed

Long-term fixed income assets consist primarily of fixed income debt securities issued by the U.S.

Treasury and other

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

income assets consist primarily of fixed income debt securities issued by the U.S.

Treasury and other government agencies, U.S.

government agencies, U.S.

Treasury Futures Contracts, and fixed income debt securities issued by corporations.

Long-term fixed income assets may also include interest rate swaps, and other instruments.

Return-generating assets are intended to provide a reasonable long-term rate of investment return with a prudent level of volatility.

Return-generating assets are composed of U.S.

Return-seeking assets are intended to provide a reasonable long-term rate of investment return with a prudent level of volatility.

Return-seeking assets are composed of U.S.

equities, international equities, and alternative investments.

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Alternative investments may include investments in real estate, private equity and various other strategies.

The plan may also hold investments in return-generating assets by holding securities in partnerships, common and collective trusts, and mutual funds.

The plan may also hold investments in return-seeking assets by holding securities in partnerships, common and collective trusts, and mutual funds.

Based on the IPS, and given the pension plan’s funded status at year-end 2022, the target and actual allocation for the pension plan at December 31, 2022, are as follows:

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Long-term fixed income assets 80 % 78 %

Return-generating assets 20 % 21 %

Return-seeking assets 20 % 22 %

Total 100 % 100 %

The permissible range is within +/-3% of the target allocation shown in the above table, and also considers the plan’s funded status.

The following table presents the additional target allocations, as a percent of total pension plan assets, for the return-generating assets:

The following table presents the additional target allocations, as a percent of total pension plan assets, for the return-seeking assets:

Target Allocation

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Long-term fixed income assets 62 %

Return-generating assets 37 %

Return-seeking assets 38 %

See Note 12 for a discussion on the fair value hierarchy and how fair value methodologies are applied.

The plans invest directly in fixed income, U.S.

Treasury Futures Contracts, and equity securities, in addition to investing indirectly in fixed income securities, equity securities and real estate through the

Treasury Futures Contracts, and equity securities, in addition to investing indirectly in fixed income securities, equity securities and real estate through the use of mutual funds, partnerships and common and collective trusts.

Equity securities held directly by the

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

use of mutual funds, partnerships and common and collective trusts.

Equity securities held directly by the plans are valued using quoted active market prices from the published exchange on which the equity security trades and are classified as Level 1.

plans are valued using quoted active market prices from the published exchange on which the equity security trades and are classified as Level 1.

Treasury Futures Contracts are valued using the quoted active market prices from the exchange on which they trade and are classified as Level 1.

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The NAV for trusts investing in real estate is derived from the appraised values of the trust’s underlying real estate assets.

As of December 31, 2021, the plans were able to transact in the common and collective trusts at NAV.

Investments in partnerships are also valued using the concept of NAV as a practical expedient and, accordingly, are not classified in the fair value hierarchy.

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See Note 17 for a discussion of VIEs.

On May 1, 2021, APS had a new purchased power lease contract that commenced, with a lease term expiring on October 31, 2027.

On December 31, 2021, APS modified an existing purchased power lease contract that had commenced in June 2020.

The lease modification extends the expiration of this

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

lease from September 30, 2025, to October 31, 2031, among other changes.

These purchased power lease agreements 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.

non-consecutive periods of use.

APS does not operate or maintain these leased assets.

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At December 31, 2022, we have various lease arrangements that have been executed but have not yet commenced.

These arrangements primarily relate to energy storage assets, with expected lease commencement dates ranging from June 2022 through June 2024, with lease terms expiring through May 2044.

We expect the total fixed consideration paid for these arrangements, which includes both lease and nonlease payments, will approximate $ 1.3 billion over the term of the arrangements.

These arrangements primarily relate to energy storage assets.

The lease commencement dates for these arrangements have experienced delays.

APS continues to work with the lessors to determine revised commencement dates.

We expected lease commencement dates ranging from June 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 $ 2.7 billion over the 20-year terms of the agreements.

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 lease agreements previously commenced in 2020 and 2021.

In January 2023, as a result of these modifications, APS recorded an additional $ 537 million of operating lease liabilities and right-of-use operating lease assets.

These obligations relate to payments that will occur during the periods 2023 through 2034.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

December 31, 2021 Year Ended December 31, 2020 Year Ended December 31, 2019

Year Ended December 31, 2022 Year Ended December 31, 2021 Year Ended December 31, 2020

Cash paid for amounts included in the measurement of lease liabilities — operating cash flows:

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Kyrene — Knox System 50.0 % 578 336 —

Agua Fria Switchyard 10.0 % — — 32

(a) See Note 17.

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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.

The settlement agreement, as amended, provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2019.

On September 1, 2020, APS and DOE entered into an addendum to the settlement agreement allowing for the recovery of costs incurred through December 31, 2022.

APS has submitted seven claims pursuant to the terms of the August 18, 2014, settlement agreement, for seven separate time periods during July 1, 2011, through June 30, 2020.

DOE has approved and paid $ 111.8 million for these claims (APS’s share is $ 32.5 million).

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, 2022.

An additional extension is currently pending.

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 November 1, 2021, APS filed its eight h claim pursuant to the terms of the August 18, 2014, settlement agreement in the amount of $ 12.2 million (APS’s share is $ 3.6 million).

On October 31, 2022, APS filed its ninth claim pursuant to the terms of the August 18, 2014 settlement agreement in the amount of $ 14.3 million (APS’s share is $ 4.2 million).

In February 2023, the DOE approved this claim.

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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

APS has also secured accidental outage insurance for a sudden and unforeseen accidental outage of any of the three units.

The property damage,

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

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 accumul ated funds.

Th e maximum amount APS could incur under the current NEIL policies totals approximately $ 22.3 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 $ 62.8 million in deposit premium within 20 days of request as assurance to satisfy any site obligation of retrospective premium assessment.

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APS is party to various fuel and purchased power contracts and purchase obligations with terms expiring between 2023 and 2043 that include required purchase provisions.

APS estimates the contract requirements to be approximately $ 1 billion in 2022;

APS estimates the contract requirements to be approximately $ 955 million in 2023;

$ 823 million in 2024;

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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”).

Based upon discussions between the OU3 working group parties and EPA, along with the results of recent technical analyses prepared by the OU3 working group to supplement the RI/FS for OU3, APS anticipates finalizing the RI/FS during the first or second quarter of 2022.

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 overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time expenditures related to this matter cannot be reasonably estimated.

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.

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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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

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.

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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.

We are unable to predict the outcome of these matters;

On August 16, 2019, Maricopa County, one of the three direct defendants in the ancillary service provider lawsuit, filed a third-party complaint seeking contribution for its liability, if any, from APS and 28 other third-party defendants.

While this lawsuit remains pending, 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 $ 21 million in CERCLA response costs claimed by the service provider.

We are unable to predict the outcome of any further litigation related to the remaining response costs at issue in this litigation;

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.

At the present time, we are unable to predict the outcome of this matter and expenditures related to this matter cannot be reasonably estimated.

Arizona Attorney General Matter

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The settlement resulted in APS paying $ 24.75 million, approximately $ 24 million of which was returned to customers as restitution.

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Four Corners SCR Cost Recovery

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The Arizona Court of Appeals heard oral arguments on November 30, 2022.

The Court took the matter under advisement and will issue its decision in due course.

If the 2019 Rate Case decision to disallow $ 215.5 million of the SCRs is ultimately upheld, APS will be required to record a charge to its results of operations, net of tax, of approximately

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

$ 154.4 million.

We cannot predict the outcome of the legal challenges nor the timing of when this matter will be resolved.

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NTEC purchased the interest from 4CA on July 3, 2018.

See “Four Corners — 4CA Matter” below for a discussion of the NTEC purchase.

The cost of the pollution controls related to the 7 % interest is approximately $ 45 million, which was assumed by NTEC through its purchase of the 7 % interest.

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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.

The rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act (“RCRA”) and establishes national

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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.

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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:

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• 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, it is not clear when that program will be put into effect.

Although ADEQ has taken steps to develop a CCR permitting program, including supporting the passage of new state legislation 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.

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.

• Based on an August 21, 2018, D.C.

Circuit decision, which vacated and remanded those provisions of the EPA CCR regulations that allow for the operation of unlined CCR surface impoundments, EPA recently proposed corresponding changes to federal CCR regulations.

On July 29, 2020, EPA took final action on new regulations establishing revised deadlines for initiating the closure of unlined CCR surface impoundments by April 11, 2021, at the latest.

All APS disposal units subject to these closure requirements were closed as of April 11, 2021.

• On November 4, 2019, EPA also proposed to change the manner by which facilities that have committed to cease burning coal in the near-term may qualify for alternative closure.

Such qualification would allow CCR disposal units at these plants to continue operating, even though they would otherwise be subject to forced closure under the federal CCR regulations.

EPA’s July 29, 2020, final regulation adopted this proposal and now requires explicit EPA approval for facilities to utilize an alternative closure deadline.

With respect to the Cholla facility, APS’s application for alternative closure (which would allow the continued disposal of CCR within the facility’s existing unlined CCR surface impoundments until the required date for ceasing coal-fired boiler operations in April 2025) was submitted to EPA on November 30, 2020, and is currently pending.

• 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.

On January 11, 2022, EPA began issuing proposed decisions pursuant to this provision of the federal CCR regulations and we anticipate receiving a proposed decision with respect to the Cholla facility in 2022.

We expect to have a proposed decision from EPA regarding Cholla sometime in 2023.

We cannot at this time predict the outcome of these regulatory proceedings or when the EPA will take final action on those matters that are still pending.

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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 $ 16 million.

APS estimates that its share of incremental costs to comply with the CCR rule for Four Corners is

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approximately $ 30 million and its share of incremental costs to comply with the CCR rule for Cholla is approximately $ 16 million.

The Navajo Plant disposed of CCR only in a dry landfill storage area.

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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

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Four Corners will need to undergo corrective action.

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).

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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 process, we cannot predict any ultimate impacts to the Company;

however, at this time we do not believe the cost estimates for Cholla and any potential change to the cost estimate for Four Corners would have a material impact on our financial position, results of operations or cash flows.

Given uncertainties that may exist until we have fully completed the corrective action assessment process, APS cannot predict any ultimate impacts to the Company;

however, at this time APS does not believe the cost estimates for Cholla and any potential change to the cost estimate for Four Corners would have a material impact on its financial position, results of operations, or cash flows.

Clean Power Plan/Affordable Clean Energy Regulations .

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Circuit vacated the ACE regulations and remanded them back to EPA to develop new existing power plant carbon regulations consistent with the court’s ruling.

That ruling endorsed an expansive view of the federal Clean Air Act consistent with EPA’s 2015 CPP.

Nonetheless, on October 29, 2021, the U.S.

Supreme Court announced that it was accepting judicial review of the January D.C.

Circuit decision vacating the ACE regulations.

While the Biden administration has expressed an intent to regulate carbon emissions in this sector more aggressively under the Clean Air Act, we cannot at this time predict the outcome of pending EPA rulemaking proceedings or ongoing litigation related to the scope of EPA’s authority under the Clean Air Act to regulate carbon emissions from existing power plants.

That decision, which endorsed an expansive view of the federal Clean Air Act consistent with EPA’s 2015 CPP, was subsequently reversed by the U.S.

Supreme Court on June 30, 2022.

While the current administration has expressed its intent to develop new carbon emission regulations governing existing power plants sometime in 2023, such action will be constrained by the U.S.

Supreme Court’s decision that the CPP violated the Clean Air Act.

Nonetheless, we cannot at this time predict the outcome of pending EPA rulemaking proceedings related to carbon emissions from existing power plants.

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 our coal plants or the willingness or ability of power plant participants to fund any required equipment upgrades or continue their participation in these plants.

The financial impact of complying with current and future environmental rules could jeopardize the economic viability of our 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.

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

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Based upon a November 1, 2019, filing by several environmental groups, the EAB again took up review of the Four Corners NPDES Permit.

Oral argument on this appeal

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was held on September 3, 2020, and the EAB denied the environmental group petition on September 30, 2020.

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 September 2019 permit remains in effect pending this appeal.

As of November 11, 2021, the parties to this lawsuit, including APS, reached a tentative agreement to settle this matter.

Review of this agreement, including public commenting, is currently pending with EPA.

Notwithstanding this tentative agreement, we cannot predict the outcome of these appeal proceedings, including further settlement discussions, and, if settlement efforts fail and the appeal is eventually successful, whether that outcome will have a material impact on our financial position, results of operations, or cash flows.

Oral argument on this appeal was held on September 3, 2020, and 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 this 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.

Four Corners — 4CA Matter

On July 6, 2016, 4CA purchased El Paso’s 7 % interest in Four Corners.

NTEC purchased this 7 % interest o n July 3, 2018, from 4CA .

NTEC purchased the 7 % interest at 4CA’s book value, approximately $ 70 million, and is paying 4CA the purchase price over a period of four years pursuant to a secured interest-bearing promissory note.

The note is secured by a portion of APS’s payments to be owed to NTEC under the 2016 Coal Supply Agreement.

As of December 31, 2021, the note has a remaining balance of approximately $ 9.2 million.

NTEC continues to make payments in accordance with the terms of the note.

Due to its short-remaining term, among other factors, there are no expected credit losses associated with the note.

NTEC purchased this 7 % interest on July 3, 2018, from 4CA.

NTEC purchased the 7 % interest at 4CA’s book value, approximately $ 70 million, and paid 4CA the purchase price over a period of four years pursuant to a secured interest-bearing promissory note, which was paid in full as of June 30, 2022.

In connection with the sale, Pinnacle West guaranteed certain obligations that NTEC will have to the other owners of Four Corners, such as NTEC’s 7 % share of capital expenditures and operating and maintenance expenses.

Pinnacle West’s guarantee is secured by a portion of APS’s payments to be owed to NTEC under the 2016 Coal Supply Agreement.

Tenaska Clear Creek Wind, LLC, the developer, owner, and operator of the Clear Creek wind farm, has disputed the proposed cost allocation of system upgrades related to connecting the Clear Creek wind farm to the transmission system and filed a complaint with FERC on May 21, 2021, which was denied on September 9, 2022.

Subsequently, Tenaska Clear Creek Wind, LLC filed with FERC a request for rehearing and a motion for stay of the September 9, 2022 order.

On October 7, 2022, the request for rehearing was denied by FERC.

FERC has not ruled on the motion for stay.

Clear Creek has filed a Petition for Review with the U.S.

Court of Appeals and Motion for Stay Pending Appeal, both of which are still pending.

Tenaska Clear Creek Wind, LLC filed a second complaint with FERC on May 25, 2022, alleging that the wind farm was being curtailed in a discriminatory manner.

The May 25, 2022 Complaint was denied by FERC on December 15, 2022 and Tenaska Clear Creek Wind, LLC requested Rehearing of the denial on January 13, 2023.

Due to the disputed system upgrades and the related curtailment, the Clear Creek wind farm has experienced a significant reduction in power generation that has had a material adverse impact on the project’s ability to generate cash flow for investors.

These energy curtailments are expected to persist, unless and until system upgrades are implemented to alleviate the present transmission system congestion,

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or the disputes are determined in favor of, or settled in a manner favorable to, Tenaska Clear Creek Wind, LLC.

As such, during the fourth quarter of 2022, due to these on-going disputes, cost allocation uncertainties, and no probable favorable resolution, BCE determined its equity method investment was fully impaired.

Prior to the impairment, the investment had a carrying value of $ 17.1 million, which has been written-down to reflect the investment’s estimated fair value of zero as of December 31, 2022.

Pinnacle West’s Consolidated Statement of Income for the year ended December 31, 2022 includes an after-tax loss of $ 12.8 million relating to this impairment.

Financial Assurances

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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.

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Pinnacle West has issued parental guarantees and has provided indemnification under certain surety bonds for APS which were not material at December 31, 2022.

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The amounts guaranteed by Pinnacle West are reduced as payments are made under the respective guarantee agreements.

The Equity Contribution Guarantees remaining as of December 31, 2021, are immaterial in amount (approximately $ 2 million) and the PTC Guarantees (approximately $ 37 million as of December 31, 2021) are currently expected to be terminated 10 years following the commercial operation date of the applicable project.

In connection with the credit agreement entered into by a special purpose subsidiary of BCE on Februa ry 11, 2022, Pinnacle West has guaranteed the full amount of the equity bridge loan under the credit facility.

As of December 31, 2022 there is approximately $ 34 million of remaining guarantees primarily relating to the PTC Guarantees that is expected to terminate by 2030.

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In connection with the credit agreement entered into by a special purpose subsidiary of BCE on Februa ry 11, 2022, Pinnacle West has issued a guarantee of up to $ 42 million primarily related to the bridge loan.

See Note 6 for additional details.

Asset Retirement Obligations

In 2022, APS did not revise any cost estimates related to existing AROs, and no new AROs were necessary.

In 2021, APS revised its cost estimates for existing AROs at Cholla related to updated estimates for the closure of ponds and facilities, which resulted in an increase to the ARO of approximately $ 28 million.

See additional details in Notes 3 and 10 .

In 2020, APS revised its cost estimates for existing AROs at Cholla relating to updated estimates for the closure of ponds and facilities, and at Four Corners and the Navajo Plant relating to corrective action and water monitoring costs, which resulted in an increase to the ARO of $ 6 million.

Also in 2020, an updated Four Corners decommissioning study was finalized for the updated closure date of 2031, which resulted in an increase to the ARO of $ 13 million.

The following table shows the change in our AROs (dollars in thousands):

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See detail of regulatory liabilities in Note 3.

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Fair Value Measurements

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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.

Thus, a valuation may be classified in Level 3 even though the

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valuation may include significant inputs that are readily observable.

We maximize the use of observable inputs and minimize the use of unobservable inputs.

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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 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;

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See Note 7 for fair value discussion of plan assets held in our retirement and other benefit plans.

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Cash Equivalents

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

Risk Management Activities — Derivative Instruments

Risk Management Activities — Energy Derivative Instruments

Exchange traded commodity contracts are valued using unadjusted quoted prices.

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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 broker quotes are not available, the primary valuation technique used to calculate the fair value is the extrapolation of forward

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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.

Risk Management Activities — Interest Rate Derivatives

Our interest rate derivative instruments relate to an interest rate swap, which is valued using financial models that utilize observable inputs for similar instruments and are classified as Level 2.

Inputs include yield curves and credit quality of the counterparties.

Investments Held in Nuclear Decommissioning Trusts and Other Special Use Funds

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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.

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Fixed Income Securities

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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.

The funds’ NAV is primarily derived from the quoted active market prices of the underlying equity securities

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held by the funds.

We may transact in these commingled funds on a semi-monthly basis at the NAV.

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Commodity contracts $ — $ 127,129 $ 26,132 $ ( 21,163 ) (a) $ 132,098

Interest rate swaps — 131 — — 131

Subtotal risk management activities - derivative instruments — 127,260 26,132 ( 21,163 ) 132,229

Nuclear decommissioning trust:

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Commodity contracts $ — $ ( 25,874 ) $ ( 31,020 ) $ 15,357 (a) $ ( 41,537 )

Interest rate swaps — ( 909 ) — — ( 909 )

Subtotal risk management activities - derivative instruments — ( 26,783 ) ( 31,020 ) 15,357 ( 42,446 )

Total liabilities $ — $ ( 26,783 ) $ ( 31,020 ) $ 15,357 $ ( 42,446 )

(a) Represents counterparty netting, margin, and collateral.

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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 December 31, 2022 and December 31, 2021:

December 31, 2022

Fair Value (thousands) Valuation Significant Weighted-Average

Commodity Contracts Assets Liabilities Technique Unobservable Input Range (b)

Forward Contracts (a) $ 26,132 $ 1,759 Discounted cash flows Electricity forward price (per MWh) $ 37.79

Forward Contracts (a) — 29,261 Discounted cash flows Natural gas forward price (per MMBtu) $( 11.81 )

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.

December 31, 2021

Fair Value (thousands) Valuation Significant Weighted-Average

Commodity Contracts Assets Liabilities Technique Unobservable Input Range (b)

Forward Contracts (a) $ — $ 2,738 Discounted cash flows Natural gas forward price (per MMBtu) $( 0.76 ) - $( 0.65 )

Total $ — $ 2,738

(a) Includes swaps and physical and financial contracts.

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

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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 for the years ended December 31, 2022 and 2021 (dollars in thousands):

Commodity Contracts 2022 2021

Net derivative balance at beginning of period $ ( 2,738 ) $ ( 1,102 )

Total net gains (losses) realized/unrealized:

Deferred as a regulatory asset or liability ( 374 ) 13,827

Settlements ( 1,123 ) ( 15,463 )

Transfers into Level 3 from Level 2 ( 846 ) —

Transfers from Level 3 into Level 2 193 —

Net derivative balance at end of period $ ( 4,888 ) $ ( 2,738 )

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

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See Note 6 for our long-term debt fair values.

The NTEC note receivable related to the sale of 4CA’s interest in Four Corners bears interest at 3.9 % per annum and has a book value of $ 9 million as of December 31, 2021, as presented on the Consolidated Balance Sheets.

The carrying amount is not materially different from the fair value of the note receivable and is classified within Level 3 of the fair value hierarchy.

See Note 11 for more information on 4CA matters.

Nonrecurring Fair Value Measurements

As of December 31, 2022, the fair value of BCE’s impaired equity method investment that is measured at fair value on a nonrecurring basis was zero, which was valued using significant unobservable inputs (Level 3).

The total tax effected impairment charge included in net income for the year ended December 31, 2022 was $ 12.8 million.

See Note 10 for additional information.

Earnings Per Share

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Net income attributable to common shareholders — diluted $ 4.26 $ 5.47 $ 4.87

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Stock-Based Compensation

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No new awards may be granted under the 2012 or 2007 Plans.

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Stock-Based Compensation Expense and Activity

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As of December 31, 2022, there were approximately $ 20 million of unrecognized compensation costs related to nonvested stock-based compensation arrangements.

We expect to recognize these costs over a weighted-average period of 2 years.

We expect to recognize these costs over a weighted-average period of two years .

The total fair value of shares vested was $ 25 million in 2022, $ 22 million in 2021 and $ 22 million in 2020.

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(a) Units granted includes awards that will be cash settled of 0 in 2022, 51,074 in 2021, and 45,646 in 2020.

See below for additional information on restricted stock unit grants.

(b) Reflects the target payout level.

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The following table is a summary of the status of non-vested awards as of December 31, 2021, and changes during the year:

The following table shows the change of nonvested awards:

Restricted Stock Units, Stock Grants, and Stock Units Performance Shares

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Fair Value Shares (b) Weighted-Average

Nonvested at January 1, 2021 220,557 $ 77.93 260,004 $ 98.28

Nonvested at December 31, 2021

253,156 $ 79.37 280,682 $ 92.16

Granted 174,791 69.66 208,736 77.63

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Forfeited (c) ( 9,144 ) 76.56 ( 22,690 ) 78.29

Nonvested at December 31, 2021 253,156 (a) 79.37 280,682 92.16

Nonvested at December 31, 2022

317,587 (a) 73.91 330,694 78.91

Vested Awards Outstanding at December 31, 2022

78,912 136,034

(a) Includes 69,413 of awards that will be cash settled.

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Restricted Stock Units, Stock Grants, and Stock Units

Restricted stock units are granted to officers and key employees.

Restricted stock units typically vest and settle in equal annual installments over a 4 -year period after the grant date.

Restricted stock units are granted to officers and key employees and typically vest and settle in equal annual installments over a 4 -year period after the grant date.

Vesting is typically dependent upon continuous service during the vesting period.

however, awards granted to retirement-eligible employees will vest upon the employee’s retirement.

Awardees typically elect to receive payment in either 100 % stock, 100 % cash, or 50 % in cash and 50 % in stock.

Restricted stock unit awards typically include a dividend equivalent feature.

This feature allows each award to accrue dividend rights equal to the dividends they would have received had they directly owned the stock.

Interest on dividend rights compounds quarterly.

If the award is forfeited the employee is not entitled to the dividends on those shares.

Beginning in 2022, restricted stock unit awards are issued in stock.

Awards include a dividend equivalent feature that allows each award to accrue dividends and treat them as reinvested, from the date of grant until the applicable vesting date.

If the award is forfeited the employee is not entitled to the accrued reinvested dividends on those shares.

Awards granted to retirement-eligible employees will vest on a pro-rata basis upon the employee’s retirement.

Prior to 2022, awardees typically elected to receive payment in either 100 % stock, 100 % cash, or 50 % in cash and 50 % in stock.

Awards included a dividend equivalent feature that accrued dividend rights from the date of grant until the applicable vesting date, plus interest compounded quarterly.

If the award was forfeited the employee was not entitled to the accrued dividends on those shares.

Awards granted to retirement-eligible employees typically vested upon the employee’s retirement.

Compensation cost for restricted stock unit awards is based on the fair value of the award, with the fair value being the market price of our stock on the measurement date.

Restricted stock unit awards that will be settled in cash are accounted for as liability awards, with compensation cost initially calculated on the date of grant using the Company’s closing stock price and remeasured at each balance sheet date.

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Restricted stock unit awards that will be settled in shares are accounted for as equity awards, with compensation cost calculated using the Company’s closing stock price on the date of grant.

Compensation cost is recognized over the requisite service period based on the fair value of the award.

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Stock grants are issued to non-officer members of the Board of Directors.

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The members of the Board of Directors who elect to defer may elect to receive payment in either 100 % stock, 100 % cash, or 50 % in cash and 50 % in stock.

Each stock unit is convertible to one share of stock.

The stock units accrue dividend rights, equal to the amount of dividends the Directors would have received had they directly owned stock equal to the number of vested restricted stock units or stock units from the date of grant to the date of payment, plus interest compounded quarterly.

The dividends and interest are paid, based on the Director’s election, in either stock, cash, or 50 % in cash and 50 % in stock.

The stock units include a dividend equivalent feature that accrues dividend rights from the date of grant to the date of payment, plus interest compounded quarterly.

Performance Share Awards

Performance share awards are granted to officers and key employees.

The awards contain two separate performance criteria that affect the number of shares that may be received if after the end of a 3 -year performance period the performance criteria are met.

For the first criteria, the number of shares that will vest is based on non-financial performance metrics (i.e., the metric component).

The other criteria is based upon Pinnacle West’s total shareholder return (“TSR”) in relation to the TSR of other companies in a specified utility index (i.e., the TSR component).

The exact number of shares issued will vary from 0 % to 200 % of the target award.

Shares received include dividend rights paid in stock equal to the amount of dividends that recipients would have received had they directly owned stock, equal to the number of vested performance shares from the date of grant to the date of payment plus interest compounded quarterly.

The awards contain separate performance metric criteria that affect the number of shares that may be received if, after the end of a 3 -year performance period, the performance criteria are met.

Beginning in 2022, performance share awards contain three separate, unrelated performance criteria.

The first performance criteria is based upon Pinnacle West’s total shareholder return (“TSR”) in relation to the TSR of other companies in a specified utility index (i.e., the TSR component).

The second performance criteria is based upon Pinnacle West’s earnings per share (“EPS”) performance relative to an approved target (i.e., the EPS component).

The third performance criteria is based upon APS’s clean MW installed of renewable or other carbon free resources compared to the approved target (i.e., the Clean component).

The exact number of shares issued is calculated separately for each performance component and can vary from 0 % to 200 % of the target award for each separate performance criteria.

Shares received include a dividend equivalent feature that treats accrued dividends as reinvested, from the date of grant until the date of payment, equal to the number of vested performance shares.

If the award is forfeited or if the performance criteria are not achieved, the employee is not entitled to the dividends on those shares.

Awards granted to retirement-eligible employees will vest on a pro-rata basis upon the employee’s retirement.

Prior to 2022, performance share awards had two performance criteria.

The first performance criteria was based upon non-financial performance metrics (i.e., the Metric component).

The second performance criteria was based upon Pinnacle West’s TSR in relation to the TSR of other companies in a specified utility index (i.e., the TSR component).

The exact number of shares issued will vary from 0 % to 200 % of the target award.

Shares received included a dividend equivalent feature that allows accrued dividend rights from the date of grant until the date of payment, plus interest compounded quarterly, equal to the number of vested performance shares.

If the award was forfeited, the employee was not entitled to the accrued dividends on those shares.

Awards granted to retirement-eligible employees typically vested upon the employee’s retirement.

Performance share awards are accounted for as equity awards, with compensation cost based on the fair value of the award on the grant date.

Compensation cost relating to the metric component of the award is based on the Company’s closing stock price on the date of grant, with compensation cost recognized over the requisite service period based on the number of shares expected to vest.

Management evaluates the probability of meeting the metric component at each balance sheet date.

If the metric component criteria are not ultimately achieved, no compensation cost is recognized relating to the metric component, and any previously recognized compensation cost is reversed.

Compensation cost relating to the TSR component of the award is determined using a Monte Carlo simulation valuation model, with compensation cost recognized ratably over the requisite service period, regardless of the number of shares that actually vest.

Compensation cost relating to the EPS, Clean and Metric component of the respective awards is based on the Company’s closing stock price on the date of grant, with compensation cost recognized over the requisite service period based on the number of shares expected to vest.

Management evaluates the probability of meeting the EPS, Clean and Metric component at each balance sheet date.

If the EPS, Clean and Metric component criteria are not ultimately achieved, no

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compensation cost is recognized relating to the EPS, Clean and Metric component, and any previously recognized compensation cost is reversed.

Compensation cost relating to the TSR component of the respective awards is determined using a Monte Carlo simulation valuation model, with compensation cost recognized ratably over the requisite service period, regardless of the number of shares that actually vest.

Derivative Accounting

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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

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power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our Consolidated Statements of Income, but does not impact our financial condition, net income, or cash flows.

Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our Consolidated 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.

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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.

For its regulated operations, 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.

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):

Energy Derivatives

For its regulated operations, APS defers for future rate treatment 100 % of the unrealized gains and losses on energy derivatives pursuant to the PSA mechanism that would otherwise be recognized in income.

Realized gains and losses on energy derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate.

Gains and losses from energy 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 energy derivatives, which represent both purchases and sales (does not reflect net position):

Commodity Unit of Measure December 31, 2022 December 31, 2021

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Gas Billion cubic feet 149 155

Gains and Losses from Derivative Instruments

The following table provides information about APS’s gains and losses from derivative instruments in designated cash flow accounting hedging relationships (dollars in thousands):

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Gains and Losses from Energy Derivative Instruments

The following table provides information about APS’s gains and losses from energy derivative instruments in designated cash flow accounting hedging relationships (dollars in thousands):

Financial Statement Year Ended

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During the next twelve months, we estimate that no amounts will be reclassified from accumulated OCI into income.

For APS, the delivery period for all derivative instruments in designated cash flow accounting hedging relationships have lapsed.

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

For APS, the delivery period for all energy derivative instruments in designated cash flow accounting hedging relationships have lapsed.

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

Financial Statement Year Ended

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

Derivative Instruments in the Consolidated 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.

Energy Derivative Instruments in the Consolidated Balance Sheets

Our energy 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.

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Transactions that do not allow for offsetting of positive and negative positions are reported gross on the Consolidated 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.

We do not offset a counterparty’s current energy derivative contracts with the counterparty’s non-current energy 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).

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The following tables provide information about the fair value of our risk management activities reported on a gross basis and the impacts of offsetting.

These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Consolidated Balance Sheets.

The following tables provide information about the fair value of APS's risk management activities reported on a gross basis and the impacts of offsetting.

These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of APS's Consolidated Balance Sheets.

As of December 31, 2022:

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Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.

Includes cash collateral received from counterparties of $ 1,635 and cash margin provided to counterparties of $ 50 .

Includes cash collateral received from counterparties of $ 5,835 thousand and cash margin provided to counterparties of $ 28 thousand.

As of December 31, 2021:

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Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.

Includes cash collateral received from counterparties of $ 1,285 .

Includes cash collateral received from counterparties of $ 1,635 thousand and cash margin provided to counterparties of $ 50 thousand.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Interest Rate Derivatives

On October 19, 2022, Bright Canyon Energy entered into an interest rate swap to hedge the variable interest rate exposure relating to the Los Alamitos credit agreement.

The transaction qualifies and has been designated as cash flow hedge.

The hedge’s gain or loss is reported as a component of other comprehensive income and subsequently will be reclassified into earnings in the periods during which the related interest expense on the debt is incurred.

As of December 31, 2022, the interest rate swap has a notional value of $ 32 million with a maturity in 2041.

Relating to this derivative, our Consolidated Balance Sheet as of December 31, 2022 includes approximately $ 0.9 million reported within the liabilities from risk management activities line within the deferred credits and other section, and $ 0.1 million reported within the current assets from risk management activities line.

For the year ended December 31, 2022, the Consolidated Income Statement includes a pretax loss of approximately $ 0.8 million recognized in other comprehensive income relating to the interest rate swap.

There were no gains or losses reclassified out of accumulated other comprehensive income for the year ended December 31, 2022, and we expect no significant amounts will be reclassified into earnings over the next 12 months.

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 December 31, 2021, we have three counterparties for which our exposure represents approximately 38 % of Pinnacle West’s $ 110 million of risk management assets.

This exposure relates to master agreements with counterparties and all three are rated as investment grade.

We are exposed to losses in the event of nonperformance or nonpayment by energy derivative counterparties and have risk management contracts with many energy derivative counterparties.

As of December 31, 2022, we have two counterparties for which our exposure represents approximately 21 % of Pinnacle West’s $ 132 million of risk management assets.

This exposure relates to master agreements with the counterparties and both are rated as investment grade.

Our risk management process assesses and monitors the financial exposure of all counterparties.

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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.

Certain of our energy 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):

For those energy 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).

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

December 31, 2022

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We also have energy related non-derivative instrument contracts with investment grade credit-related contingent features, which could also require us to post additional collateral of approximately $ 76 million if our debt credit ratings were to fall below investment grade.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Other Income and Other Expense

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Debt return on Four Corners SCR deferral (Note 3)

— 14,955 15,865

Debt return on Ocotillo modernization project (Note 3)

— 23,366 26,121

Miscellaneous 590 53 149

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Non-operating costs $ ( 18,619 ) $ ( 13,008 ) $ ( 12,400 )

Investment gains (losses) — net ( 1,367 ) — ( 1,835 )

Miscellaneous ( 11,021 ) ( 45,376 ) (a) ( 5,382 )

Investment gains (losses) — net ( 20,537 ) (b) ( 1,367 ) —

Miscellaneous ( 13,229 ) (a) ( 11,021 ) ( 45,376 ) (a)

Total other expense $ ( 52,385 ) $ ( 25,396 ) $ ( 57,776 )

(a) The 2020 miscellaneous amount includes donations of approximately $ 10 million to the APS Foundation and approximately $ 25.2 million related to the CCT plan.

(a) The 2022 miscellaneous amount includes donations of $ 7 million to the APS Foundation.

The 2020 miscellaneous amount includes donations of approximately $ 10 million to the APS Foundation and approximately $ 25.2 million related to the CCT plan.

(b) The 2022 investment loss is primarily related to an impairment write-off of BCE’s Clear Creek wind farm investment.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Other Income and Other Expense - APS

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Debt return on Four Corners SCR deferral (Note 3)

— 14,955 15,865

Debt return on Ocotillo modernization project (Note 3)

— 23,366 26,121

Miscellaneous 556 40 148

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Non-operating costs $ ( 15,579 ) $ ( 10,080 ) $ ( 10,659 )

Miscellaneous ( 8,817 ) ( 43,035 ) (a) ( 3,378 )

Miscellaneous ( 10,529 ) (a) ( 8,817 ) ( 43,035 ) (a)

Total other expense $ ( 26,108 ) $ ( 18,897 ) $ ( 53,694 )

(a) The 2020 miscellaneous amount includes donations of approximately $ 10 million to the APS Foundation and approximately $ 25.2 million related to the CCT plan.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(a) The 2022 miscellaneous amount includes donations of $ 7 million to the APS Foundation.

The 2020 miscellaneous amount includes donations of approximately $ 10 million to the APS Foundation and approximately $ 25.2 million related to the CCT plan.

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.

Prior to April 1, 2021, the lease terms allowed APS the right to retain the assets through 2023 under one lease and 2033 under the other two leases.

On April 1, 2021, APS executed an amended lease agreement with one of the VIE lessor trust entities relating to the lease agreement with the term ending in 2023.

The amendment extends the lease term for this lease through 2033 and changes the lease payment.

As a result of this amendment, APS will now retain the assets through 2033 under all three lease agreements.

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.

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Predominantly due to the lease terms, APS has been deemed the primary beneficiary of these VIEs and therefore consolidates the VIEs.

As a result of consolidation, we eliminate lease accounting and instead recognize depreciation expense, resulting in an increase in net income of $ 17 million for 2021, and $ 19 million for 2020 and 2019.

As a result of consolidation, we eliminate lease accounting and instead recognize depreciation expense, resulting in an increase in net income of $ 17 million for 2022, $ 17 million for 2021 and $ 19 million for 2020.

The increase in net income is entirely attributable to the noncontrolling interests.

Income attributable to Pinnacle West shareholders is not impacted by the consolidation.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Our Consolidated Balance Sheets include the following amounts relating to the VIEs (dollars in thousands):

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For regulatory ratemaking purposes, the agreements continue to be treated as operating leases and, as a result, we have recorded a regulatory asset relating to the arrangements.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Investments in Nuclear Decommissioning Trusts and Other Special Use Funds

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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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

regulatory liabilities.

Activities relating to APS coal mine reclamation escrow account investments are included within the other special use funds in the table below.

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These investments may be used to pay active union employee medical costs incurred in the current and future periods.

In 2021 and 2020, APS was reimbursed $ 15 million and $ 14 million, respectively, for prior year active union employee medical claims from the active union employee medical account.

In 2022 and 2021, APS was reimbursed $ 15 million for each year, for prior year active union employee medical claims from the active union employee medical account.

The account is invested primarily in fixed income securities.

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Activities relating to active union employee medical account investments are included within the other special use funds in the table below.

On January 4, 2021, an additional $ 106 million of investments were transferred from APS other postretirement benefit trust assets into the active union employee medical account, see Note 8.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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):

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OCI (loss) before reclassifications 17,550 1,873 19,423

Amounts reclassified from accumulated other comprehensive loss 4,401 (a) 18 (b) 4,419

Amounts reclassified from accumulated other comprehensive loss 4,003 (a) — 4,003

Balance at December 31, 2022 $ ( 32,332 ) $ 897 $ ( 31,435 )

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OCI (loss) before reclassifications 15,646 — 15,646

Amounts reclassified from accumulated other comprehensive loss 3,995 (a) 18 (b) 4,013

Amounts reclassified from accumulated other comprehensive loss 3,638 (a) — 3,638

Balance at December 31, 2022 $ ( 15,596 ) $ — $ ( 15,596 )

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Long-term debt less current maturities (Note 6)

947,892 647,139

Pension liabilities 8,218 14,537

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Advances of loans to subsidiaries ( 3,308 ) ( 12,256 ) ( 7,261 )

Net cash flow provided by (used for) investing activities ( 153,505 ) ( 144,210 ) 1,582

Net cash flow used for investing activities ( 175,630 ) ( 153,505 ) ( 144,210 )

Cash flows from financing activities

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 8. Financial Statements and Supplementary Data