UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 

FORM 10-Q
 
(Mark One)
 
☒QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the quarterly period ended March 31, 20202021
 
OR
 
☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from              to          
 
Commission File

Number
Exact Name of Each Registrant as specified in its

charter; State of Incorporation; Address; and

Telephone Number
IRS Employer

Identification No.
1-8962PINNACLE WEST CAPITAL CORPORATION86-0512431
(an Arizona corporation)
400 North Fifth Street, P.O. Box 53999
PhoenixArizona85072-3999
(602)250-1000
1-4473ARIZONA PUBLIC SERVICE COMPANY86-0011170
(an Arizona corporation)
400 North Fifth Street, P.O. Box 53999
PhoenixArizona85072-3999
(602)250-1000
 
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common StockPNWThe New York Stock Exchange

Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
 
PINNACLE WEST CAPITAL CORPORATIONYes
☒ 
No 
☐ 
ARIZONA PUBLIC SERVICE COMPANYYes
☒ 
No 
☐ 
 
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
PINNACLE WEST CAPITAL CORPORATIONYes
☒ 
No 
☐ 
ARIZONA PUBLIC SERVICE COMPANYYes
☒ 
No 
☐ 
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company or an emerging growth company.  See the definitions of "large“large accelerated filer," "accelerated” “accelerated filer," "smaller” “smaller reporting company,"” and "emerging“emerging growth company"company” in Rule 12b-2 of the Exchange Act.

 PINNACLE WEST CAPITAL CORPORATION
Large accelerated filer
☒
Accelerated filer☐Non-accelerated filer☐Smaller reporting company☐
Large accelerated filer
☒
Accelerated filer☐Non-accelerated filer☐Smaller reporting company☐
Emerging growth company☐
 
ARIZONA PUBLIC SERVICE COMPANY
Large accelerated filer☐Accelerated filer☐Non-accelerated filer
☒
Smaller reporting company☐
Large accelerated filer☐Accelerated filer☐Non-accelerated filer
☒
Smaller reporting company☐
Emerging growth company☐
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether each registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
PINNACLE WEST CAPITAL CORPORATIONYes  ☐No 
☒ 
ARIZONA PUBLIC SERVICE COMPANYYes    ☐No 
☒ 
 
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
 
PINNACLE WEST CAPITAL CORPORATIONNumber of shares of common stock, no par value, outstanding as of May 1, 2020:April 28, 2021:112,493,458112,750,962
ARIZONA PUBLIC SERVICE COMPANY
Number of shares of common stock, $2.50 par value, outstanding as of May 1April 28, 2021:, 2020:
71,264,947
 
Arizona Public Service Company meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this form with the reduced disclosure format allowed under that General Instruction.





TABLE OF CONTENTS
Page
2
4
Item 1.
4
Pinnacle West Capital Corporation
5
Arizona Public Service Company
11
Item 2.
6566
Item 3.
8488
Item 4.
8589
8690
Item 1.
8690
Item 1A.
8690
Item 5.
8690
Item 6.
8891
9093
 
This combined Form 10-Q is separately provided by Pinnacle West Capital Corporation ("(“Pinnacle West"West”) and Arizona Public Service Company ("APS"(“APS”).  Any use of the words "Company," "we,"“Company,” “we,” and "our"“our” refer to Pinnacle West.  Each registrant is providing on its own behalf all of the information contained in this Form 10-Q that relates to such registrant and, where required, its subsidiaries.  Except as stated in the preceding sentence, neither registrant is providing any information that does not relate to such registrant, and therefore makes no representation as to any such information.  The information required with respect to each company is set forth within the applicable items.  Item 1 of this report includes Condensed Consolidated Financial Statements of Pinnacle West and Condensed Consolidated Financial Statements of APS.  Item 1 also includes Combined Notes to Condensed Consolidated Financial Statements.


1

FORWARD-LOOKING STATEMENTS
This document contains forward-looking statements based on current expectations.  These forward-looking statements are often identified by words such as "estimate," "predict," "may," "believe," "plan," "expect," "require," "intend," "assume," "project," "anticipate," "goal," "seek," "strategy," "likely," "should," "will," "could,"“estimate,” “predict,” “may,” “believe,” “plan,” “expect,” “require,” “intend,” “assume,” “project,” “anticipate,” “goal,” “seek,” “strategy,” “likely,” “should,” “will,” “could,” and similar words.  Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements.  A number of factors could cause future results to differ materially from historical results, or from outcomes currently expected or sought by Pinnacle West or APS.  In addition to the Risk Factors described in Part I, Item 1A of the Pinnacle West/APS Annual Report on Form 10-K for the fiscal year ended December 31, 2019 ("20192020 (“2020 Form 10-K"10-K”), Part II, Item 1A of this report and in Part I, Item 2 — "Management’s“Management’s Discussion and Analysis of Financial Condition and Results of Operations"Operations” of this report, these factors include, but are not limited to:
•the potential effects of the continued Coronavirus ("(“COVID-19") pandemic, including, but not limited to, those described in Part II, Item 1A "Risk Factors" herein;demand for energy, economic growth, our employees and contractors, supply chain, expenses, capital markets, capital projects, operations and maintenance activities, uncollectable accounts, liquidity, cash flows or other unpredictable events;
•our ability to manage capital expenditures and operations and maintenance costs while maintaining reliability and customer service levels;
•variations in demand for electricity, including those due to weather, seasonality, the general economy or social conditions, customer and sales growth (or decline), the effects of energy conservation measures and distributed generation, and technological advancements;
•power plant and transmission system performance and outages;
•competition in retail and wholesale power markets;
•regulatory and judicial decisions, developments and proceedings;
•new legislation, ballot initiatives and regulation, including those relating to environmental requirements, regulatory and energy policy, nuclear plant operations and potential deregulation of retail electric markets;
•fuel and water supply availability;
•our ability to achieve timely and adequate rate recovery of our costs through our rates and adjustor recovery mechanisms, including returns on and of debt and equity capital investment;
•our ability to meet renewable energy and energy efficiency mandates and recover related costs;
•the ability of APS to achieve its clean energy goals (including a goal by 2050 of 100% clean, carbon-free electricity) and, if these goals are achieved, the impact of such achievement on APS, its customers, and its business, financial condition and results of operations;
•risks inherent in the operation of nuclear facilities, including spent fuel disposal uncertainty;
•current and future economic conditions in Arizona, including in real estate markets;
•
•the direct or indirect effect on our facilities or business from cybersecurity threats or intrusions, data security breaches, terrorist attack, physical attack, severe storms, droughts, or other catastrophic events, such as fires, explosions, pandemic health events, or similar occurrences;
•, or similar occurrences;
the development of new technologies which may affect electric sales or delivery;
•the cost of debt and equity capital and the ability to access capital markets when required;
•environmental, economic and other concerns surrounding coal-fired generation, including regulation of greenhouse gas emissions;
•volatile fuel and purchased power costs;
•the investment performance of the assets of our nuclear decommissioning trust, pension, and other postretirement benefit plans and the resulting impact on future funding requirements;
•the liquidity of wholesale power markets and the use of derivative contracts in our business;
•potential shortfalls in insurance coverage;
•new accounting requirements or new interpretations of existing requirements;
•generation, transmission and distribution facility and system conditions and operating costs;
•the ability to meet the anticipated future need for additional generation and associated transmission facilities in our region;
•the willingness or ability of our counterparties, power plant participants and power plant land ownerslandowners to meet contractual or other obligations or extend the rights for continued power plant operations; and
2

•restrictions on dividends or other provisions in our credit agreements and Arizona Corporation Commission ("ACC"(“ACC”) orders. 


These and other factors are discussed in the Risk Factors described in Part I, Item 1A of our 20192020 Form 10-K, in Part II, Item 1A of this report, and in Part I, Item 2 — "Management’s“Management’s Discussion and Analysis of Financial Condition and Results of Operations"Operations” of this report, which readers should review carefully before placing any reliance on our financial statements or disclosures.  Neither Pinnacle West nor APS assumes any obligation to update these statements, even if our internal estimates change, except as required by law.

3

PART I — FINANCIAL INFORMATION
 
ITEM 1.  FINANCIAL STATEMENTS
 
 INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
 
Page
5
6
7
9
10
11
12
13
15
16
17
17
18
20
2122
3840
3942
4043
4547
5254
5355
5355
5960
Note 13. New Accounting Standards
61
6263
6365
Note 16. Asset Retirement Obligations
64



4


PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(dollars and shares in thousands, except per share amounts)
 
 Three Months Ended
March 31,		 Three Months Ended
March 31,
 2020 2019 20212020
    
OPERATING REVENUES (NOTE 2) $661,930
 $740,530
OPERATING REVENUES (NOTE 2)$696,475 $661,930 
    
OPERATING EXPENSES  
  
OPERATING EXPENSES  
Fuel and purchased power 188,521
 230,588
Fuel and purchased power198,227 188,521 
Operations and maintenance 221,318
 245,634
Operations and maintenance230,055 221,318 
Depreciation and amortization 154,079
 148,707
Depreciation and amortization157,820 154,079 
Taxes other than income taxes 56,768
 55,090
Taxes other than income taxes59,483 56,768 
Other expenses 822
 427
Other expenses3,356 822 
Total 621,508
 680,446
Total648,941 621,508 
OPERATING INCOME 40,422
 60,084
OPERATING INCOME47,534 40,422 
OTHER INCOME (DEDUCTIONS)  
  
OTHER INCOME (DEDUCTIONS)  
Allowance for equity funds used during construction 7,697
 11,188
Allowance for equity funds used during construction9,207 7,697 
Pension and other postretirement non-service credits - net 13,911
 5,114
Pension and other postretirement non-service credits — netPension and other postretirement non-service credits — net27,791 13,911 
Other income (Note 9) 12,569
 7,169
Other income (Note 9)12,429 12,569 
Other expense (Note 9) (4,784) (4,358)Other expense (Note 9)(3,853)(4,784)
Total 29,393
 19,113
Total45,574 29,393 
INTEREST EXPENSE  
  
INTEREST EXPENSE  
Interest charges 59,234
 60,653
Interest charges61,938 59,234 
Allowance for borrowed funds used during construction (4,076) (6,665)Allowance for borrowed funds used during construction(4,994)(4,076)
Total 55,158
 53,988
Total56,944 55,158 
INCOME BEFORE INCOME TAXES 14,657
 25,209
INCOME BEFORE INCOME TAXES36,164 14,657 
INCOME TAXES (20,209) 2,418
INCOME TAXES(4,350)(20,209)
NET INCOME 34,866
 22,791
NET INCOME40,514 34,866 
Less: Net income attributable to noncontrolling interests (Note 6) 4,873
 4,873
Less: Net income attributable to noncontrolling interests (Note 6)4,873 4,873 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $29,993
 $17,918
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS$35,641 $29,993 
    
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC 112,594
 112,337
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC112,829 112,594 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED 112,862
 112,735
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED113,093 112,862 
    
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING  
  
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING  
Net income attributable to common shareholders — basic $0.27
 $0.16
Net income attributable to common shareholders — basic$0.32 $0.27 
Net income attributable to common shareholders — diluted $0.27
 $0.16
Net income attributable to common shareholders — diluted$0.32 $0.27 
 
The accompanying notes are an integral part of the financial statements.

5

PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(unaudited)
(dollars in thousands)
 
Three Months Ended
March 31,		 Three Months Ended
March 31,
2020 2019 20212020
   
NET INCOME$34,866
 $22,791
NET INCOME$40,514 $34,866 
   
OTHER COMPREHENSIVE INCOME, NET OF TAX 
  
OTHER COMPREHENSIVE INCOME, NET OF TAX  
Derivative instruments: 
  
Derivative instruments:  
Net unrealized gain, net of tax expense of $292 and $0292
 —
Reclassification of net realized loss, net of tax benefit of $394 and $10820
 328
Pension and other postretirement benefits activity, net of tax expense of $245 and $2881,205
 879
Net unrealized gain, net of tax (expense) benefit of $(86) and $292Net unrealized gain, net of tax (expense) benefit of $(86) and $292262 292 
Reclassification of net realized gain, net of tax expense of $0 and $394Reclassification of net realized gain, net of tax expense of $0 and $3940 20 
Pension and other postretirement benefit activity, net of tax expense of $336 and $245Pension and other postretirement benefit activity, net of tax expense of $336 and $2451,022 1,205 
Total other comprehensive income1,517
 1,207
Total other comprehensive income1,284 1,517 
   
COMPREHENSIVE INCOME36,383
 23,998
COMPREHENSIVE INCOME41,798 36,383 
Less: Comprehensive income attributable to noncontrolling interests4,873
 4,873
Less: Comprehensive income attributable to noncontrolling interests4,873 4,873 
   
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS$31,510
 $19,125
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS$36,925 $31,510 
 
The accompanying notes are an integral part of the financial statements.


6

PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(dollars in thousands)
 
March 31, 2020 December 31, 2019 March 31, 2021December 31, 2020
ASSETS 
  
ASSETS  
   
CURRENT ASSETS 
  
CURRENT ASSETS  
Cash and cash equivalents$63,139
 $10,283
Cash and cash equivalents$17,202 $59,968 
Customer and other receivables258,874
 266,426
Customer and other receivables263,126 313,576 
Accrued unbilled revenues93,434
 128,165
Accrued unbilled revenues122,034 132,197 
Allowance for doubtful accounts(8,366) (8,171)Allowance for doubtful accounts(20,405)(19,782)
Materials and supplies (at average cost)323,545
 331,091
Materials and supplies (at average cost)314,702 314,745 
Fossil fuel (at average cost)16,930
 14,829
Fossil fuel (at average cost)24,396 19,552 
Income tax receivable20,599
 21,727
Income tax receivable0 6,792 
Assets from risk management activities (Note 7)2,108
 515
Assets from risk management activities (Note 7)22,611 2,931 
Deferred fuel and purchased power regulatory asset (Note 4)77,730
 70,137
Deferred fuel and purchased power regulatory asset (Note 4)228,609 175,835 
Other regulatory assets (Note 4)147,741
 133,070
Other regulatory assets (Note 4)111,271 115,878 
Other current assets82,573
 61,958
Other current assets86,238 76,627 
Total current assets1,078,307
 1,030,030
Total current assets1,169,784 1,198,319 
INVESTMENTS AND OTHER ASSETS 
  
INVESTMENTS AND OTHER ASSETS  
Nuclear decommissioning trust (Notes 11 and 12)920,426
 1,010,775
Nuclear decommissioning trust (Notes 11 and 12)1,159,699 1,138,435 
Other special use funds (Notes 11 and 12)252,723
 245,095
Other special use funds (Notes 11 and 12)357,506 254,509 
Other assets97,822
 96,953
Other assets88,487 92,922 
Total investments and other assets1,270,971
 1,352,823
Total investments and other assets1,605,692 1,485,866 
PROPERTY, PLANT AND EQUIPMENT 
  
PROPERTY, PLANT AND EQUIPMENT  
Plant in service and held for future use19,930,983
 19,836,292
Plant in service and held for future use20,948,591 20,837,885 
Accumulated depreciation and amortization(6,784,467) (6,637,857)Accumulated depreciation and amortization(7,189,708)(7,110,310)
Net13,146,516
 13,198,435
Net13,758,883 13,727,575 
Construction work in progress942,258
 808,133
Construction work in progress1,056,991 937,384 
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)100,938
 101,906
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)97,068 98,036 
Intangible assets, net of accumulated amortization279,238
 290,564
Intangible assets, net of accumulated amortization278,226 282,570 
Nuclear fuel, net of accumulated amortization168,457
 123,500
Nuclear fuel, net of accumulated amortization124,533 113,645 
Total property, plant and equipment14,637,407
 14,522,538
Total property, plant and equipment15,315,701 15,159,210 
DEFERRED DEBITS 
  
DEFERRED DEBITS  
Regulatory assets (Note 4)1,302,448
 1,304,073
Regulatory assets (Note 4)1,135,857 1,133,987 
Operating lease right-of-use assets144,380
 145,813
Operating lease right-of-use assets502,959 505,064 
Assets for other postretirement benefits (Note 5)96,243
 90,570
Assets for pension and other postretirement benefits (Note 5)Assets for pension and other postretirement benefits (Note 5)418,427 502,992 
Other32,004
 33,400
Other36,238 34,983 
Total deferred debits1,575,075
 1,573,856
Total deferred debits2,093,481 2,177,026 
   
TOTAL ASSETS$18,561,760
 $18,479,247
TOTAL ASSETS$20,184,658 $20,020,421 
 
The accompanying notes are an integral part of the financial statements.


7

PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(dollars in thousands)
March 31, 2020 December 31, 2019 March 31, 2021December 31, 2020
LIABILITIES AND EQUITY 
  
LIABILITIES AND EQUITY  
   
CURRENT LIABILITIES 
  
CURRENT LIABILITIES  
Accounts payable$301,325
 $346,448
Accounts payable$309,145 $318,585 
Accrued taxes194,732
 144,899
Accrued taxes213,536 159,551 
Accrued interest53,608
 53,534
Accrued interest58,709 56,962 
Common dividends payable—
 87,982
Common dividends payable0 93,531 
Short-term borrowings (Note 3)563,000
 114,675
Short-term borrowings (Note 3)214,750 169,000 
Current maturities of long-term debt (Note 3)650,000
 800,000
Customer deposits54,965
 64,908
Customer deposits45,170 48,340 
Liabilities from risk management activities (Note 7)54,784
 38,946
Liabilities from risk management activities (Note 7)3,067 7,557 
Liabilities for asset retirements10,095
 11,025
Liabilities for asset retirements16,021 15,586 
Operating lease liabilities12,360
 12,713
Operating lease liabilities74,328 74,785 
Regulatory liabilities (Note 4)279,105
 234,912
Regulatory liabilities (Note 4)250,228 229,088 
Other current liabilities121,514
 168,323
Other current liabilities145,589 187,448 
Total current liabilities2,295,488
 2,078,365
Total current liabilities1,330,543 1,360,433 
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 3)4,833,324
 4,832,558
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 3)6,465,045 6,314,266 
DEFERRED CREDITS AND OTHER 
  
DEFERRED CREDITS AND OTHER  
Deferred income taxes2,016,770
 1,992,339
Deferred income taxes2,134,471 2,135,403 
Regulatory liabilities (Note 4)2,067,801
 2,267,835
Regulatory liabilities (Note 4)2,427,769 2,450,169 
Liabilities for asset retirements649,226
 646,193
Liabilities for asset retirements693,383 689,497 
Liabilities for pension benefits (Note 5)273,284
 280,185
Liabilities for pension benefits (Note 5)164,230 166,484 
Liabilities from risk management activities (Note 7)32,577
 33,186
Liabilities from risk management activities (Note 7)6,928 11,062 
Customer advances212,545
 215,330
Customer advances220,999 221,032 
Coal mine reclamation166,796
 165,695
Coal mine reclamation171,227 170,097 
Deferred investment tax credit196,002
 196,468
Deferred investment tax credit190,842 191,372 
Unrecognized tax benefits6,400
 6,189
Unrecognized tax benefits5,870 5,834 
Operating lease liabilities51,198
 51,872
Operating lease liabilities360,497 361,336 
Other163,517
 159,844
Other206,174 190,643 
Total deferred credits and other5,836,116
 6,015,136
Total deferred credits and other6,582,390 6,592,929 
COMMITMENTS AND CONTINGENCIES (SEE NOTE 8)


 


COMMITMENTS AND CONTINGENCIES (NOTE 8)COMMITMENTS AND CONTINGENCIES (NOTE 8)00
EQUITY 
  
EQUITY  
Common stock, no par value; authorized 150,000,000 shares, 112,563,610 and 112,540,126 issued at respective dates2,664,387
 2,659,561
Treasury stock at cost; 72,302 and 103,546 shares at respective dates(7,000) (9,427)
Common stock, no par value; authorized 150,000,000 shares, 112,791,565 and 112,760,051 issued at respective datesCommon stock, no par value; authorized 150,000,000 shares, 112,791,565 and 112,760,051 issued at respective dates2,687,052 2,677,482 
Treasury stock at cost; 44,338 and 72,006 shares at respective datesTreasury stock at cost; 44,338 and 72,006 shares at respective dates(3,776)(6,289)
Total common stock2,657,387
 2,650,134
Total common stock2,683,276 2,671,193 
Retained earnings2,867,610
 2,837,610
Retained earnings3,060,752 3,025,106 
Accumulated other comprehensive loss(55,579) (57,096)Accumulated other comprehensive loss(61,512)(62,796)
Total shareholders’ equity5,469,418
 5,430,648
Total shareholders’ equity5,682,516 5,633,503 
Noncontrolling interests (Note 6)127,414
 122,540
Noncontrolling interests (Note 6)124,164 119,290 
Total equity5,596,832
 5,553,188
Total equity5,806,680 5,752,793 
   
TOTAL LIABILITIES AND EQUITY$18,561,760
 $18,479,247
TOTAL LIABILITIES AND EQUITY$20,184,658 $20,020,421 
The accompanying notes are an integral part of the financial statements.

8

PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(dollars in thousands)
Three Months Ended
March 31,		 Three Months Ended
March 31,
2020 2019 20212020
CASH FLOWS FROM OPERATING ACTIVITIES 
  
CASH FLOWS FROM OPERATING ACTIVITIES  
Net income$34,866
 $22,791
Net income$40,514 $34,866 
Adjustments to reconcile net income to net cash provided by operating activities: 
  
Adjustments to reconcile net income to net cash provided by operating activities:  
Depreciation and amortization including nuclear fuel173,168
 167,801
Depreciation and amortization including nuclear fuel176,409 173,168 
Deferred fuel and purchased power(5,785) 16,709
Deferred fuel and purchased power(52,210)(5,785)
Deferred fuel and purchased power amortization(1,808) 12,872
Deferred fuel and purchased power amortization(564)(1,808)
Allowance for equity funds used during construction(7,697) (11,188)Allowance for equity funds used during construction(9,207)(7,697)
Deferred income taxes(18,086) 3,620
Deferred income taxes(11,077)(18,086)
Deferred investment tax credit(465) (353)Deferred investment tax credit(529)(465)
Stock compensation6,282
 12,074
Stock compensation11,337 6,282 
Changes in current assets and liabilities: 
  
Changes in current assets and liabilities:  
Customer and other receivables25,575
 15,476
Customer and other receivables50,545 25,575 
Accrued unbilled revenues34,731
 23,093
Accrued unbilled revenues10,163 34,731 
Materials, supplies and fossil fuel5,445
 (13,057)Materials, supplies and fossil fuel(4,801)5,445 
Income tax receivable1,128
 —
Income tax receivable6,792 1,128 
Other current assets(20,202) (10,115)Other current assets(9,042)(20,202)
Accounts payable(5,192) 26,593
Accounts payable24,465 (5,192)
Accrued taxes49,833
 45,130
Accrued taxes53,985 49,833 
Other current liabilities(63,096) (86,250)Other current liabilities(46,028)(63,096)
Change in other long-term assets81,143
 (65,470)Change in other long-term assets(36,777)81,143 
Change in other long-term liabilities(106,212) 13,706
Change in other long-term liabilities(1,963)(106,212)
Net cash flow provided by operating activities183,628
 173,432
Net cash flow provided by operating activities202,012 183,628 
CASH FLOWS FROM INVESTING ACTIVITIES   
CASH FLOWS FROM INVESTING ACTIVITIES 
Capital expenditures(340,014) (259,792)Capital expenditures(363,775)(340,014)
Contributions in aid of construction3,152
 7,938
Contributions in aid of construction15,296 3,152 
Allowance for borrowed funds used during construction(4,076) (6,665)Allowance for borrowed funds used during construction(4,994)(4,076)
Proceeds from nuclear decommissioning trust sales and other special use funds195,087
 179,048
Proceeds from nuclear decommissioning trust sales and other special use funds379,978 195,087 
Investment in nuclear decommissioning trust and other special use funds(195,658) (179,618)Investment in nuclear decommissioning trust and other special use funds(380,548)(195,658)
Other349
 4,576
Other5,974 349 
Net cash flow used for investing activities(341,160) (254,513)Net cash flow used for investing activities(348,069)(341,160)
CASH FLOWS FROM FINANCING ACTIVITIES 
  
CASH FLOWS FROM FINANCING ACTIVITIES  
Issuance of long-term debt—
 497,324
Issuance of long-term debt150,000 0 
Short-term borrowing and payments — net(76,675) 172,650
Short-term debt borrowings751,690
 —
Short-term debt repayments(226,690) (5,000)
Short-term borrowing and (repayments) — netShort-term borrowing and (repayments) — net49,750 (76,675)
Short-term debt borrowings under revolving credit facilityShort-term debt borrowings under revolving credit facility0 751,690 
Short-term debt repayments under revolving credit facilityShort-term debt repayments under revolving credit facility(4,000)(226,690)
Dividends paid on common stock(86,257) (80,897)Dividends paid on common stock(91,721)(86,257)
Repayment of long-term debt(150,000) (500,000)Repayment of long-term debt0 (150,000)
Common stock equity issuance - net of purchases(1,680) (2,653)
Common stock equity issuance — net of purchasesCommon stock equity issuance — net of purchases(738)(1,680)
Net cash flow provided by financing activities210,388
 81,424
Net cash flow provided by financing activities103,291 210,388 
NET INCREASE IN CASH AND CASH EQUIVALENTS52,856
 343
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTSNET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS(42,766)52,856 
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD10,283
 5,766
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD59,968 10,283 
CASH AND CASH EQUIVALENTS AT END OF PERIOD$63,139
 $6,109
CASH AND CASH EQUIVALENTS AT END OF PERIOD$17,202 $63,139 
The accompanying notes are an integral part of the financial statements.

9

PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(unaudited)
(dollars in thousands)
Three Months Ended March 31, 2021
Common StockTreasury StockRetained EarningsAccumulated Other Comprehensive Income (Loss)Noncontrolling InterestsTotal
SharesAmountSharesAmount
Balance, January 1, 2021112,760,051 $2,677,482 (72,006)$(6,289)$3,025,106 $(62,796)$119,290 $5,752,793 
Net income— — 35,641 — 4,873 40,514 
Other comprehensive income— — — 1,284 — 1,284 
Dividends on common stock— — 5 — — 5 
Issuance of common stock31,514 9,570 — — — 9,570 
Purchase of treasury stock (a)— (17,437)(1,333)— — — (1,333)
Reissuance of treasury stock for stock-based compensation and other— 45,105 3,846 — — — 3,846 
Other— — — — 1 1 
Balance, March 31, 2021112,791,565 $2,687,052 (44,338)$(3,776)$3,060,752 $(61,512)$124,164 $5,806,680 
Three Months Ended March 31, 2020Three Months Ended March 31, 2020
Common Stock Treasury Stock Retained Earnings Accumulated Other Comprehensive Income (Loss) Noncontrolling Interests TotalCommon StockTreasury StockRetained EarningsAccumulated Other Comprehensive Income (Loss)Noncontrolling InterestsTotal
Shares Amount Shares Amount        SharesAmountSharesAmount
Balance, January 1, 2020112,540,126
 $2,659,561
 (103,546) $(9,427) $2,837,610
 $(57,096) $122,540
 $5,553,188
Balance, January 1, 2020112,540,126 $2,659,561 (103,546)$(9,427)$2,837,610 $(57,096)$122,540 $5,553,188 
Net income  —
   —
 29,993
 —
 4,873
 34,866
Net income— — 29,993 — 4,873 34,866 
Other comprehensive income  —
   —
 —
 1,517
 —
 1,517
Other comprehensive income— — — 1,517 — 1,517 
Dividends on common stock  —
   —
 8
 —
 —
 8
Dividends on common stock— — 8 — — 8 
Issuance of common stock23,484
 4,826
   

 —
 —
 —
 4,826
Issuance of common stock23,484 4,826 — — — — 4,826 
Purchase of treasury stock (a)  —
 (20,724) (2,086) —
 —
 —
 (2,086)Purchase of treasury stock (a)(20,724)(2,086)(2,086)
Reissuance of treasury stock for stock-based compensation and other  —
 51,968
 4,513
 —
 —
 —
 4,513
Reissuance of treasury stock for stock-based compensation and other— 51,968 4,513 — — — 4,513 
Other  —
 —
 —
 (1) —
 1
 —
Other— — (1)— 1 0 
Balance, March 31, 2020112,563,610
 $2,664,387
 (72,302) $(7,000) $2,867,610
 $(55,579) $127,414
 $5,596,832
Balance, March 31, 2020112,563,610 $2,664,387 (72,302)$(7,000)$2,867,610 (55,579)$127,414 $5,596,832 

(a)Primarily represents shares of common stock withheld from certain stock awards for tax purposes.
 Three Months Ended March 31, 2019
 Common Stock Treasury Stock Retained Earnings Accumulated Other Comprehensive Income (Loss) Noncontrolling Interests Total
 Shares Amount Shares Amount        
Balance, January 1, 2019112,159,896
 $2,634,265
 (58,135) $(4,825) $2,641,183
 $(47,708) $125,790
 $5,348,705
Net income  —
   —
 17,918
 —
 4,873
 22,791
Other comprehensive income  —
   —
 —
 1,207
 —
 1,207
Dividends on common stock  —
   —
 (15) —
 —
 (15)
Issuance of common stock180,426
 9,798
   —
 —
 —
 —
 9,798
Purchase of treasury stock (a)  —
 (75,791) (6,882) —
 —
 —
 (6,882)
Reissuance of treasury stock for stock-based compensation and other  —
 70,655
 6,121
 —
 —
 —
 6,121
Balance, March 31, 2019112,340,322
 $2,644,063
 (63,271) $(5,586) $2,659,086
 $(46,501) $130,663
 $5,381,725

(a)Primarily represents shares of common stock withheld from certain stock awards for tax purposes.
    
The accompanying notes are an integral part of the financial statements.








10


ARIZONA PUBLIC SERVICE COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(dollars in thousands)
 
 Three Months Ended
March 31,		 Three Months Ended
March 31,
 2020 2019 20212020
    
OPERATING REVENUES (NOTE 2) $661,930
 $740,530
OPERATING REVENUES (NOTE 2)$696,475 $661,930 
    
OPERATING EXPENSES  
  
OPERATING EXPENSES  
Fuel and purchased power 188,521
 230,588
Fuel and purchased power198,227 188,521 
Operations and maintenance 218,265
 240,375
Operations and maintenance226,401 218,265 
Depreciation and amortization 154,058
 148,685
Depreciation and amortization157,800 154,058 
Taxes other than income taxes 56,758
 55,078
Taxes other than income taxes59,472 56,758 
Other expenses 822
 427
Other expenses3,356 822 
Total 618,424
 675,153
Total645,256 618,424 
OPERATING INCOME 43,506
 65,377
OPERATING INCOME51,219 43,506 
OTHER INCOME (DEDUCTIONS)  
  
OTHER INCOME (DEDUCTIONS)  
Allowance for equity funds used during construction 7,697
 11,188
Allowance for equity funds used during construction9,207 7,697 
Pension and other postretirement non-service credits - net 14,262
 5,499
Pension and other postretirement non-service credits — netPension and other postretirement non-service credits — net27,837 14,262 
Other income (Note 9) 11,633
 6,416
Other income (Note 9)11,960 11,633 
Other expense (Note 9) (4,668) (3,878)Other expense (Note 9)(3,350)(4,668)
Total 28,924
 19,225
Total45,654 28,924 
INTEREST EXPENSE  
  
INTEREST EXPENSE  
Interest charges 55,736
 56,665
Interest charges59,388 55,736 
Allowance for borrowed funds used during construction (4,076) (6,665)Allowance for borrowed funds used during construction(4,994)(4,076)
Total 51,660
 50,000
Total54,394 51,660 
INCOME BEFORE INCOME TAXES 20,770
 34,602
INCOME BEFORE INCOME TAXES42,479 20,770 
INCOME TAXES (19,448) 1,453
INCOME TAXES2,319 (19,448)
NET INCOME 40,218
 33,149
NET INCOME40,160 40,218 
Less: Net income attributable to noncontrolling interests (Note 6) 4,873
 4,873
Less: Net income attributable to noncontrolling interests (Note 6)4,873 4,873 
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER $35,345
 $28,276
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER$35,287 $35,345 
 
The accompanying notes are an integral part of the financial statements.

11

ARIZONA PUBLIC SERVICE COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(unaudited)
(dollars in thousands)
 
Three Months Ended
March 31,		 Three Months Ended
March 31,
2020 2019 20212020
   
NET INCOME$40,218
 $33,149
NET INCOME$40,160 $40,218 
   
OTHER COMPREHENSIVE INCOME, NET OF TAX 
  
OTHER COMPREHENSIVE INCOME, NET OF TAX  
Derivative instruments: 
  
Derivative instruments:  
Net unrealized gain, net of tax expense of $292 and $0292
 —
Reclassification of net realized loss, net of tax benefit of $394 and $10820
 328
Pension and other postretirement benefits activity, net of tax expense of $237 and $2471,013
 752
Net unrealized gain, net of tax benefit of $0 and $292Net unrealized gain, net of tax benefit of $0 and $2920 292 
Reclassification of net realized loss, net of tax expense of $0 and $394Reclassification of net realized loss, net of tax expense of $0 and $3940 20 
Pension and other postretirement benefits activity, net of tax expense of $305 and $237Pension and other postretirement benefits activity, net of tax expense of $305 and $237927 1,013 
Total other comprehensive income1,325
 1,080
Total other comprehensive income927 1,325 
   
COMPREHENSIVE INCOME41,543
 34,229
COMPREHENSIVE INCOME41,087 41,543 
Less: Comprehensive income attributable to noncontrolling interests4,873
 4,873
Less: Comprehensive income attributable to noncontrolling interests4,873 4,873 
   
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER$36,670
 $29,356
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER$36,214 $36,670 
 
The accompanying notes are an integral part of the financial statements.


12

ARIZONA PUBLIC SERVICE COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(dollars in thousands)
 
March 31,
2021		December 31,
2020
ASSETS  
PROPERTY, PLANT AND EQUIPMENT  
Plant in service and held for future use$20,945,129 $20,834,424 
Accumulated depreciation and amortization(7,186,452)(7,107,058)
Net13,758,677 13,727,366 
Construction work in progress1,056,991 937,384 
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)97,068 98,036 
Intangible assets, net of accumulated amortization278,071 282,415 
Nuclear fuel, net of accumulated amortization124,533 113,645 
Total property, plant and equipment15,315,340 15,158,846 
INVESTMENTS AND OTHER ASSETS  
Nuclear decommissioning trust (Notes 11 and 12)1,159,699 1,138,435 
Other special use funds (Notes 11 and 12)357,506 254,509 
Other assets44,829 46,010 
Total investments and other assets1,562,034 1,438,954 
CURRENT ASSETS  
Cash and cash equivalents14,536 57,310 
Customer and other receivables262,636 312,644 
Accrued unbilled revenues122,034 132,197 
Allowance for doubtful accounts(20,405)(19,782)
Materials and supplies (at average cost)314,702 314,745 
Fossil fuel (at average cost)24,396 19,552 
Assets from risk management activities (Note 7)22,611 2,931 
Deferred fuel and purchased power regulatory asset (Note 4)228,609 175,835 
Other regulatory assets (Note 4)111,271 115,878 
Other current assets56,987 47,593 
Total current assets1,137,377 1,158,903 
DEFERRED DEBITS  
Regulatory assets (Note 4)1,135,857 1,133,987 
Operating lease right-of-use assets501,395 503,475 
Assets for pension and other postretirement benefits (Note 5)410,933 495,673 
Other35,751 34,413 
Total deferred debits2,083,936 2,167,548 
TOTAL ASSETS$20,098,687 $19,924,251 
 March 31,
2020		 December 31,
2019
ASSETS 
  
    
PROPERTY, PLANT AND EQUIPMENT 
  
Plant in service and held for future use$19,927,522
 $19,832,805
Accumulated depreciation and amortization(6,781,228) (6,634,597)
Net13,146,294
 13,198,208
    
Construction work in progress942,258
 808,133
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)100,938
 101,906
Intangible assets, net of accumulated amortization279,082
 290,409
Nuclear fuel, net of accumulated amortization168,457
 123,500
Total property, plant and equipment14,637,029
 14,522,156
    
INVESTMENTS AND OTHER ASSETS 
  
Nuclear decommissioning trust (Notes 11 and 12)920,426
 1,010,775
Other special use funds (Notes 11 and 12)252,723
 245,095
Other assets44,681
 43,781
Total investments and other assets1,217,830
 1,299,651
    
CURRENT ASSETS 
  
Cash and cash equivalents53,351
 10,169
Customer and other receivables258,457
 255,479
Accrued unbilled revenues93,434
 128,165
Allowance for doubtful accounts(8,366) (8,171)
Materials and supplies (at average cost)323,545
 331,091
Fossil fuel (at average cost)16,930
 14,829
Income tax receivable8,724
 7,313
Assets from risk management activities (Note 7)2,108
 515
Deferred fuel and purchased power regulatory asset (Note 4)77,730
 70,137
Other regulatory assets (Note 4)147,741
 133,070
Other current assets57,471
 38,895
Total current assets1,031,125
 981,492
    
DEFERRED DEBITS 
  
Regulatory assets (Note 4)1,302,448
 1,304,073
Operating lease right-of-use assets142,647
 144,024
Assets for other postretirement benefits (Note 5)92,391
 86,736
Other31,282
 32,591
Total deferred debits1,568,768
 1,567,424
    
TOTAL ASSETS$18,454,752
 $18,370,723

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


13

ARIZONA PUBLIC SERVICE COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(dollars in thousands) 
March 31,
2021		December 31,
2020
LIABILITIES AND EQUITY  
CAPITALIZATION  
Common stock$178,162 $178,162 
Additional paid-in capital2,871,696 2,871,696 
Retained earnings3,252,244 3,216,955 
Accumulated other comprehensive loss(39,991)(40,918)
Total shareholder equity6,262,111 6,225,895 
Noncontrolling interests (Note 6)124,164 119,290 
Total equity6,386,275 6,345,185 
Long-term debt less current maturities (Note 3)5,818,520 5,817,945 
Total capitalization12,204,795 12,163,130 
CURRENT LIABILITIES  
Short-term borrowings (Note 3)199,500 0 
Accounts payable301,675 311,699 
Accrued taxes211,174 148,970 
Accrued interest56,454 56,322 
Common dividends payable0 93,500 
Customer deposits45,170 48,340 
Liabilities from risk management activities (Note 7)3,067 7,557 
Liabilities for asset retirements16,021 15,586 
Operating lease liabilities74,235 74,695 
Regulatory liabilities (Note 4)250,228 229,088 
Other current liabilities152,290 190,420 
Total current liabilities1,309,814 1,176,177 
DEFERRED CREDITS AND OTHER  
Deferred income taxes2,150,668 2,143,673 
Regulatory liabilities (Note 4)2,427,769 2,450,169 
Liabilities for asset retirements693,383 689,497 
Liabilities for pension benefits (Note 5)147,235 148,943 
Liabilities from risk management activities (Note 7)6,928 11,062 
Customer advances220,999 221,032 
Coal mine reclamation171,227 170,097 
Deferred investment tax credit190,842 191,372 
Unrecognized tax benefits39,863 39,410 
Operating lease liabilities358,840 359,653 
Other176,324 160,036 
Total deferred credits and other6,584,078 6,584,944 
COMMITMENTS AND CONTINGENCIES (NOTE 8)00
TOTAL LIABILITIES AND EQUITY$20,098,687 $19,924,251 
 March 31,
2020		 December 31,
2019
LIABILITIES AND EQUITY 
  
    
CAPITALIZATION 
  
Common stock$178,162
 $178,162
Additional paid-in capital2,721,696
 2,721,696
Retained earnings3,047,269
 3,011,927
Accumulated other comprehensive loss(34,197) (35,522)
Total shareholder equity5,912,930
 5,876,263
Noncontrolling interests (Note 6)127,414
 122,540
Total equity6,040,344
 5,998,803
Long-term debt less current maturities (Note 3)4,833,743
 4,833,133
Total capitalization10,874,087
 10,831,936
CURRENT LIABILITIES 
  
Short-term borrowings (Note 3)430,000
 —
Current maturities of long-term debt (Note 3)200,000
 350,000
Accounts payable294,037
 338,006
Accrued taxes190,571
 136,328
Accrued interest51,042
 52,619
Common dividends payable—
 88,000
Customer deposits54,965
 64,908
Liabilities from risk management activities (Note 7)54,784
 38,946
Liabilities for asset retirements10,095
 11,025
Operating lease liabilities12,224
 12,549
Regulatory liabilities (Note 4)279,105
 234,912
Other current liabilities133,497
 164,736
Total current liabilities1,710,320
 1,492,029
DEFERRED CREDITS AND OTHER 
  
Deferred income taxes2,057,824
 2,033,096
Regulatory liabilities (Note 4)2,067,801
 2,267,835
Liabilities for asset retirements649,226
 646,193
Liabilities for pension benefits (Note 5)255,749
 262,243
Liabilities from risk management activities (Note 7)32,577
 33,186
Customer advances212,545
 215,330
Coal mine reclamation166,796
 165,695
Deferred investment tax credit196,002
 196,468
Unrecognized tax benefits40,399
 40,188
Operating lease liabilities49,442
 50,092
Other141,984
 136,432
Total deferred credits and other5,870,345
 6,046,758
COMMITMENTS AND CONTINGENCIES (SEE NOTE 8)


 


TOTAL LIABILITIES AND EQUITY$18,454,752
 $18,370,723

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

14

ARIZONA PUBLIC SERVICE COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(dollars in thousands)
Three Months Ended
March 31,		 Three Months Ended
March 31,
2020 2019 20212020
CASH FLOWS FROM OPERATING ACTIVITIES 
  
CASH FLOWS FROM OPERATING ACTIVITIES  
Net income$40,218
 $33,149
Net income$40,160 $40,218 
Adjustments to reconcile net income to net cash provided by operating activities: 
  
Adjustments to reconcile net income to net cash provided by operating activities:  
Depreciation and amortization including nuclear fuel173,147
 167,779
Depreciation and amortization including nuclear fuel176,389 173,147 
Deferred fuel and purchased power(5,785) 16,709
Deferred fuel and purchased power(52,210)(5,785)
Deferred fuel and purchased power amortization(1,808) 12,872
Deferred fuel and purchased power amortization(564)(1,808)
Allowance for equity funds used during construction(7,697) (11,188)Allowance for equity funds used during construction(9,207)(7,697)
Deferred income taxes(17,782) (1,205)Deferred income taxes(2,616)(17,782)
Deferred investment tax credit(465) (353)Deferred investment tax credit(529)(465)
Changes in current assets and liabilities: 
  
Changes in current assets and liabilities:  
Customer and other receivables15,045
 16,541
Customer and other receivables50,103 15,045 
Accrued unbilled revenues34,731
 23,093
Accrued unbilled revenues10,163 34,731 
Materials, supplies and fossil fuel5,445
 (13,057)Materials, supplies and fossil fuel(4,801)5,445 
Income tax receivable(1,411) —
Income tax receivable0 (1,411)
Other current assets(18,164) (9,598)Other current assets(8,825)(18,164)
Accounts payable(4,038) 30,774
Accounts payable23,881 (4,038)
Accrued taxes54,243
 54,234
Accrued taxes62,204 54,243 
Other current liabilities(49,149) (81,627)Other current liabilities(43,917)(49,149)
Change in other long-term assets82,178
 (64,516)Change in other long-term assets(36,626)82,178 
Change in other long-term liabilities(105,117) 14,525
Change in other long-term liabilities(642)(105,117)
Net cash flow provided by operating activities193,591
 188,132
Net cash flow provided by operating activities202,963 193,591 
CASH FLOWS FROM INVESTING ACTIVITIES 
  
CASH FLOWS FROM INVESTING ACTIVITIES  
Capital expenditures(340,014) (259,446)Capital expenditures(363,775)(340,014)
Contributions in aid of construction3,152
 7,938
Contributions in aid of construction15,296 3,152 
Allowance for borrowed funds used during construction(4,076) (6,665)Allowance for borrowed funds used during construction(4,994)(4,076)
Proceeds from nuclear decommissioning trust sales and other special use funds195,087
 179,048
Proceeds from nuclear decommissioning trust sales and other special use funds379,978 195,087 
Investment in nuclear decommissioning trust and other special use funds(195,658) (179,618)Investment in nuclear decommissioning trust and other special use funds(380,548)(195,658)
Other(900) (1,140)Other2,306 (900)
Net cash flow used for investing activities(342,409) (259,883)Net cash flow used for investing activities(351,737)(342,409)
CASH FLOWS FROM FINANCING ACTIVITIES 
  
CASH FLOWS FROM FINANCING ACTIVITIES  
Issuance of long-term debt—
 497,324
Short-term borrowings and payments — net—
 157,500
Short-term borrowings and (repayments) — netShort-term borrowings and (repayments) — net199,500 0 
Short-term debt borrowings under revolving credit facility540,000
 —
Short-term debt borrowings under revolving credit facility0 540,000 
Short-term debt repayments under revolving credit facility(110,000) —
Short-term debt repayments under revolving credit facility0 (110,000)
Repayment of long-term debt(150,000) (500,000)Repayment of long-term debt0 (150,000)
Dividends paid on common stock(88,000) (82,700)Dividends paid on common stock(93,500)(88,000)
Net cash flow provided by financing activities192,000
 72,124
Net cash flow provided by financing activities106,000 192,000 
NET INCREASE IN CASH AND CASH EQUIVALENTS43,182
 373
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTSNET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS(42,774)43,182 
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD10,169
 5,707
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD57,310 10,169 
CASH AND CASH EQUIVALENTS AT END OF PERIOD$53,351
 $6,080
CASH AND CASH EQUIVALENTS AT END OF PERIOD$14,536 $53,351 

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

15


ARIZONA PUBLIC SERVICE COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(unaudited)
(dollars in thousands)
Three Months Ended March 31, 2021
Common StockAdditional Paid-In CapitalRetained EarningsAccumulated Other Comprehensive Income (Loss)Noncontrolling InterestsTotal
SharesAmount
Balance, January, 202171,264,947 $178,162 $2,871,696 $3,216,955 $(40,918)$119,290 $6,345,185 
Net Income— — 35,287 — 4,873 40,160 
Other comprehensive income— — — 927 — 927 
Other— — 2 — 1 3 
Balance, March 31, 202171,264,947 $178,162 $2,871,696 $3,252,244 $(39,991)$124,164 $6,386,275 
 Three Months Ended March 31, 2020
 Common Stock Additional Paid-In Capital Retained Earnings Accumulated Other Comprehensive Income (Loss) Noncontrolling Interests Total
 Shares Amount          
Balance, January 1, 202071,264,947
 $178,162
 $2,721,696
 $3,011,927
 $(35,522) $122,540
 $5,998,803
Net Income  —
 —
 35,345
 —
 4,873
 40,218
Other comprehensive income  —
 —
 —
 1,325
 —
 1,325
Other  —
 —
 (3) —
 1
 (2)
Balance, March 31, 202071,264,947
 $178,162
 $2,721,696
 $3,047,269
 $(34,197) $127,414
 $6,040,344


Three Months Ended March 31, 2020
Common StockAdditional Paid-In CapitalRetained EarningsAccumulated Other Comprehensive Income (Loss)Noncontrolling InterestsTotal
SharesAmount
Balance, January 1, 202071,264,947 $178,162 $2,721,696 $3,011,927 $(35,522)$122,540 $5,998,803 
Net Income— — 35,345 — 4,873 40,218 
Other comprehensive income— — — 1,325 — 1,325 
Other(3)1 (2)
Balance, March 31, 202071,264,947 $178,162 $2,721,696 $3,047,269 $(34,197)$127,414 $6,040,344 
 Three Months Ended March 31, 2019
 Common Stock Additional Paid-In Capital Retained Earnings Accumulated Other Comprehensive Income (Loss) Noncontrolling Interests Total
 Shares Amount          
Balance, January 1, 201971,264,947
 $178,162
 $2,721,696
 $2,788,256
 $(27,107) $125,790
 $5,786,797
Net Income  —
 —
 28,276
 —
 4,873
 33,149
Other comprehensive income  —
 —
 —
 1,080
 —
 1,080
Balance, March 31, 201971,264,947
 $178,162
 $2,721,696
 $2,816,532
 $(26,027) $130,663
 $5,821,026


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
















16

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1.     
Consolidation and Nature of Operations
 
The unaudited condensed consolidated financial statements include the accounts of Pinnacle West and our subsidiaries:  APS, 4C Acquisition, LLC ("4CA"(“4CA”), Bright Canyon Energy Corporation ("BCE"(“BCE”) and El Dorado Investment Company ("(“El Dorado"Dorado”).  See Note 8 for more information on 4CA matters. Intercompany accounts and transactions between the consolidated companies have been eliminated.  The unaudited condensed consolidated financial statements for APS include the accounts of APS and the Palo Verde Generating Station ("(“Palo Verde"Verde”) sale leaseback variable interest entities ("VIEs"(“VIEs”) (see Note 6 for further discussion).  Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America ("GAAP"(“GAAP”).  The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

Amounts reported in our interim Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the respective annual periods, due to the effects of seasonal temperature variations on energy consumption, timing of maintenance on electric generating units ("EGU"(“EGU”), and other factors.
 
Our condensed consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations, and cash flows for the periods presented. Certain information and footnote disclosures normally included in financial statements prepared in conformity with GAAP have been condensed or omitted pursuant to such regulations, although we believe that the disclosures provided are adequate to make the interim information presented not misleading. The accompanying condensed consolidated financial statements and these notes should be read in conjunction with the audited consolidated financial statements and notes included in our 20192020 Form 10-K.

On June 30, 2020, the United States Federal Energy Regulatory Commission (“FERC”) issued an order granting a waiver request related to the existing Allowance for Funds Used During Construction (“AFUDC”) rate calculation beginning March 1, 2020 through February 28, 2021.  On February 23, 2021, this waiver was extended until September 30, 2021. 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 both 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 change will not have a material impact on our financial statements. See Note 1 in our 2020 Form 10-K for information on the accounting treatment for AFUDC.

17

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Supplemental Cash Flow Information

The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):
 Three Months Ended
March 31,
 20212020
Cash paid during the period for:
Income taxes, net of refunds$(827)$(3,002)
Interest, net of amounts capitalized53,885 53,723 
Significant non-cash investing and financing activities:
Accrued capital expenditures$79,597 $100,868 
Right-of-use operating lease assets obtained in exchange for operating lease liabilities785 2,311 
 Three Months Ended
March 31,
 2020 2019
Cash paid during the period for:   
Income taxes, net of refunds$(3,002) $1
Interest, net of amounts capitalized53,723
 63,764
Significant non-cash investing and financing activities:   
Accrued capital expenditures$100,868
 $95,879
Right-of-use operating lease assets obtained in exchange for operating lease liabilities2,311
 2,293


The following table summarizes supplemental APS cash flow information (dollars in thousands):
Three Months Ended
March 31,
 20212020
Cash paid during the period for:
Income taxes, net of refunds$0 $0 
Interest, net of amounts capitalized53,153 52,034 
Significant non-cash investing and financing activities:
Accrued capital expenditures$79,597 $100,868 
Right-of-use operating lease assets obtained in exchange for operating lease liabilities785 2,311 
 Three Months Ended
March 31,
 2020 2019
Cash paid during the period for:   
Income taxes, net of refunds$—
 $—
Interest, net of amounts capitalized52,034
 61,387
Significant non-cash investing and financing activities:   
Accrued capital expenditures$100,868
 $95,879
Right-of-use operating lease assets obtained in exchange for operating lease liabilities2,311
 2,293



2.    Revenue

Sources of Revenue

The following table provides detail of Pinnacle West'sWest’s consolidated revenue disaggregated by revenue sources (dollars in thousands):
 Three Months Ended March 31,Three Months Ended March 31,
 2020201920212020
Retail Electric Revenue  Retail Electric Revenue
Residential $325,073
$351,566
Residential$340,838 $325,073 
Non-Residential 303,351
332,668
Non-Residential314,783 303,351 
Wholesale energy sales 14,668
36,452
Transmission services for others 15,927
15,249
Other sources 2,911
4,595
Wholesale Energy SalesWholesale Energy Sales17,597 14,668 
Transmission Services for OthersTransmission Services for Others18,993 15,927 
Other SourcesOther Sources4,264 2,911 
Total operating revenues $661,930
$740,530
Total operating revenues$696,475 $661,930 

18

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Retail Electric Revenue. Pinnacle West'sWest’s retail electric revenue is generated by wholly ownedwholly-owned regulated subsidiary APS'sAPS’s sale of electricity to our regulated customers within the authorized service territory at tariff rates approved by the ACC and based on customer usage. Revenues related to the sale of electricity are generally recognized when service is rendered or electricity is delivered to customers. The billing of electricity sales to individual customers is based on the reading of their meters. We obtain customers'customers’ meter data on a systematic basis throughout the month, and generally bill customers within a month from when service was provided. Customers are generally required to pay for services within 15 days of when the services are billed. See “Allowance for Doubtful Accounts” discussion below for additional details regarding payment terms.

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

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

Revenue Activities

Our revenues primarily consist of activities that are classified as revenues from contracts with customers. We derive our revenues from contracts with customers primarily from sales of electricity to our regulated retail customers. Revenues from contracts with customers also include wholesale and transmission activities. Our revenues from contracts with customers for the three months ended March 31, 2021 and 2020 were $682 million and 2019 were $648 million, and $721 million, respectively.

We have certain revenues that do not meet the specific accounting criteria to be classified as revenues from contracts with customers. For the three months ended March 31, 20202021 and 2019,2020, our revenues that do not qualify as revenue from contracts with customers were $14 million and $20$14 million, respectively. This relates primarily to certain regulatory cost recovery mechanisms that are considered alternative revenue programs. We recognize revenue associated with alternative revenue programs when specific events permitting recognition are completed. Certain amounts associated with alternative revenue programs will subsequently be billed to customers; however, we do not reclassify billed amounts into revenue from contracts with customers. See Note 4 for a discussion of our regulatory cost recovery mechanisms.

Contract Assets and Liabilities from Contracts with Customers

There were no material contract assets, contract liabilities, or deferred contract costs recorded on the Condensed Consolidated Balance Sheets as of March 31, 20202021 or December 31, 2019.2020.

Allowance for Doubtful Accounts

The allowance for doubtful accounts represents our best estimate of accounts receivable and accrued unbilled revenues that will ultimately be uncollectible.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.

During March 2020, due to the Coronavirus ("COVID-19") pandemic, and to assist customers who may be experiencing economic difficulties, we suspended all service shut-offs due to nonpayment. We are expecting an
19

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

increase inOn March 13, 2020, due to the numberCOVID-19 pandemic we voluntarily suspended disconnections of customers needing to utilize longer-term payment plans to avoid service disruption. These changes, among others includingfor nonpayment. The suspension of customer disconnections was extended from March 13, 2020 through December 31, 2020. Our disconnection policies are also impacted by the Summer Disconnection Moratorium (defined in Note 4),Moratorium.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. These circumstances and the on-going COVID-19 pandemic have impacted our write-off factor during the period. We continue to monitor COVID-19 and its impact on our allowance for doubtful accounts, which may impactincluding our write-off factor. We continue to monitor the impacts of COVID-19, our disconnection policies, payment arrangements, among other considerations impacting our estimated write-off factor and allowance for upcoming 2020 financial statements.doubtful accounts. See Note 4 for additional details.

The following table provides a rollforward of Pinnacle West’s allowance for doubtful accounts (dollars in thousands):

March 31, 2021December 31, 2020
Allowance for doubtful accounts, balance at beginning of period$19,782 $8,171 
Bad debt expense4,151 20,633 
Actual write-offs(3,528)(9,022)
Allowance for doubtful accounts, balance at end of period$20,405 $19,782 
  March 31, 2020 December 31, 2019
Allowance for doubtful accounts, balance at beginning of period $8,171
 $4,069
Bad debt expense 3,122
 11,819
Actual write-offs (2,927) (7,717)
Allowance for doubtful accounts, balance at end of period $8,366
 $8,171




3.Long-Term Debt and Liquidity Matters
3.Long-Term Debt and Liquidity Matters

Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs, to refinance indebtedness, and for other general corporate purposes.
 
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 agreement that would have matured May 4, 2021. Borrowings under the agreement bore interest at Eurodollar Rate plus 1.40% per annum. At March 31, 2021, Pinnacle West had $15 million in outstanding borrowings under the current agreement, all of which was repaid on April 27, 2021.

On December 23, 2020, Pinnacle West entered into a $150 million term loan facility that matures June 2022. The proceeds were received on January 4, 2021 and used for general corporate purposes. We recognized the term loan facility as long-term debt upon settlement on January 4, 2021.

At March 31, 2020,2021, Pinnacle West had a $200 million revolving credit facility that matures in July 2023. 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'sWest’s senior unsecured debt credit ratings. The facility is available to support Pinnacle West'sWest’s $200 million commercial paper program, for bank borrowings or for issuances of letters of credits. At March 31, 2020,2021, Pinnacle West had $100 million0 outstanding borrowings under its credit facility, 0 letters of credit outstanding and 0$0.3 million of outstanding commercial paper borrowings.

On May 5, 2020, Pinnacle West refinanced its 364-day $50 million term loan agreement that would have matured on May 7, 2020 with a new 364-day $31 million term loan agreement that matures on May 4, 2021. Borrowings under the agreement bear interest at London Inter-bank Offered Rate ("LIBOR") plus 1.40% per annum. At March 31, 2020, Pinnacle West had $33 million in outstanding borrowings under the prior agreement.

20

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

APS

APS

On January 15, 2020, APS repaid at maturity the remaining $150 million of the $250 million aggregate principal amount of its 2.2% Senior Notes.

At March 31, 2020,2021, APS had 2 revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in June 2022 and a $500 million facility that matures in July 2023.  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. These facilities are available to support APS’s $500$750 million commercial paper program, for bank borrowings or for issuances of letters of credit.  At March 31, 2020,2021, APS had $430 million0 outstanding borrowings under its revolving credit facilities, and 0 letters of credit outstanding, orand $199.5 million of outstanding commercial paper borrowings.

On November 27, 2018,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 athe sum of (i) 7% of APS’s capitalization, and (ii) $500 million (which is required to be used for costs relating to purchases of natural gas and power) and a long-term debt authorization of $5.9$7.5 billion. On March 27, 2020, APS filed an application with the ACC to increase the long-term debt limit from $5.9 billion to $7.5 billion and to continue its authorization of short-term debt granted in the 2018 financing order.

See "Financial Assurances"“Financial Assurances” in Note 8 for a discussion of other outstanding letters of credit.
 
Debt Fair Value
 
Our long-term debt fair value estimates are classified within Level 2 of the fair value hierarchy. The following table presents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):

 As of March 31, 2020 As of December 31, 2019
 
Carrying
Amount
 Fair Value 
Carrying
Amount
 Fair Value
Pinnacle West$449,581
 $448,449
 $449,425
 $450,822
APS5,033,743
 5,634,265
 5,183,133
 5,743,570
Total$5,483,324
 $6,082,714
 $5,632,558
 $6,194,392


 As of March 31, 2021As of December 31, 2020
 Carrying
Amount		Fair ValueCarrying
Amount		Fair Value
Pinnacle West$646,525 $653,395 $496,321 $509,050 
APS5,818,520 6,436,224 5,817,945 7,103,791 
Total$6,465,045 $7,089,619 $6,314,266 $7,612,841 
4.Regulatory Matters
     
COVID-19 Pandemic
21

Due to the COVID-19 pandemic, APS has voluntarily suspended disconnections of customers for nonpayment beginning March 13, 2020.  In addition, APS has waived all late payment fees during this current moratorium.  APS currently estimates that the Summer Disconnection Moratorium (see below for discussion of the Summer Disconnection Moratorium), the suspension of disconnections during the COVID-19 pandemic and the increased bad debt expense associated with both events will result in a negative impact to its 2020 operating results of approximately $20 to $30 million pre-tax above the impact of disconnections on its operating results for years that did not have the Summer Disconnection Moratorium or COVID-19 pandemic.

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

4.Regulatory Matters
COVID-19 Pandemic

Due to the COVID-19 pandemic, APS voluntarily suspended disconnections of customers for nonpayment and waived late payment fees beginning March 13, 2020 until December 31, 2020. The suspension of disconnection of customers for nonpayment ended on January 1, 2021 and customers were automatically placed on eight-month payment arrangements if they had past due balances at the end of the disconnection period of $75 or greater. APS will continue to waive late payment fees until October 15, 2021. APS has experienced and is anticipatingcontinuing to experience an increase in bad debt expense associated with the COVID-19 pandemic, but it still believes that costs associated with the Summer Disconnection Moratorium (defined below) and the COVID-19 disconnection suspensions and related bad debt expense with both events will fall within this estimated $20 to $30 million range. These estimated impact amounts depend on certain assumptions, includingwrite-offs of customer behaviors and the impacts of COVID-19 on the economy not extending into 2021. APS also established a customer support fund of $1.5 million to assist customers with a one-time credit of up to $100 on their bill with a priority given to customers on limited-income service plans. Additionally, duedelinquent accounts. Due to COVID-19, APS also delayed the reset of the Environmental Improvement Surcharge ("EIS"(“EIS”) adjustor and suspended the discontinuation of TEAM Phase II to the first billing cycle in May 2020 rather than April 2020 (see2020. In February 2021, APS delayed the annual reset of the PSA. Rather than the increase being effective February 2021, the PSA reset will be implemented with 50% of the increase effective April 2021 and the remaining 50% increase effective November 2021 (see below for discussion of EIS, and TEAM Phase II)II and PSA).

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 hashad been collected through the Demand Side Management ("DSM"(“DSM”) Adjustor Clause,Charge, but not allocated for current DSM programs, directly to customers through a bill credit in June 20202020. APS has refunded approximately $43 million to customers. The additional $7 million over the approved amount of $36 million was the result of the kWh credit being based on historic consumption, which was different than actual consumption in the refund period. This difference was recorded to the DSM balancing account and will be addressed in subsequent DSM filings (see below for discussion of the DSM Adjustor Clause)Charge).   Also, on May 5,

In 2020, APS also voluntarilyspent 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 a series of voluntary commitments of funds that are not recoverable through rates throughout 2020 of approximately $8.8 million. An additional $3.6 million in bill credits for limited income customers was ordered by the ACC in December 2020 of which 50%, up to contribute $5.3a maximum of $2.5 million, of non-ratepayerwas committed to be funds to provide assistance to residential and businessthat are not recoverable through rates with the remaining being deferred for potential future recovery in rates. Included in the COVID Customer Support Fund were programs that assisted customers that have been impacted byhad a delinquency of two or more months with 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.
22

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
2019 Retail Rate Case Filing with the Arizona Corporation Commission

On October 31,In accordance with the requirements of the 2019 rate review order described below, APS filed an application with the ACC foron October 31, 2019 seeking an annual 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"(“SCR”) project that is currently the subject of a separate proceeding (see “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 Tax Expense Adjustment Mechanism ("TEAM"(“TEAM”). The proposed total annual revenue increase in APS'sAPS’s application is $184 million. The average annual customer bill impact of APS’s request is an increase of 5.6% (the average annual bill impact for a typical APS residential customer is 5.4%).

The principal provisions of APS'sAPS’s application are:were:

•a test year comprised of twelve months ended June 30, 2019, adjusted as described below;
•an original cost rate base of $8.87 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 45.3 %4.10 %
Common stock equity 54.7 %10.15 %
Weighted-average cost of capital   7.41 %

 
•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”);
•authorization to defer until APS'sAPS’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;
•a number of proposed rate and program changes for residential customers, including:
▪a super off-peak period during the winter months for APS’s time-of-use with demand rates;
▪
▪a super off-peak period during the winter months for APS’s time-of-use with demand rates;
▪additional $1.25 million in funding for APS’s limited-income crisis bill program; and
▪a flat bill/subscription rate pilot program;
•APS's limited-income crisis bill program; and

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

▪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;
•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); and
•
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); and
continued recovery of the remaining investment and other costs related to the retirement and closure of the Navajo Generating Station (the "Navajo Plant"“Navajo Plant”) (see "Navajo Plant"“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 in this rate case. The ACC Staff recommends, among other things, a (i) $89.7 million revenue increase, (ii) average annual customer bill increase of 2.7%, (iii) 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) recovery of the deferral and rate base effects of the construction and operating costs of the Four Corners SCR project and (vi) recovery of the rate base effects of the construction and ongoing consideration of the deferral of the Ocotillo modernization project. RUCO recommends, among other things, a (i) $20.8 million revenue decrease, (ii) average annual customer bill decrease of 0.63%, (iii) return on equity of 8.74%, (iv) a 0% return on the increment of fair value rate base, (v) nonrecovery of the
23

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
deferral and rate base effects of the construction and operating costs of the Four Corners SCR project pending further consideration, and (vi) 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 requestedfiled 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 (“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: (i) $100 million that will be paid over 10 years to the Navajo Nation for a sustainable transition to a post-coal economy, which would be funded by customers, (ii) $1.25 million that will be paid over five years to the Navajo Nation to fund an economic development organization, which would be funds not recoverable through rates, (iii) $10 million to facilitate electrification projects within the Navajo Nation, which would be funded equally by funds not recoverable through rates and by customers, (iv) $2.5 million per year in transmission revenue sharing to be paid to the Navajo Nation beginning after the closure of the Four Corners Power Plant through 2038, which would be funds not recoverable through rates, (v) $12 million that will be paid over five years to the Navajo County Communities surrounding Cholla Power Plant, which would primarily be funded by customers, and (vi) $3.7 million that will be paid over five years to the Hopi Tribe related to APS’s ownership interests in the Navajo Generating Station, which would primarily be funded by customers. The commitment of funds that would not be recoverable through rates of $25 million were recognized in our December 31, 2020 financials.

On December 4, 2020, the ACC Staff and intervenors filed surrebuttal testimony. The ACC Staff reduced its recommended rate increase become effective December 1, 2020.  to $59.8 million, or an average annual customer bill increase of 1.82%. In RUCO’s surrebuttal, the recommended revenue decrease changed to $50.1 million, or an average annual customer bill decrease of 1.52%.

The hearing forconcluded on March 3, 2021 and the post-hearing briefing schedule concluded on April 30, 2021. In May 2021, the ACC will be discussing whether to re-open the evidentiary record in APS’s pending rate case to take additional evidence on topics raised by certain ACC Commissioners, including adjustor cost recovery mechanisms. APS believes that the rate case record is sufficient, and adjustors provide substantial benefits to customers by supporting critical programs and reflecting changes in utility costs that can be promptly passed along to customers. Pending this decision, the next steps in this rate case was delayed by 75 days, atare that the requestAdministrative Law Judge will issue a Recommended Order and Opinion and then the ACC will review and consider the matter, which is anticipated to be in the third quarter of 2021. Unfavorable ACC Staff and is currently scheduled to begin September 30, 2020.intervenor positions and recommendations, including modifications or elimination of APS's adjustor cost recovery mechanisms could have a material impact on APS’s financial statements if ultimately adopted by the ACC. APS cannot predict the outcome or timing of its request.this proceeding.
24

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

2016 Retail Rate Case Filing with the Arizona Corporation Commission
 
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 Residential Utility Consumer Office,RUCO, limited income advocates and private rooftop solar organizations signed a settlement agreement (the "2017“2017 Settlement Agreement"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: (1) a non-fuel, non-depreciation, base rate increase of $87.2 million per year; (2) a base rate decrease of $53.6 million attributable to reduced fuel and purchased power costs; and (3) a base rate increase of $61.0 million due to changes in depreciation schedules. The average annual customer bill impact under the 2017 Settlement Agreement was calculated as an increase of 3.28% (the average annual bill impact for a typical APS residential customer was calculated as an increase of 4.54%).

Other key provisions of the agreement include the following:

an agreement by APS not to file another general retail rate case application before June 1, 2019;
•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 the Four Corners Power Plant ("(“Four Corners"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 Power Supply Adjustor (“PSA”) to include certain environmental chemical costs and third-party energy storage costs;
•a new AZ Sun II program (now known as "APS“APS Solar Communities"Communities”) for utility-owned solar distributed generation with the purpose of expanding access to rooftop solar for low and moderate income Arizonans, recoverable through the Arizona Renewable Energy Standard and Tariff ("RES"(“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-7 p.m. to 3 p.m.-8 p.m. Monday through Friday, excluding holidays;
COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
▪non-grandfathered distributed generation (“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; and
▪a change in the on-peak time of use period from noon - 7 p.m. to 3 p.m. - 8 p.m. Monday through Friday, excluding holidays;
▪non-grandfathered distributed generation ("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; and
•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.

Through a separate agreement, APS, industry representatives, and solar advocates committed to stand by the 2017 Settlement Agreement and refrain from seeking to undermine it through ballot initiatives, legislation or advocacy at the ACC.

25

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
On August 15, 2017, the ACC approved (by a vote of 4-1), the 2017 Settlement Agreement without material modifications.  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“2017 Rate Case Decision"Decision”), which is subject to requests for rehearing and potential appeal. The new rates went into effect on August 19, 2017.

On January 3, 2018, an APS customer filed a petition with the ACC that was determined by the ACC Staff to be a complaint filed pursuant to Arizona Revised Statute §40-246 (the “Complaint”). The Complaint was later amended alleging that the rates and charges in the 2017 Rate Case Decision are not just and reasonable. The ACC held a hearing on this matter, and the hearing was concluded on October 1, 2018. On April 9, 2019, the Administrative Law Judge issued a Recommended Opinion and Order recommending that the Complaint be dismissed. On July 3, 2019, the Administrative Law Judge issued an amendment to the Recommended Opinion and Order that incorporated the requirements of the rate review of the 2017 Rate Case Decision (see below discussion regarding the rate review). On July 10, 2019, the ACC adopted the Administrative Law Judge'sJudge’s amended Recommended Opinion and Order along with several ACC Commissioner amendments and an amendment incorporating the results of the rate review and resolved the Complaint.

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.

ACC Review of APS 2017 Rate Case Decision

On December 24, 2018, certain ACC Commissioners filed a letter stating that because the ACC had received a substantial number of complaints that the rate increase authorized by the 2017 Rate Case Decision was much more than anticipated, they believe there is a possibility that APS is earning more than was authorized by the 2017 Rate Case Decision.  Accordingly, the ACC Commissioners requested the ACC Staff to perform a rate review of APS using calendar year 2018 as a test year. The ACC Commissioners also asked the ACC Staff to evaluate APS’s efforts to educate its customers regarding the new rates approved in the 2017 Rate Case Decision.

On June 4, 2019, the ACC Staff filed a proposed order regarding the rate review of the 2017 Rate Case Decision. On June 11, 2019, the ACC Commissioners approved the proposed ACC Staff order with amendments. The key provisions of the amended order include the following:

•APS must file a rate case no later than October 31, 2019, using a June 30, 2019 test-year;test year;
•until the conclusion of the rate case being filed no later than October 31, 2019, APS must provide information on customer bills that shows how much a customer would pay on their most economical rate given their actual usage during each month;
•APS customers can switch rate plans during an open enrollment period of six months;

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

•APS must identify customers whose bills have increased by more than 9% and that are not on the most economical rate and provide such customers with targeted education materials and an opportunity to switch rate plans;
•APS must provide grandfathered net metering customers on legacy demand rates an opportunity to switch to another legacy rate to enable such customers to fully benefit from legacy net metering rates;
•APS must fund and implement a supplemental customer education and outreach program to be developed with and administered by ACC Staff and a third-party consultant; and
•APS must fund and organize, along with the third-party consultant, a stakeholder group to suggest better ways to communicate the impact of changes to adjustor cost recovery mechanisms (see below for discussion on cost recovery mechanisms), including more effective ways to educate customers on rate plans and to reduce energy usage.

26

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
APS cannot predict the outcome or impact of thefiled its rate case filed on October 31, 2019.2019 (see “2019 Retail Rate Case Filing with the Arizona Corporation Commission” above for more information). APS does not believe that the implementation of the other key provisions of the amended order regarding the rate review will have a material impact on its financial position, results of operations or cash flows.

On May 19, 2020, the ACC Staff filed a third-party consultant’s report which evaluated the effectiveness of APS’s customer outreach and education program related to the 2017 Rate Case Decision. On May 29, 2020, the Chairman of the ACC filed a letter with the ACC in response to this report and is alleging that APS is out of compliance with the 2017 Rate Case Decision and is over-earning. The Chairman proposed that the current rates should be classified as interim rates and customers held harmless if APS’s activities have caused the rates set in the 2017 Rate Case Decision to not be just and reasonable. Also, on May 29, 2020, a second commissioner filed a letter with the ACC agreeing with the Chairman’s assertions and further asserting that the 2017 Rate Case Decision should be re-opened. On June 18, 2020, at an ACC Open Meeting, the matters raised in these letters were discussed. The ACC did not vote to move forward with any adjustments to APS’s current rates. On November 4, 2020, the ACC voted to administratively close this docket.

Cost Recovery Mechanisms
 
APS has received regulatory decisions that allow for more timely recovery of certain costs outside of a general retail rate case through the following recovery mechanisms.
 
Renewable Energy Standard.  In 2006, the ACC approved the RES.  Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies.  In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects.  Each year APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget. In 2015, the ACC revised the RESRES rules to allow the ACC to consider all available information, including the number of rooftop solar arrays in a utility’s service territory, to determine compliance with the RES.

On November 20, 2017, APS filed an updated 2018 RES budget to include budget adjustments for APS Solar Communities (formerly known as AZ Sun II), which was approved as part of the 2017 Rate Case Decision. APS Solar Communities is a 3-year program authorizing APS to spend $10 million to $15 million in capital costs each year to install utility-owned DG systems for low to moderate income residential homes, non-profit entities, Title I schools and rural government facilities. The 2017 Rate Case Decision provided that all operations and maintenance expenses, property taxes, marketing and advertising expenses, and the capital carrying costs for this program will be recovered through the RES.

On June 29, 2018, APS filed its 2019 RES Implementation Plan and proposed a budget of approximately $89.9 million.  APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the residential distributed energy requirement for 2019 contained in the RES rules. On October 29, 2019, the ACC approved the 2019 RES Implementation Plan including a waiver of the residential distributed energy requirements for the 2019 implementation year.

On July 1, 2019, APS filed its 2020 RES Implementation Plan and proposed a budget of approximately $86.3 million. APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the residential distributed energy requirement for 2020 contained in the RES rules. TheOn September 23, 2020, the ACC has not yet ruled onapproved the 2020 RES Implementation Plan.

Plan including a waiver of the residential distributed energy requirements for the 2020 implementation year. In addition, the ACC approved the implementation of a new pilot program that incentivizes Arizona households to install at-home battery
27

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
systems. Recovery of the costs associated with the pilot will be addressed in the 2021 Demand Side Management Implementation Plan (“DSM Plan”).

On July 2, 2019, ACC Staff issued draft rules, which propose1, 2020, APS filed its 2021 RES Implementation Plan and proposed a RES goalbudget of 45% of retail energy served be renewables by 2035approximately $84.7 million.  APS’s budget request supports existing approved projects and commitments and requests a goal of 20% of retail sales during peak demand to be from clean energy resources by 2035.  The draft rules would also require a certain amountpermanent waiver of the residential distributed energy requirement for 2021 contained in the RES goalrules. In the 2021 RES Implementation Plan, APS requested $4.5 million to be derived from distributed renewable storage, for which utilities would be requiredmeet revenue requirements associated with the APS Solar Communities program to offer performance-based incentives. Nuclear energy would be consideredcomplete installations delayed as a clean resource underresult of the draft rules. COVID-19 pandemic in 2020. The ACC has not yet ruled on the 2021 RES Implementation Plan.

On February 18,July 30, 2020, ACC Staff issued revisedfinal draft rules which, if approved, would change the RES andrequire APS to meet certain clean energy goals to standards and would provide additional reportingtechnology procurement mandates, obtain approval for its action plan included in its IRP, and compliance requirements. Certain ACC Commissioners have proposed different options with different implementation dates of these rules.seek cost recovery in a rate process. APS cannot predict the outcome of this matter. See "Energy“Energy Modernization Plan"Plan” below for more information.

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

On September 1, 2017, APS filed its 2018 DSM Plan, which proposesproposed modifications to the demand side management 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 seekssought a requested budget of $52.6 million and requestsrequested 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. The ACC has not yet ruled on the APS 2018 amended DSM Plan.

On December 31, 2018, APS filed its 2019 DSM Plan, which requestsrequested a budget of $34.1 million and continues APS's focusfocused on DSM strategies to better meet system and customer needs, such as peak demand reduction, load shifting, storage and electrification strategies. The ACC has not yet ruled on the APS 2019 DSM Plan.

On December 31, 2019, APS filed its 2020 DSM Plan, which requestsrequested a budget of $51.9 million and continues APS'scontinued APS’s focus on DSM strategies such as peak demand reduction, load shifting, storage and electrification strategies. The 2020 DSM Plan addressesaddressed all components of the pending 2018 and 2019 DSM plans, which enablesenabled the ACC to review the 2020 DSM Plan only. On May 15, 2020, APS filed an amended 2020 DSM Plan to provide assistance to customers experiencing economic impacts of the COVID-19 pandemic. The amended 2020 DSM Plan requested the same budget amount of $51.9 million. On September 23, 2020, the ACC has not yet ruled onapproved the APSamended 2020 DSM Plan.

On April 17, 2020, APS filed an application with the ACC requesting a COVID-19 emergency relief package to provide additional assistance to its customers. On May 5, 2020, the ACC approved APS returning $36 million that hashad been collected through the DSM Adjustor Clause,Charge, but not allocated for current DSM programs, directly to customers through a bill credit in June 2020. APS has refunded approximately $43 million to customers. The additional $7 million over the approved amount was the result of the kWh credit being based on historic consumption which was different than actual consumption in the refund period. This difference was recorded to the DSM balancing account and will be addressed in subsequent DSM filings. See "COVID-19 Pandemic"“COVID-19 Pandemic” above for more information.
28

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 approved in the 2020 RES Implementation Plan. The ACC has not yet ruled on the amended APS 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 has not ruled on this request.

Power Supply Adjustor Mechanism and Balance. The PSA provides for the adjustment of retail rates to reflect variations primarily in retail fuel and purchased power costs.  The following table shows the changes in the deferred fuel and purchased power regulatory asset for 20202021 and 20192020 (dollars in thousands):
 
 Three Months Ended
March 31,
 2020 2019
Beginning balance$70,137
 $37,164
Deferred fuel and purchased power costs — current period5,785
 (16,709)
Amounts charged to customers1,808
 (12,872)
Ending balance$77,730
 $7,583

 Three Months Ended
March 31,
 20212020
Beginning balance$175,835 $70,137 
Deferred fuel and purchased power costs — current period52,210 5,785 
Amounts refunded to customers564 1,808 
Ending balance$228,609 $77,730 
 
The PSA rate for the PSA year beginning February 1, 2018 is2019 was $0.001658 per kWh, as compared to the $0.004555 per kWh consistingfor the prior year. This rate was comprised of a forward component of $0.002009$0.000536 per kWh and a historical component of $0.002546 per kWh. This represented a $0.004 per kWh increase over the August 19, 2017 PSA, the maximum permitted under the Plan of Administration for the PSA. This left $16.4 million of 2017 fuel and purchased power costs above this annual cap. These costs rolled over into the following year and were reflected in the 2019 reset of the PSA.

The PSA rate for the PSA year beginning February 1, 2019 was $0.001658 per kWh, consisting 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. That rate was $(0.000456) per kWh and consisted of a Forward Componentforward component of $(0.002086) per kWh and a Historical Componenthistorical component of $0.001630 per kWh. The 2020 PSA rate is a $0.002115 per kWh decrease compared to the 2019 PSA year. These rates went into effect as filed on February 1, 2020.

On November 30, 2020, APS filed its PSA rate for the PSA year beginning February 1, 2021. That rate was $0.003544 per kWh and consisted of a forward component of $0.003434 per kWh and a historical component of $0.000110 per kWh. The 2021 PSA rate is a $0.004 per kWh increase, compared to the 2020 PSA year. 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, with 50% of the rate increase effective in April 2021 and the remaining 50% of the increase effective in November 2021. The PSA rate implemented was $0.001544 per kWh and consisted of a forward component of $(0.004444) per kWh and a historical component of $0.005988 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.

On March 15, 2019, APS filed an application with the ACC requesting approval to recover the costs related to 2 energy storage power purchase tolling agreements through the PSA. This application is pending withOn December 29, 2020, the ACC. APS cannot predictACC Staff filed its report and recommended the outcome ofstorage costs be included in the PSA once the systems are in-service. On January 12, 2021, the ACC approved this matter.

application.

29

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Environmental Improvement Surcharge. The EIS permits APS to recover the capital carrying costs (rate of return, depreciation and taxes) plus incremental operations and maintenance expenses associated with environmental improvements made outside of a test year to comply with environmental standards set by federal, state, tribal, or local laws and regulations.  A filing is made on or before February 1st1 for qualified environmental improvements made during the prior calendar year, and the new charge becomes effective April 1 unless suspended by the ACC.  There is an overall cap of $0.0005 per kWh (approximately $13 - 14million to $14 million per year).  APS’s February 1, 20202021 application requested an increase in the charge to $8.75$10.3 million, or $2.0$1.5 million over the prior-period charge in effect for the 2019-2020 rateand it became effective year. On March 19, 2020, due to the COVID-19 pandemic, APS delayed the reset of the EIS adjustor towith the first billing cycle in May 2020 rather than April 2020.2021.
 
Transmission Rates, Transmission Cost Adjustor ("TCA"(“TCA”) and Other Transmission Matters. In July 2008, FERC approved a modification to APS’s Open Access Transmission Tariff to allow APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services.  A large portion of the rate represents charges for

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

transmission services to serve APS'sAPS’s retail customers ("(“Retail Transmission Charges"Charges”).  In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA.  Under the terms of the settlement agreement entered into in 2012 regarding APS'sAPS’s rate case ("(“2012 Settlement Agreement"Agreement”), however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC.
 
The formula rate is updated each year effective June 1 on the basis of APS'sAPS’s actual cost of service, as disclosed in APS'sAPS’s FERC Form 1 report for the previous fiscal year.  Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items.  The resolution of proposed adjustments can result in significant volatility in the revenues to be collected.  APS reviews the proposed formula rate filing amounts with the ACC Staff.  Any items or adjustments which are not agreed to by APS and the ACC Staff can remain in dispute until settled or litigated at FERC.  Settlement or litigated resolution of disputed issues could require an extended period of time and could have a significant effect on the Retail Transmission Charges because any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts.

On March 7, 2018, APS made a filing to make modifications to its annual transmission formula to provide transmission customers the benefit of the reduced federal corporate income tax rate resulting from the Tax Cuts and Jobs Act ("(“Tax Act"Act”) beginning in its 2018 annual transmission formula rate update filing. These modifications were approved by FERC on May 22, 2018 and reduced APS’s transmission rates compared to the rate that would have gone into effect absent these changes. On March 17, 2020, APS made a filing to make further 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. This filing is pending with FERC.

Effective June 1, 2018, APS's annual wholesale transmission rates for all users of its transmission system decreased by approximately $22.7 million for the twelve-month period beginning June 1, 2018 in accordance with the FERC-approved formula.  An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2018.

Effective June 1, 2019, APS'sAPS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $4.9$25.8 million for the twelve-month period beginning June 1, 2019 in accordance with the FERC-approved formula. Of this amount, retail customer rates increased by approximately $4.7 million. 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 rates for all users of its transmission system decreased by approximately $6.1 million for the twelve-month period beginning June 1, 2020 in accordance with the FERC-approved formula.  Of this amount, retail customer rates decreased by approximately $10.9 million. An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2020.
30

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Lost Fixed Cost Recovery Mechanism.  The LFCR mechanism permits APS to recover on an after-the-fact basis a portion of its fixed costs that would otherwise have been collected by APS in the kWh sales lost due to APS energy efficiency programs and to DG such as rooftop solar arrays.  The fixed costs recoverable by the LFCR mechanism were first established in the 2012 Settlement Agreement and amount to approximately 3.1 cents per residential kWh lost and 2.3 cents per non-residential kWh lost. These amounts were revised in the 2017 Settlement Agreement toare currently 2.5 cents for both lost residential and non-residential kWh.kWh as set forth in the 2017 Settlement Agreement.  The LFCR adjustment has a year-over-year cap of 1% of retail revenues.  Any amounts left unrecovered in a particular year because of this cap can be carried over for recovery in a future year.  The kWhs lost from energy efficiency are based on a third-party evaluation of APS’s energy efficiency programs.  DG sales losses are determined from the metered output from the DG units.
 
On February 15, 2018, APS filed its 2018 annual LFCR adjustment, requesting that effective May 1, 2018, the LFCR be adjusted to $60.7 million. On February 6, 2019, the ACC approved the 2018 annual LFCR

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

adjustment to become effective March 1, 2019. On February 15, 2019, APS filed its 2019 annual LFCR adjustment, requesting that effective May 1, 2019, the annual LFCR recovery amount be reduced to $36.2 million (a $24.5 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 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 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 requested as part of APS’s next LFCR application filing in 2022. The ACC has not yet released its order on this matter. APS does not anticipate that the order will have a material impact on its financial position, results of operations and cash flows.

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

On January 8, 2018, APS filed an application with the ACC that addressed the change in the marginal federal tax rate from 35% to 21% resulting from the Tax Act and reduced rates by $119.1 million annually through an equal cents per kWh credit ("(“TEAM Phase I"I”).  On February 22, 2018, the ACC approved the reduction of rates through an equal cents per kWh credit. The rate reduction was effective for the first billing cycle in March 2018.

The impact of the TEAM Phase I, over time, is expected to be earnings neutral. However, on a quarterly basis, there is a difference between the timing and amount of the income tax benefit and the reduction in revenues refunded through the TEAM Phase I related to the lower federal income tax rate. The amount of the benefit of the lower federal income tax rate is based on quarterly pre-tax results, while the reduction in revenues refunded through the TEAM Phase I is based on a per kWh sales credit which follows our seasonal kWh sales pattern and is not impacted by earnings of the Company.

On August 13, 2018, APS filed a second request with the ACC that addressed the return of an additional $86.5 million in tax savings to customers related to the amortization of non-depreciation related excess deferred taxes previously collected from customers ("(“TEAM Phase II"II”). The ACC approved this request on March 13, 2019, effective the first billing cycle in April 2019 through the last billing cycle in March 2020.
31

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 APS'sAPS’s 2019 ACC 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.

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 year28.5-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 benefit of $39.5 million to customers through December 31, 2020. It is currently anticipated that benefits relatedOn November 20, 2020, APS filed an application to continue the amortizationTEAM Phase III monthly bill credit through the earlier of depreciation related excess deferred taxes for periods beginning after December 31, 2020 will be fully incorporated into2021, or at the conclusion of APS’s 2019 pending 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.


COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Net Metering

In 2015, the ACC voted to conduct a generic evidentiary hearing on the value and cost of DG to gather information that will inform the ACC on net metering issues and cost of service studies in upcoming utility rate cases.  A hearing was held in April 2016. On October 7, 2016, the Administrative Law Judge issued a recommendation in the docket concerning the value and cost of DG solar installations. On December 20, 2016, the ACC completed its open meeting to consider the recommended opinion and order by the Administrative Law Judge. After making several amendments, the ACC approved the recommended decision by a 4-1 vote. As a result of the ACC’s action, effective with APS’s 2017 Rate Case Decision the net metering tariff that governs payments for energy exported to the grid from residential rooftop solar systems was replaced by a more formula-driven approach that utilizes inputs from historical wholesale solar power until an avoided cost methodology is developed by the ACC.

As amended, the 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 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'sAPS’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•customers who have interconnected a DG system or submitted an application for interconnection for DG systems prior to September 1, 2017, based on APS'sAPS’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;
Customers•customers with DG solar systems are to be considered a separate class of customers for ratemaking purposes; and
Once•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.

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. A first-year export energy price of 12.9 cents per kWh was included in the 2017 Settlement Agreement and became effective on September 1, 2017.

In accordance with the 2017 Rate Case Decision, APS filed its request for a second-year export energy price of 11.6 cents per kWh on May 1, 2018.  This price reflected the 10% annual reduction discussed above. The new rate rider became effective on October 1, 2018. APS filed its request for a third-year export energy price of 10.5 cents per kWh on May 1, 2019.  This price also reflects the 10% annual reduction discussed above. The new rate rider became effective on October 1, 2019. APS filed its request for a fourth-year export energy price of 9.4 cents per kWh on May 1, 2020, with a requested effective date of September 1, 2020.  This price reflects the 10% annual reduction discussed above. On September 23, 2020, the ACC approved the
32

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
annual reduction of the export energy price but voted to delay the effectiveness of the reduction in export prices until October 1, 2021. APS’s export energy price will remain at 10.5 cents per kWh until October 1, 2021.

On January 23, 2017, The Alliance for Solar Choice ("TASC"(“TASC”) sought rehearing of the ACC'sACC’s decision regarding the value and cost of DG. TASC asserted that the ACC improperly ignored the Administrative Procedure Act, failed to give adequate notice regarding the scope of the proceedings, and relied on information that was not submitted as evidence, among other alleged defects. TASC filed a Notice of Appeal in the Arizona

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Court of Appeals and filed a Complaint and Statutory Appeal in the Maricopa County Superior Court on March 10, 2017. As part of the 2017 Settlement Agreement described above, TASC agreed to withdraw these appeals when the ACC decision implementing the 2017 Settlement Agreement is no longer subject to appellate review.

See "2016“2016 Retail Rate Case Filing with the Arizona Corporation Commission"Commission” above for information regarding an ACC order in connection with the rate review of the 2017 Rate Case Decision requiring APS to provide grandfathered net metering customers on legacy demand rates with an opportunity to switch to another legacy rate to enable such customers to benefit from legacy net metering rates.

Subpoena from Former Arizona Corporation Commissioner Robert Burns

On August 25, 2016, Commissionerthen-Commissioner Robert Burns, individually and not by action of the ACC as a whole, served subpoenas in APS’s then current retail rate proceeding on APS and Pinnacle West for the production of records and information relating to a range of expenditures from 2011 through 2016. The subpoenas requested information concerning marketing and advertising expenditures, charitable donations, lobbying expenses, contributions to 501(c)(3) and (c)(4) nonprofits and political contributions. The return date for the production of information was set as September 15, 2016. The subpoenas also sought testimony from Company personnel having knowledge of the material, including the Chief Executive Officer.

On September 9, 2016, APS filed with the ACC a motion to quash the subpoenas or, alternatively to stay APS'sAPS’s obligations to comply with the subpoenas and decline to decide APS'sAPS’s motion pending court proceedings. Contemporaneously with the filing of this motion, APS and Pinnacle West filed a complaint for special action and declaratory judgment in the Superior Court of Arizona for Maricopa County, seeking a declaratory judgment that Commissioner Burns’ subpoenas are contrary to law. On September 15, 2016, APS produced all non-confidential and responsive documents and offered to produce any remaining responsive documents that are confidential after an appropriate confidentiality agreement is signed.

On February 7, 2017, Commissioner Burns opened a new ACC docket and indicated that its purpose is to study and rectify problems with transparency and disclosure regarding financial contributions from regulated monopolies or other stakeholders who may appear before the ACC that may directly or indirectly benefit an ACC Commissioner, a candidate for ACC Commissioner, or key ACC Staff.  As part of this docket, Commissioner Burns set March 24, 2017 as a deadline for the production of all information previously requested through the subpoenas. Neither APS nor Pinnacle West produced the information requested and instead objected to the subpoena. On March 10, 2017, Commissioner Burns filed suit against APS and Pinnacle West in the Superior Court of Arizona for Maricopa County in an effort to enforce his subpoenas. On March 30, 2017, APS filed a motion to dismiss Commissioner Burns'Burns’ suit against APS and Pinnacle West. In response to the motion to dismiss, the court stayed the suit and ordered Commissioner Burns to file a motion to compel the production of the information sought by the subpoenas with the ACC. On June 20, 2017, the ACC denied the motion to compel.

On August 4, 2017, Commissioner Burns amended his complaint to add all of the ACC Commissioners and the ACC itself as defendants. All defendants moved to dismiss the amended complaint. On February 15, 2018, the
33

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Superior Court dismissed Commissioner Burns’ amended complaint. On March 6, 2018, Commissioner Burns filed an objection to the proposed final order from the Superior Court and a motion to further amend his complaint. The Superior Court permitted Commissioner Burns to amend his complaint to add a claim regarding his attempted investigation into whether his fellow commissioners should have been disqualified from voting on APS’s 2017 rate case. Commissioner Burns filed his second amended complaint, and all defendants filed responses opposing the second amended complaint and requested that it be dismissed.

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Oral argument occurred in November 2018 regarding the motion to dismiss. On December 18, 2018, the trial court granted the defendants’ motions to dismiss and entered final judgment on January 18, 2019.

On February 13, 2019, Commissioner Burns filed a notice of appeal. On July 12, 2019, Commissioner Burns filed his opening brief in the Arizona Court of Appeals. APS filed its answering brief on October 21, 2019. The Arizona Court of Appeals originally granted the request for oral argument; however, on March 31, 2020, the court vacated the date scheduled for oral argument given the COVID-19 pandemic.  The court determined that the matter could be submitted without oral argument and has taken the matter under advisement and will issue a decision without oral argument.

Burns’ position as an ACC commissioner ended on January 4, 2021. Nevertheless, Burns filed a motion with the Court of Appeals arguing that the appeal was not mooted by this fact and the court should decide the matter. Both APS and the ACC filed responses opposing the motion and asserting that the matter is moot. Pinnacle West and APS cannot predict the outcome of this matter.

Information Requests from Arizona Corporation Commissioners

On January 14, 2019, ACC Commissioner Kennedy opened a docket to investigate campaign expenditures and political participation of APS and Pinnacle West. In addition, on February 27, 2019, ACC Commissioners Burns and Dunn opened a new docket and requested documents from APS and Pinnacle West related to ACC elections and charitable contributions related to the ACC. On March 1, 2019, ACC Commissioner Kennedy issued a subpoena to APS seeking several categories of information for both Pinnacle West and APS, including political contributions, lobbying expenditures, marketing and advertising expenditures, and contributions made to 501(c)(3) and 501(c)(4) entities, for the years 2013-2018. Pinnacle West and APS voluntarily responded to both sets of requests on March 29, 2019. APS also received and responded to various follow-on requests from ACC Commissioners on these matters. Pinnacle West and APS cannot predict the outcome of these matters. The Company'sCompany’s CEO, Mr. Guldner, appeared at the ACC'sACC’s January 14, 2020 Open Meeting regarding ACC Commissioners'Commissioners’ questions about political spending.  Mr. Guldner committed to the ACC that, during his tenure, Pinnacle West and APS, and any of their affiliated companies, will not participate in ACC campaign elections through financial contributions or in-kind contributions.

Energy Modernization Plan

On January 30, 2018, former ACC Commissioner Tobin proposed the Energy Modernization Plan, 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"(“IRP”) process. In August 2018, the ACC directed ACC Staff to open a new rulemaking docket which will address a wide range of energy issues, including the Energy Modernization Plan proposals. The rulemaking will consider possible modifications to existing ACC rules, such as the RES, Electric and Gas Energy Efficiency Standards, Net Metering, Resource Planning, and the Biennial Transmission Assessment, as well as the development of new rules regarding forest bioenergy, electric vehicles, interconnection of distributed
34

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
generation, baseload security, blockchain technology and other technological developments, retail competition, and other energy-related topics.

On April 25, 2019, the ACC Staff issued aan initial set of draft energy rules in regardsand held various workshops to incorporate feedback from stakeholders and ACC Commissioners from April 2019 through July 2020. At the Energy Modernization Plan and workshops were held on April 29, 2019 regarding theseMarch 11-12, 2020 workshop, the ACC Staff committed to filing a final draft rules.of proposed rules by July 2020. On July 2, 2019,30, 2020, the ACC Staff issued a revised set offinal draft energy rules which proposeproposed 100% of retail kWh sales from clean energy resources by the end of 2050. Nuclear is defined as a RES goal of 45%clean energy resource. The proposed rules also require 50% of retail energy served be renewable by 2035 and a goalthe end of 20% of retail sales during peak demand to be from clean2035. A new energy resources by 2035.  The draft rules also require a certain amount ofefficiency standard was not included in the RES goal to be derived from distributed renewable storage, for which utilitiesproposed rules. APS would be required to offer performance-based incentives.  Nuclear energyobtain approval of its action plan included in its IRP and seek recovery of prudently incurred costs in a rate process. If approved by the ACC Commissioners, the rules would be consideredrequire utilities to file a clean resource under the draft rules. The ACC held various stakeholder meetingsClean Energy Implementation Plan and workshops on ACC Staff’s draft energy rulesEnergy Efficiency Report as part of their IRP every three years beginning in July through September 2019. On February 18, 2020,2023. In addition, the ACC Staff issued a revised proposed set of draft rules which would change the RES and clean energy goals to standards and would provide additional reporting and compliance requirements. In addition, ACC Staff proposed

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

changing the IRP planning horizon from 15 years to 10 years. Certain

The ACC Commissioners havehas discussed the final draft energy rules at several different meetings in 2020. On October 14, 2020, the ACC passed one amendment to ACC Staff’s final draft energy rules that will require electric utilities to obtain 35% of peak load (as measured in 2020) by 2030 from DSM resources, including traditional energy efficiency, demand response and other programs aimed at reducing energy usage, peak demand management and load shifting. This standard aligns with the proposed different optionsrules’ three-year resource planning cycle and allows recovery of costs through existing mechanisms until the ACC issues a decision in a future rate proceeding. On October 29, 2020, the ACC approved an amendment that will require electric utilities to reduce their carbon emissions over 2016-2018 levels by 50% by 2032; 75% by 2040; and 100% by 2050. The ACC also approved an amendment that will require utilities to install energy storage systems with different implementation datesan aggregate capacity equal to 5% of these rules.each utility’s 2020 peak demand by 2035, of which 40% must be derived from customer-owned or customer-leased distributed storage. Another approved amendment modifies the resource planning process, including requirements for the ACC to approve a utility’s load forecast and resource plan, and for a utility to perform an all-source request for information to guide its resource plan. On November 13, 2020, the ACC approved a final draft energy rules package. On April 19, 2021, the Administrative Law Judge issued a Recommended Order and Opinion on the final energy rules and the ACC will need to review and approve the Recommended Order and Opinion before the rules will take effect. APS cannot predict the outcome of this matter.

Integrated Resource Planning

ACC rules require utilities to develop 15-year IRPs which describe how the utility plans to serve customer load in the plan timeframe.  The ACC reviews each utility’s IRP to determine if it meets the necessary requirements and whether it should be acknowledged.  In March of 2018, the ACC reviewed the 2017 IRPs of its jurisdictional utilities and voted to not acknowledge any of the plans.  APS does not believe that this lack of acknowledgment will have a material impact on our financial position, results of operations or cash flows.  Based on an ACC decision, APS was originally required to file its next IRP by April 1, 2020.  On February 20, 2020, the ACC extended the deadline for all utilities to file their IRP’s from April 1, 2020 to June 26, 2020. On June 26, 2020, APS filed its final IRP. On July 15, 2020, the ACC extended the schedule for final ACC review of utility IRPs to February 2021. In March 2021, the ACC Staff requested additional time to prepare its assessment of utility IRPs. The ACC has taken no action on APS’s IRP. APS cannot predict the outcome of this matter. See "Energy“Energy Modernization Rules"Plan” above for information regarding proposed changes to the IRP filings.

Public Utility Regulatory Policies Act

In August 2016, APS filed an application requesting that allUnder the Public Utility Regulatory Policies Act of its contracts with1978 (“PURPA”), qualifying facilities over 100 kW be set at a presumptive maximum 2 year term. A qualifying facility is an eligible energy-producing facility as defined by FERC regulations within a host electric utility’s service territory that has aare provided the right to sell energy and/or capacity to the host utility. Host utilities and are required to purchase powergranted relief from qualifying facilities at an avoided cost as determined by the utility subject to state commission oversight. A hearing was held in August 2019 and briefing on this matter was completed in October 2019 regarding APS’s application.certain regulatory burdens. On
35

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
December 17, 2019, the ACC denied the application and mandated a minimum contract length of 18 years for qualifying facilities over 100 kW in Arizona, and established that the rate paid to the qualifying facilities willmust be based on the long-term avoided cost. “Avoided cost” is generally defined as the price at which the utility could purchase or produce the same amount of power from sources other than the qualifying facility on a long-term basis. During calendar year 2020, APS entered into 2 18-year power purchase agreements with qualified facilities, each for 80 MW solar facilities. In March 2021, the ACC approved these agreements.

On July 16, 2020, FERC issued a final rule revising FERC’s regulations implementing PURPA. The final rule went into effect on December 31, 2020. APS is in discussions with qualifying facility developers but has not entered into any new qualifying facility agreements that would be subject toevaluating how the new requirements of the ACC's decision.revised regulations may impact its operations.

Residential Electric Utility Customer Service Disconnections

On June 13, 2019, APS voluntarily suspended electric disconnections for residential customers who had not paid their bills. On June 20, 2019, the ACC voted to enact emergency rule amendments to prevent residential electric utility customer service disconnections during the period from June 1 through October 15 ("(“Summer Disconnection Moratorium"Moratorium”). During the Summer Disconnection Moratorium, APS could not charge late fees and interest on amounts that were past due from customers. Customer deposits must also be used to pay delinquent amounts before disconnection can occur and customers will have four months to pay back their deposit and any remaining delinquent amounts. In accordance with the emergency rules, APS began putting delinquent customers on a mandatory four-month payment plan beginning on October 16, 2019. The emergency rule changes will be effective for 180 days and may be renewed for one additional 180-day period.


In addition, in June 2019, the ACC began a formal regular rulemaking process to allow stakeholder input and time for consideration of permanent rule changes. The ACC further ordered that each regulated electric utility serving retail customers in Arizona update its service conditions by incorporating the emergency rule amendments, restore power to any customers who were disconnected during the month of June 2019 and credit any fees that were charged for a reconnection. The ACC Staff issuedand ACC proposed draft amendments to the customer service disconnections rules. Stakeholders submitted initial comments to the draft amendments on September 23, 2019. ACC stakeholder meetings were held in September 2019, October 2019 and January 2020 regarding the customer service disconnections rules.

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Although On April 14, 2021, the emergencyACC voted to send to the formal rulemaking process a draft rules expired in December 2019,package governing customer disconnections that allows utilities to choose between a temperature threshold (above 95 degrees and below 32 degrees) or calendar threshold (June 1 – October 15) for disconnection moratoriums. During the formal rulemaking process, the public will have an opportunity to provide input on the draft rules, before the draft rules come back to the ACC for a final vote. The Summer Disconnection Moratorium will remain in effect through utility tariffs for 2020 and beyond until the ACC adopts permanentformalizes the final rules or determines otherwise.package.

Due to the COVID-19 pandemic, APS has voluntarily suspended disconnections of customers for nonpayment and waived late payment fees beginning March 13, 2020 until December 31, 2020. APS currently estimates that the Summer Disconnection Moratorium, theThe suspension of disconnections duringdisconnection of customers for nonpayment ended on January 1, 2021 and customers were automatically placed on eight-month payment arrangements if they had past due balances at the COVID-19 pandemicend of the disconnection period of $75 or greater. APS will continue to waive late payment fees until October 15, 2021. APS has experienced and the increasedis continuing to experience an increase in bad debt expense associated with both events will result in a negative impact to its 2020 operating results of approximately $20 to $30 million pre-tax above the impact of disconnections on its operating results for years that did not have the Summer Disconnection Moratorium or COVID-19 pandemic. These estimated impact amounts depend on certain assumptions, including customer behaviors, the impacts of COVID-19 on the economy not extending into 2021 and the results of final rulemaking related to the Summer Disconnection Moratorium. See "COVID-19 Pandemic"“COVID-19 Pandemic” above for more information.

Retail Electric Competition Rules

On November 17, 2018, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona. An ACC special open meeting workshop was held on December 3, 2018. No substantive action was taken, but interested parties were asked to submit written comments and respond to a list of questions from ACC Staff. On July 1 and July 2, 2019, ACC Staff issued a report and initial proposed draft
36

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
rules regarding possible modifications to the ACC’s retail electric competition rules. Interested parties filed comments to the ACC Staff report and a stakeholder meeting and workshop to discuss the retail electric competition rules was held on July 30, 2019. ACC Commissioners submitted additional questions regarding this matter. On February 10, 2020, two ACC Commissioners filed two sets of draft proposed retail electric competition rules. On February 12, 2020, ACC staffStaff issued its second report regarding possible modifications to the ACC’s retail electric competition rules. The ACC held a workshop on February 25-26, 2020 foron further consideration and discussion of the retail electric competition rules. During a July 15, 2020 ACC Staff meeting, the ACC Commissioners discussed the possible development of a retail competition pilot program, but no action was taken. The ACC Commissioners are continuing to explore the retail electric competition rules. 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.

Rate Plan Comparison Tool and Investigation

On November 14, 2019, APS learned that its rate plan comparison tool was not functioning as intended due to an integration error between the tool and the Company’sAPS’s meter data management system. APS immediately removed the tool from its website and notified the ACC. The purpose of the tool was to provide customers with a rate plan recommendation based upon historical usage data. Upon investigation, APS determined that the error may have affected rate plan recommendations to customers between February 4, 2019 and November 14, 2019. By the middle of May 2020, APS is providingprovided refunds to approximately 13,000 potentially impacted customers equal to the difference between what they paid for electricity and the amount they would have paid had they selected their most economical rate, as applicable, and a $25 payment for any inconvenience that the customer may have experienced. The refunds and payment for inconvenience being provided isdid not expected to have a material impact on APS'sAPS’s financial statements. APS developed a new tool for comparing customers’ rate plan options.  APS had an independent third party verify that the new rate comparison tool works correctly.  In February 2020, APS launched the new online rate comparison tool, which is now available for its customers. The ACC is currently investigating this matter and has hired an outside consultant to evaluate the extent of the error and the overall effectiveness of the tool. On August 20, 2020, ACC Staff filed the outside consultant’s report on APS’s rate comparison tool. The report concluded APS’s new rate comparison tool is working as intended. The report also identified a small population of additional customers that may have been affected by the error and APS has provided refunds and the $25 inconvenience payment to approximately 3,800 additional customers. These additional refunds and payment for inconvenience did not have a material impact on APS’s financial statements. On September 28, 2020, the ACC discussed this report but did not take any action. APS cannot predict if any action will be taken by the ACC at this time.

APS received a civil investigative demanddemands from the Office of the Arizona Attorney General, Civil Litigation Division, Consumer Protection & Advocacy Section that seeks(“Attorney General”) seeking information pertaining to the rate plan comparison tool offered to APS customers.customers and other related issues including implementation of rates from the 2017 Settlement Agreement and its Customer Education and Outreach Plan associated with the 2017 Settlement Agreement. APS is fully cooperatingcooperated with the Attorney General’s Office in this matter. On February 22, 2021 APS entered into a consent agreement with the Attorney General as a way to settle the matter. The settlement results in APS paying $24.75 million, $24 million of which is being returned to customers as restitution. While this matter has been resolved with the Attorney General, APS cannot predict whether additional inquiries or actions may be taken by the outcome of these matters.ACC.


COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Four Corners SCR Cost Recovery

On December 29, 2017, in accordance with the 2017 Rate Case Decision, APS filed a Notice of Intent to file its SCR Adjustment to permit recovery of costs associated with the installation of SCR equipment at Four Corners Units 4 and 5.  APS filed the SCR Adjustment request in April 2018.  Consistent with the 2017
37

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Rate Case Decision, the request was narrow in scope and addressed only costs associated with this specific environmental compliance equipment.  The SCR Adjustment request provided that there would be a $67.5 million annual revenue impact that would be applied as a percentage of base rates for all applicable customers.  Also, as provided for in the 2017 Rate Case Decision, APS requested that the adjustment become effective no later than January 1, 2019.  The hearing for this matter occurred in September 2018.  At the hearing, APS accepted ACC Staff'sStaff’s recommendation of a lower annual revenue impact of approximately $58.5 million. The Administrative Law Judge issued a Recommended Opinion and Order finding that the costs for the SCR project were prudently incurred and recommending authorization of the $58.5 million annual revenue requirement related to the installation and operation of the SCRs. Exceptions to the Recommended Opinion and Order were filed by the parties and intervenors on December 7, 2018.  The ACC has not issued a decision on this matter. APS included the costs for the SCR project in the retail rate base in its 2019 retail rate caseRetail Rate Case filing with the ACC. On March 18, 2020, the ACC agreed to take administrative notice to include in the pending rate case portions of the record in this prior proceeding that are relevant to the SCRs. APS cannot predict the outcome or timing of the decision on this matter. APS may be required to record a charge to its results of operations if the ACC issues an unfavorable decision (see SCR deferral in the Regulatory Assets and Liabilities table below).

Cholla

On September 11, 2014, APS announced that it would close Unit 2 of the Cholla Power Plant ("Cholla"(“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"(“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'sAPS’s plan to retire Unit 2, without expressing any view on the future recoverability of APS'sAPS’s remaining investment in the unit. APS closed Unit 2 on October 1, 2015. In early 2017, EPA approved a final rule incorporating APS'sAPS’s compromise proposal, which took effect on April 26, 2017. In December 2019, PacifiCorp notified APS that it plansplanned to retire Cholla Unit 4 by the end of 2020. Cholla Unit 4 was retired on December 24, 2020.

Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS has been recovering a return on and of the net book value of the unit in base rates. Pursuant to the 2017 Settlement Agreement described above, APS will be allowed continued recovery of the net book value of the unit and the unit’s decommissioning and other retirement-related costs ($6952.9 million as of March 31, 2020)2021), in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. The 2017 Settlement Agreement also shortened the depreciation lives of Cholla Units 1 and 3 to 2025.
On March 20, 2019, APS announced that it began evaluating the feasibility and cost of converting a unit at Cholla to burn biomass. Biomass is a fuel comprised of forest trimmings, and a converted unit at Cholla could assist in forest thinning, responsible forest management, an improved watershed, and a reduced wildfire risk. APS’s ability to operate a biomass power plant would depend on third-parties procuring forest biomass for fuel. APS reported the results of its evaluation on May 9, 2019 to the ACC. On July 10, 2019, the ACC voted to not require APS to file a request for proposal to convert the unit at Cholla to burn biomass.

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Navajo Plant

The co-owners of the Navajo Plant and the Navajo Nation agreed that the Navajo Plant would remainceased operations in operation until December 2019 under the existing plant lease.November 2019. The co-owners and the Navajo Nation executed a lease extension on November 29, 2017 that allows for decommissioning activities to begin after the plant ceased operations in November 2019.
operations.
APS is currently recovering depreciation and a return on the net book value of its interest in the Navajo Plant over its previously estimated life through 2026. APS will seek continued recovery in rates for the book value of its remaining investment in the plant ($7969.4 million as of March 31, 2020)2021) plus a return on the net book value as well as other costs related to retirement and closure, which are still being assessed and may be material.including the Navajo coal reclamation regulatory asset ($17.8 million as of March 31, 2021). APS believes it will be allowed recovery of the net book value, retirement and closure costs, in addition to a return on its investment. In accordance with GAAP, in the second quarter of 2017, APS'sAPS’s remaining net book value of its interest in the Navajo Plant was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery
38

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
of the remaining net book value of this interest, all or a portion of the regulatory asset will be written off and APS'sAPS’s net income, cash flows, and financial position will be negatively impacted.

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Regulatory Assets and Liabilities 

The detail of regulatory assets is as follows (dollars in thousands): 
 Amortization ThroughMarch 31, 2021December 31, 2020
 CurrentNon-CurrentCurrentNon-Current
Pension(a)$0 $467,423 $0 $469,953 
Deferred fuel and purchased power (b) (c)2022228,609 0 175,835 0 
Income taxes — allowance for funds used during construction (“AFUDC”) equity20517,169 159,119 7,169 158,776 
Retired power plant costs203328,182 107,169 28,181 114,214 
Ocotillo deferralN/A0 110,820 0 95,723 
SCR deferralN/A0 88,044 0 81,307 
Deferred property taxes20278,569 47,484 8,569 49,626 
Lost fixed cost recovery (b)202245,905 0 41,807 0 
Deferred compensation20360 35,806 0 36,195 
Four Corners cost deferral20248,077 22,056 8,077 24,075 
Income taxes — investment tax credit basis adjustment20491,113 24,221 1,113 24,291 
Palo Verde VIEs (Note 6)20460 21,409 0 21,255 
Coal reclamation20261,068 16,732 1,068 16,999 
Loss on reacquired debt20381,703 10,486 1,689 10,877 
Mead-Phoenix transmission line contributions in aid of construction (“CIAC”)2050332 9,297 332 9,380 
Demand side management (b)20210 7,268 0 7,268 
Tax expense adjustor mechanism (b)20215,854 0 6,226 0 
Tax expense of Medicare subsidy20241,235 3,626 1,235 3,704 
Deferred fuel and purchased power — mark-to-market (Note 7)20240 3,728 3,341 9,244 
PSA interest202246 0 4,355 0 
OtherVarious2,018 1,169 2,716 1,100 
Total regulatory assets (d) $339,880 $1,135,857 $291,713 $1,133,987 
 Amortization Through March 31, 2020 December 31, 2019
  Current Non-Current Current Non-Current
Pension(a) $—
 $652,691
 $—
 $660,223
Retired power plant costs2033 28,182
 135,349
 28,182
 142,503
Income taxes — allowance for funds used during construction ("AFUDC") equity2050 6,815
 155,369
 6,800
 154,974
Deferred fuel and purchased power — mark-to-market (Note 7)2024 51,954
 32,576
 36,887
 33,185
Deferred fuel and purchased power (b) (c)2021 77,730
 —
 70,137
 —
Deferred property taxes2027 8,569
 56,053
 8,569
 58,196
SCR deferralN/A —
 58,258
 —
 52,644
Ocotillo deferralN/A —
 51,767
 —
 38,144
Four Corners cost deferral2024 8,077
 30,133
 8,077
 32,152
Deferred compensation2036 —
 37,550
 —
 36,464
Lost fixed cost recovery (b)2021 28,885
 —
 26,067
 —
Income taxes — investment tax credit basis adjustment2048 1,098
 24,920
 1,098
 24,981
Palo Verde VIEs (Note 6)2046 —
 20,790
 —
 20,635
Coal reclamation2026 1,068
 17,800
 1,546
 17,688
Loss on reacquired debt2038 1,637
 11,636
 1,637
 12,031
Mead-Phoenix transmission line contributions in aid of construction ("CIAC")2050 332
 9,629
 332
 9,712
TCA balancing account (b)2021 6,048
 1,027
 6,324
 2,885
Tax expense of Medicare subsidy2024 1,238
 4,881
 1,235
 4,940
AG-1 deferral2022 2,787
 2,019
 2,787
 2,716
Tax expense adjuster mechanism (b)2020 942
 —
 1,612
 —
OtherVarious 109
 —
 1,917
 —
Total regulatory assets (d)  $225,471
 $1,302,448
 $203,207
 $1,304,073


(a)This asset represents the future recovery of pension benefit obligations through retail rates.  If these costs are disallowed by the ACC, this regulatory asset would be charged to other comprehensive income ("OCI") and result in lower future revenues.
(b)See "Cost Recovery Mechanisms" discussion above.
(c)Subject to a carrying charge.
(d)There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base.  FERC rates are set using a formula rate as described in "Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters."

(a)This asset represents the future recovery of pension benefit obligations through retail rates.  If these costs are disallowed by the ACC, this regulatory asset would be charged to other comprehensive income (“OCI”) and result in lower future revenues. See Note 5.
(b)See “Cost Recovery Mechanisms” discussion above.
(c)Subject to a carrying charge.
(d)There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base.  FERC rates are set using a formula rate as described in “Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.”


39

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The detail of regulatory liabilities is as follows (dollars in thousands):
 
 Amortization ThroughMarch 31, 2021December 31, 2020
 CurrentNon-CurrentCurrentNon-Current
Excess deferred income taxes - ACC - Tax Cuts and Jobs Act (a)2046$41,353 $1,004,226 $41,330 $1,012,583 
Excess deferred income taxes - FERC - Tax Cuts and Jobs Act (a)20587,240 228,690 7,240 229,147 
Asset retirement obligations20570 519,015 0 506,049 
Other postretirement benefits(d)37,705 337,853 37,705 349,588 
Removal costs(c)55,247 89,937 52,844 103,008 
Income taxes — change in rates20502,839 66,374 2,839 66,553 
Four Corners coal reclamation20385,461 49,703 5,460 49,435 
Income taxes — deferred investment tax credit20492,231 48,507 2,231 48,648 
Spent nuclear fuel20276,831 43,059 6,768 44,221 
Renewable energy standard (b)202234,460 30 39,442 103 
Deferred fuel and purchased power — mark-to-market (Note 7)202220,829 0 0 0 
Property tax deferralN/A0 15,022 0 13,856 
Sundance maintenance20312,867 11,910 2,989 11,508 
Demand side management (b)20227,821 5,975 10,819 0 
FERC transmission true up20237,630 2,379 6,598 3,008 
TCA balancing account (b)20227,315 1,754 2,902 4,672 
Tax expense adjustor mechanism (b) (e)20217,452 0 7,089 0 
Deferred gains on utility property20222,423 939 2,423 1,544 
Active union medical trustN/A0 2,337 0 6,057 
OtherVarious524 59 409 189 
Total regulatory liabilities $250,228 $2,427,769 $229,088 $2,450,169 

(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.
(b)See “Cost Recovery Mechanisms” discussion above.
(c)In accordance with regulatory accounting guidance, APS accrues removal costs for its regulated assets, even if there is no legal obligation for removal.
(d)See Note 5.
(e)Pursuant to Decision 77852, the ACC has authorized APS to return to customers up to $7 million of liability recorded to the TEAM balancing account through December 31, 2021. Should new base rates become effective prior to December 31, 2021, any remaining unreturned balance is anticipated to be included in the new base rates.

 Amortization Through March 31, 2020 December 31, 2019
  Current Non-Current Current Non-Current
Excess deferred income taxes - ACC - Tax Cuts and Jobs Act (a)2046 $113,142
 $976,018
 $59,918
 $1,054,053
Excess deferred income taxes - FERC - Tax Cuts and Jobs Act (a)2058 6,315
 237,508
 6,302
 237,357
Asset retirement obligations2057 —
 311,517
 —
 418,423
Removal costs(c) 44,586
 135,450
 47,356
 136,072
Other postretirement benefits(d) 37,575
 130,270
 37,575
 139,634
Spent nuclear fuel2027 6,638
 49,234
 6,676
 51,019
Income taxes — change in rates2050 2,802
 51,152
 2,797
 68,265
Four Corners coal reclamation2038 5,461
 48,405
 1,059
 51,704
Income taxes — deferred investment tax credit2048 2,202
 49,910
 2,202
 50,034
Renewable energy standard (b)2021 45,872
 115
 39,287
 10,300
Demand side management (b)2021 1,702
 43,423
 15,024
 24,146
Sundance maintenance2031 184
 13,515
 5,698
 11,319
Active union medical trustN/A —
 7,986
 —
 2,041
Property tax deferralN/A —
 7,968
 —
 7,046
Tax expense adjustor mechanism (b)2020 6,615
 —
 7,018
 —
Deferred gains on utility property2022 2,423
 3,577
 2,423
 4,163
FERC transmission true up2022 3,304
 1,621
 1,045
 2,004
OtherVarious 284
 132
 532
 255
Total regulatory liabilities  $279,105
 $2,067,801
 $234,912
 $2,267,835

(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.
(b)See “Cost Recovery Mechanisms” discussion above.
(c)In accordance with regulatory accounting guidance, APS accrues removal costs for its regulated assets, even if there is no legal obligation for removal.
(d)See Note 5.

5.
5.Retirement Plans and Other Postretirement Benefits
 
Pinnacle West sponsors a qualified defined benefit and account balance pension plan, a non-qualified supplemental excess benefit retirement plan, and an other postretirement benefit planplans for the employees of Pinnacle West and our subsidiaries.  The other postretirement benefit plans include a group life and medical plan and a post-65 retiree health reimbursement arrangement (“HRA”). Pinnacle West uses a December 31
40

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
measurement date each year for its pension and other postretirement benefit plans.  The market-related value of our plan assets is their fair value at the measurement dates.date.


Under the HRA, included in the other postretirement benefit plan, the Company provides a subsidy to retirees to defray the cost of a Medicare supplemental policy. In prior years, we had been assuming a 4.75% escalation of these benefits; however, actual escalation has been significantly less than this assumption. Accordingly, during 2020 and for future periods, the escalation assumption was reduced to 2.00%. This escalation factor assumption change, among other factors, resulted in an increase in the over-funded status of the other postretirement benefit plan as of December 31, 2020. As a result, on January 4, 2021, we initiated the transfer of approximately $106 million of assets from the other postretirement benefit plan into the Active Union Employee Medical Account. The Active Union Employee Medical Account is an existing trust account that holds assets restricted for paying active union employee medical costs (see Note 12). The transfer of other postretirement benefit plan assets into the Active Union Employee Medical Account permits access to approximately $106 million of assets for the sole purpose of paying active union employee medical benefits. This transfer of assets into the Active Union Employee Medical Account is consistent with the terms of a similar 2018 transaction.
COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

 Pension BenefitsOther Benefits
 Three Months Ended
March 31,		 Three Months Ended
March 31,
 2020 2019 2020 2019
Service cost — benefits earned during the period$14,257
 $12,543
 $5,717
 $4,714
Non-service costs (credits):       
Interest cost on benefit obligation29,761
 34,352
 6,512
 7,526
Expected return on plan assets(46,806) (42,893) (10,019) (9,603)
  Amortization of: 
    
  
  Prior service credit—
 —
 (9,394) (9,455)
  Net actuarial loss9,011
 11,239
 —
 —
Net periodic benefit cost (credit)$6,223
 $15,241
 $(7,184) $(6,818)
Portion of cost (credit) charged to expense$1,342
 $8,244
 $(5,456) $(4,817)

 Pension BenefitsOther Benefits
 Three Months Ended
March 31,		Three Months Ended
March 31,
 2021202020212020
Service cost — benefits earned during the period$15,679 $14,257 $4,557 $5,717 
Non-service costs (credits):
Interest cost on benefit obligation24,669 29,761 4,162 6,512 
Expected return on plan assets(50,608)(46,806)(10,361)(10,019)
  Amortization of:   
  Prior service credit0 0 (9,427)(9,394)
  Net actuarial loss (gain)3,985 9,011 (2,405)0 
Net periodic benefit cost/(benefit)$(6,275)$6,223 $(13,474)$(7,184)
Portion of cost/(benefit) charged to expense$(8,011)$1,342 $(9,528)$(5,456)
 
Contributions
 
We have not0t made voluntary contributions to our pension plan year-to-date in 2020.2021. The minimum required contributions for the pension plan are 0 for the next three years. We expect to make voluntary contributions up to $100 million per year during the 2020-2022 period.in 2021 and 0 in 2022 and 2023. We do not0t expect to make any contributions over the next three yearsthis period to our other postretirement benefit plans.
 
41
6.

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
6.    Palo Verde Sale Leaseback Variable Interest Entities
 
In 1986, APS entered into agreements with 3 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 willthe right to retain the assets through 2023 under 1 lease and 2033 under the other 2 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 be required to make payments relating to thesethe 3 leases in total of approximately $23$21 million annually for the period 2020 through 2023, and $16 million annually for the period 20242021 through 2033. At the end of the lease period, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to two years, or return the assets to the lessors.

The leases'leases’ terms give APS the ability to utilize the assets for a significant portion of the assets’ economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the VIEs’ economic performance.  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 for the three months ended March 31, 20202021 and 20192020 of $5 million, for each period, entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders is not impacted by the consolidation.

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Our Condensed Consolidated Balance Sheets at March 31, 20202021 and December 31, 20192020 include the following amounts relating to the VIEs (dollars in thousands):
 
 March 31, 2020 December 31, 2019
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation$100,938
 $101,906
Equity — Noncontrolling interests127,414
 122,540

March 31, 2021December 31, 2020
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation$97,068 $98,036 
Equity — Noncontrolling interests124,164 119,290 
 
Assets of the VIEs are restricted and may only be used for payment to the noncontrolling interest holders. These assets are reported on our condensed consolidated financial statements.
 
APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur.  Under certain circumstances (for example, the Nuclear Regulatory Commission ("NRC"(“NRC”) issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value.  If such an event were to occur during the lease periods, APS may be required to pay the noncontrolling equity participants approximately $304$307 million beginning in 2020,2021, and up to $456$501 million over the lease extension terms.
 
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.

42

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
7.    Derivative Accounting
 
Derivative financial instruments are used to manage exposure to commodity price and transportation costs of electricity, natural gas, emissions allowances, and in interest rates.  Risks associated with market volatility are managed by utilizing various physical and financial derivative instruments, including futures, forwards, options and swaps.  As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and fuels.natural gas.  Derivative instruments that meet certain hedge accounting criteria may be designated as cash flow hedges and are used to limit our exposure to cash flow variability on forecasted transactions.  The changes in market value of such instruments have a high correlation to price changes in the hedged transactions.  Derivative instruments are also entered into for economic hedging purposes.  While economic hedges may mitigate exposure to fluctuations in commodity prices, these instruments have not been designated as accounting hedges.  Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our Condensed 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 sheets as an asset or liability and are measured at fair value.  See Note 11 for a discussion of fair value measurements.  Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery and the quantities represent those transacted in the normal course of business.  Derivative instruments qualifying for the normal purchases and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below.

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 
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 (see Note 4).  Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.
 
As of March 31, 2020 and December 31, 2019, we hadThe following table shows the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): 
Quantity
CommodityUnit of MeasureMarch 31, 2021December 31, 2020
PowerGWh368 368 
GasBillion cubic feet211 205 
   Quantity
Commodity Unit of MeasureMarch 31, 2020 December 31, 2019
Power GWh477
 193
Gas Billion cubic feet263
 257
43

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 during(dollars in thousands):
 Financial Statement LocationThree Months Ended
March 31,
Commodity Contracts20212020
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)Fuel and purchased power (b)$0 $(414)

(a)During the three months ended March 31, 2021 and 2020, and 2019 (dollars in thousands):we had 0 gains or losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.
(b)
  Financial Statement Location Three Months Ended
March 31,
Commodity Contracts  2020 2019
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a) Fuel and purchased power (b) $(414) $(436)

(a)
During the three months ended March 31, 2020 and 2019, we had 0 gains or losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.Amounts are before the effect of PSA deferrals.
(b)Amounts are before the effect of PSA deferrals.
 
During the next twelve months, we estimate that a net loss of approximately $0.3 million before income taxes0 amounts will be reclassified from accumulated OCI as an offset tointo income. For APS, the effect of market price changesdelivery period for the related hedged transactions.  In accordance with the PSA, most of these amounts will be recorded as either a regulatory asset or liability andall derivative instruments in designated cash flow accounting hedging relationships have no immediate effect on earnings.lapsed.


COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the three months ended March 31, 2020 and 2019 (dollars in thousands):
 Financial Statement Location Three Months Ended
March 31,		 Financial Statement LocationThree Months Ended
March 31,
Commodity Contracts 2020 2019Commodity Contracts20212020
Net Gain (Loss) Recognized in Income Fuel and purchased power (a) $(30,078) $8,170
Net Gain (Loss) Recognized in IncomeFuel and purchased power (a)$26,859 $(30,078)

(a)Amounts are before the effect of PSA deferrals.
(a)Amounts are before the effect of PSA deferrals.
 
Derivative Instruments in the Condensed 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.  Agreements that allow for the offsetting of positive and negative exposures associated with a single counterparty are considered master netting arrangements.  Transactions with counterparties that have master netting arrangements are offset and reported net on the Condensed Consolidated Balance Sheets.  Transactions that do not allow for offsetting of positive and negative positions are reported gross on the Condensed 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.  These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, trade receivables and trade payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit).  These types of transactions are excluded from the offsetting tables presented below.
 

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following tables provide information about the fair value of our risk management activities reported on a gross basis and the impacts of offsetting as of March 31, 2020 and December 31, 2019.offsetting.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities and other assets lines of our Condensed Consolidated Balance Sheets.

44
As of March 31, 2020:
(dollars in thousands)		 
Gross
 Recognized
 Derivatives
 (a)
 
Amounts
Offset
 (b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount Reported on Balance Sheets
Current assets $2,778
 $(1,482) $1,296
 $812
 $2,108
Investments and other assets 50
 (50) —
 —
 —
Total assets 2,828
 (1,532) 1,296
 812
 2,108
           
Current liabilities (55,081) 1,482
 (53,599) (1,185) (54,784)
Deferred credits and other (32,627) 50
 (32,577) —
 (32,577)
Total liabilities (87,708) 1,532
 (86,176) (1,185) (87,361)
Total $(84,880) $—
 $(84,880) $(373) $(85,253)

(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)NaN cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)Represents cash collateral and cash margin that is not subject to offsetting. 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 $1,185 and cash margin provided to counterparties of $812.

As of December 31, 2019:
(dollars in thousands)		 
Gross
Recognized
Derivatives
 (a)
 
Amounts
Offset
(b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount
Reported on
Balance Sheets
Current assets $584
 $(474) $110
 $405
 $515
Total assets 584
 (474) 110
 405
 515
           
Current liabilities (38,235) 474
 (37,761) (1,185) (38,946)
Deferred credits and other (33,186) —
 (33,186) —
 (33,186)
Total liabilities (71,421) 474
 (70,947) (1,185) (72,132)
Total $(70,837) $—
 $(70,837) $(780) $(71,617)

(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)NaN cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)Represents cash collateral and cash margin that is not subject to offsetting. 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 $1,185 and cash margin provided to counterparties of $405.


COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
As of March 31, 2021:
 (dollars in thousands)
Gross
 Recognized
 Derivatives
 (a)
Amounts
Offset
 (b)
Net
 Recognized
 Derivatives
Other
 (c)
Amount Reported on Balance Sheet
Current assets$25,703 $(3,092)$22,611 $0 $22,611 
Investments and other assets3,990 (790)3,200 0 3,200 
Total assets29,693 (3,882)25,811 0 25,811 
Current liabilities(4,874)3,092 (1,782)(1,285)(3,067)
Deferred credits and other(7,718)790 (6,928)0 (6,928)
Total liabilities(12,592)3,882 (8,710)(1,285)(9,995)
Total$17,101 $0 $17,101 $(1,285)$15,816 

(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)NaN cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)Represents cash collateral that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions or collateral posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $1,285.
As of December 31, 2020:
 (dollars in thousands)
Gross
Recognized
Derivatives
 (a)
Amounts
Offset
(b)
Net
 Recognized
 Derivatives
Other
 (c)
Amount
Reported on
Balance Sheet
Current assets$5,870 $(2,939)$2,931 $0 $2,931 
Investments and other assets3,150 (1,332)1,818 0 1,818 
Total assets9,020 (4,271)4,749 0 4,749 
Current liabilities(9,211)2,939 (6,272)(1,285)(7,557)
Deferred credits and other(12,394)1,332 (11,062)0 (11,062)
Total liabilities(21,605)4,271 (17,334)(1,285)(18,619)
Total$(12,585)$0 $(12,585)$(1,285)$(13,870)

(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)NaN cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)Represents cash collateral and cash margin that is not subject to offsetting. 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.

45

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 March 31, 20202021, we have one counterparty for which our exposure represents approximately 22%59% of Pinnacle West'sWest’s $26 million of risk management assets. This exposure relates to a master agreement with a counterparty that has a very high credit rating. is rated as investment grade. Our risk management process assesses and monitors the financial exposure of all counterparties.  Despite the fact that the great majority of our trading counterparties'counterparties’ debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these counterpartiescompanies could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies.  We maintain credit policies that we believe minimize overall credit risk to within acceptable limits.  Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition.  To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.  Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.
 
Certain of our derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross-default provisions, and adequate assurance provisions.  Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions.  For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s).
 
The following table provides information about our derivative instruments that have credit-risk-related contingent features at March 31, 2020 (dollars in thousands):
 March 31, 2020
Aggregate fair value of derivative instruments in a net liability position$86,955
Cash collateral posted—
Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a)81,719

(a)This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded fromMarch 31, 2021
Aggregate fair value of derivative instruments in a net liability position$11,520 
Cash collateral posted0 
Additional cash collateral in the derivative details above.event credit-risk-related contingent features were fully triggered (a)6,674 

(a)This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.
 
We 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 $97$86 million if our debt credit ratings were to fall below investment grade.

46

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

8.    Commitments and Contingencies
8.
Commitments and Contingencies
 
Palo Verde Generating Station
 
Spent Nuclear Fuel and Waste Disposal
 
On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a second breach of contract lawsuit against the United States Department of Energy ("DOE"(“DOE”) in the United States Court of Federal Claims ("(“Court of Federal Claims"Claims”).  The lawsuit sought to recover damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste ("(“Standard Contract"Contract”) for failing to accept Palo Verde'sVerde’s spent nuclear fuel and high level waste from January 1, 2007 through June 30, 2011, as it was required to do pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act.  On August 18, 2014, APS and DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment by DOE to the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. In addition, the settlement agreement, as amended, provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2019. The DOE is reviewing a possible 3 year extension of the settlement agreement. APS cannot predict the timing of the DOE's decision on the extension.2022.

APS has submitted 56 claims pursuant to the terms of the August 18, 2014 settlement agreement, for 56 separate time periods during July 1, 2011 through June 30, 2018.2019. The DOE has approved and paid $84.3$99.7 million for these claims (APS’s share is $24.5$29.0 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 (see Note 4). On October 31, 2019,November 2, 2020, APS filed its next7th claim pursuant to the terms of the August 18, 2014 settlement agreement in the amount of $16$12.2 million (APS’s share is $4.7$3.6 million). On February 11, 2020,March 15, 2021, the DOE approved a payment of $15.4$12.1 million (APS's(APS’s share is $4.5$3.5 million) and on April 20, 2020,16, 2021, APS received this payment.

Nuclear Insurance

Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act ("(“Price-Anderson Act"Act”), which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial sources and an industry-wide retrospective payment plan.  In accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident of up to approximately $13.8$13.7 billion per occurrence. Palo Verde maintains the maximum available nuclear liability insurance in the amount of $450 million, which is provided by American Nuclear Insurers ("ANI"(“ANI”).  The remaining balance of approximately $13.3$13.2 billion of liability coverage is provided through a mandatory industry-wide retrospective premium program.  If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be responsible for retrospective premiums.  The maximum retrospective premium per reactor under the program for each nuclear liability incident is approximately $137.6 million, subject to a maximum annual premium of approximately $20.5 million per incident.  Based on APS’s ownership interest in the 3 Palo Verde units, APS’s maximum retrospective premium per incident for all 3 units is approximately $120.1 million, with a maximum annual retrospective premium of approximately $17.9 million.

The Palo Verde participants maintain insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.8 billion.  APS has also secured accidental outage insurance for a sudden and unforeseen accidental outage of any of the 3 units.  The property damage, decontamination, and accidental outage insurance are provided by Nuclear Electric Insurance

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Limited ("NEIL"(“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
47

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
policies totals approximately $25.5$22.4 million for each retrospective premium assessment declared by NEIL’s Board of Directors due to losses.  In addition, NEIL policies contain rating triggers that would result in APS providing approximately $73.4$63.3 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade.  The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions, sublimits and exclusions.

Contractual Obligations

As of March 31, 2021, our fuel and purchased power commitments have increased from the information provided in our 2020 Form 10-K. The increase is primarily due to new purchased power and energy storage commitments of approximately $550 million. The majority of the changes relate to 2026 and thereafter.

Other than the item described above, there have been no material changes, as of March 31, 2021, outside the normal course of business in contractual obligations from the information provided in our 20192020 Form 10-K. See Note 3 for discussion regarding changes in our short-term and long-term debt obligations.

Superfund-Related Matters
 
The Comprehensive Environmental Response Compensation and Liability Act ("Superfund"(“Superfund” or "CERCLA"“CERCLA”) establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air.  Those who released, generated, transported to or disposed of hazardous substances at a contaminated site are among the parties who are potentially responsible ("PRPs"(“PRPs”).  PRPs may be strictly, and often are jointly and severally, liable for clean-up.  On September 3, 2003, EPA advised APS that EPA considers APS to be a PRP in the Motorola 52nd Street Superfund Site, Operable Unit 3 ("OU3"(“OU3”) in Phoenix, Arizona.  APS has facilities that are within this Superfund site.  APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3.  In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study ("(“RI/FS"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 induring the fallsecond quarter of 2020.2021. We estimate that our costs related to this investigation and study will be approximately $3 million.  We anticipate 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.
 
On August 6, 2013, the Roosevelt Irrigation District ("RID"(“RID”) filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants.  The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID.  The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3.  As part of a state governmental investigation into groundwater contamination in this area, on January 25, 2015, the Arizona Department of Environmental Quality ("ADEQ"(“ADEQ”) sent a letter to APS seeking information concerning the degree to which, if any, APS’s current and former ownership of these facilities may have contributed to groundwater contamination in this area.  APS responded to ADEQ on May 4, 2015. On December 16, 2016, 2 RID environmental and engineering contractors filed an ancillary lawsuit for recovery of costs against APS and the other defendants in the RID litigation. That same day, another RID service provider filed an additional ancillary CERCLA lawsuit against certain of the defendants in the main RID litigation, but excluded APS and certain other parties as named defendants. Because the ancillary lawsuits concern past costs allegedly incurred
48

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
by these RID vendors, which were ruled unrecoverable directly by RID in November of 2016, the additional lawsuits do not increase APS'sAPS’s exposure or risk related to these matters.


COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

On April 5, 2018, RID and the defendants in that particular litigation executed a settlement agreement, fully resolving RID'sRID’s CERCLA claims concerning both past and future cost recovery. APS'sAPS’s share of this settlement was immaterial. In addition, the 2 environmental and engineering vendors voluntarily dismissed their lawsuit against APS and the other named defendants without prejudice. An order to this effect was entered on April 17, 2018. With this disposition of the case, the vendors may file their lawsuit again in the future. On August 16, 2019, Maricopa County, one of the three direct defendants in the service provider lawsuit, filed a third-party complaint seeking contribution for its liability, if any, from APS and 28 other third-party defendants. We are unable to predict the outcome of these matters; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows.

Arizona Attorney General Matter

APS received civil investigative demands from the Attorney General seeking information pertaining to the rate plan comparison tool offered to APS customers and other related issues including implementation of rates from the 2017 Settlement Agreement and its Customer Education and Outreach Plan associated with the 2017 Settlement Agreement. APS fully cooperated with the Attorney General’s Office in this matter. On February 22, 2021 APS entered into a consent agreement with the Attorney General as a way to settle the matter. The settlement results in APS paying $24.75 million, $24 million of which is being returned to customers as restitution.
  
Environmental Matters

APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions of both conventional pollutants and greenhouse gases, water quality, wastewater discharges, solid waste, hazardous waste, and coal combustion residuals ("CCRs"(“CCRs”).  These laws and regulations can change from time to time, imposing new obligations on APS resulting in increased capital, operating, and other costs.  Associated capital expenditures or operating costs could be material.  APS intends to seek recovery of any such environmental compliance costs through our rates but cannot predict whether it will obtain such recovery.  The following proposed and final rules involve material compliance costs to APS.
 
Regional Haze Rules. APS has received the final rulemaking imposing new pollution control requirements on Four Corners. EPA required the plant to install pollution control equipment that constitutes best available retrofit technology ("BART"(“BART”) to lessen the impacts of emissions on visibility surrounding the plant. In addition, EPA issued a final rule for Regional Haze compliance at Cholla that does not involve the installation of new pollution controls and that will replace an earlier BART determination for this facility. See below for details of the Cholla BART approval.

Four Corners. Based on EPA’s final standards, APS'sAPS’s 63% share of the cost of required controls for Four Corners Units 4 and 5 was approximately $400 million, which has been incurred.  In addition, APS and El Paso Electric Company ("(“El Paso"Paso”) entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso'sPaso’s 7% interest in Four Corners Units 4 and 5. 4CA purchased the El Paso interest on July 6, 2016. Navajo Transitional Energy Company, LLC ("NTEC"(“NTEC”) purchased the interest from 4CA on July 3, 2018. See "Four“Four Corners -— 4CA Matter"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.

49

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Cholla. APS believed that EPA’s original 2012In early 2017, EPA approved a final rule establishing controls constituting BART for Cholla, which would require installation of SCR controls, was unsupported and that EPA had no basis for disapprovingcontaining a revision to Arizona’s State Implementation Plan ("SIP"(“SIP”) and promulgating a FIPfor Cholla that was inconsistentimplemented BART requirements for this facility, which did not require the installation of any new pollution control capital improvements.In conjunction with the state’s considered BART determinations under the regional haze program.  In September 2014, APS met with EPA to propose a compromise BART strategy, whereby APS would permanently closeclosure of Cholla Unit 2 and cease burningin 2015, APS has committed to ceasing coal atcombustion within Units 1 and 3 by April 2025.PacifiCorp retired Cholla Unit 4 at the mid-2020s.end of 2020. (See "Cholla"“Cholla” in Note 4 for information regarding future plans for the Cholla plant and details related to the resulting regulatory asset.) APS made the proposal with the understanding that additional emission control equipment is unlikely to be required in the future because retiring and/or converting the units as contemplated in the proposal is more cost effective than, and will result in increased visibility improvement over, the BART requirements for oxides of nitrogen ("NOx") imposed through EPA's BART FIP. In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect for Cholla on April 26, 2017.asset).

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 
Coal Combustion Waste. On December 19, 2014, EPA issued its final regulations governing the handling and disposal of CCR, such as fly ash and bottom ash. The rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act ("RCRA"(“RCRA”) and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions. These criteria include standards governing location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and internet posting requirements. The rule generally requires any existing unlined CCR surface impoundment that is contaminating groundwater above a regulated constituent’s groundwater protection standard to stop receiving CCR and either retrofit or close, and further requires the closure of any CCR landfill or surface impoundment that cannot meet the applicable performance criteria for location restrictions or structural integrity. Such closure requirements are deemed "forced closure"“forced closure” or "closure“closure for cause"cause” of unlined surface impoundments and are the subject of recent regulatory and judicial activities described below.
Since these regulations were finalized, EPA has taken steps to substantially modify the federal rules governing CCR disposal. While certain changes have been prompted by utility industry petitions, others have resulted from judicial review, court-approved settlements with environmental groups, and statutory changes to RCRA. The following lists the pending regulatory changes that, if finalized, could have a material impact as to how APS manages CCR at its coal-fired power plants:

•Following the passage of the Water Infrastructure Improvements for the Nation Act in 2016, EPA possesses authority to either authorize states to develop their own permit programs for CCR management or issue federal permits governing CCR disposal both in states without their own permit programs and on tribal lands. Although ADEQ has taken steps to develop a CCR permitting program, 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.

•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 November 4, 2019,July 29, 2020, EPA proposed that alltook final action on new regulations establishing revised deadlines for initiating the closure of unlined CCR surface impoundments, regardlessimpoundments; such disposal units were closed as of their impact (or lack thereof) upon surrounding groundwater, must cease operation and initiate closure by August 31, 2020 (with an optional three-month extension as needed for the completion of alternative disposal capacity).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 regardingand 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 require express EPA authorization for such facilities to continue operating theirallow the continued disposal of CCR disposal units under alternative closure.

within the facility’s existing unlined CCR
50

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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. This application will be subject to public comment and, potentially, judicial review.

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

APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners. APS estimates that its share of incremental costs to comply with the CCR rule for Four Corners is approximately $22$27 million and its share of incremental costs to comply with the CCR rule for Cholla is approximately $15$16 million. The Navajo Plant disposed of CCR only in a dry landfill storage area. To comply with the CCR rule for the Navajo Plant, APS'sAPS’s share of incremental costs was approximately $1 million, which has been incurred. Additionally, the CCR rule requires ongoing, phased groundwater monitoring.

As of October 2018, APS has completed the statistical analyses for its CCR disposal units that triggered assessment monitoring. APS determined that several of its CCR disposal units at Cholla and Four Corners will need to undergo corrective action. In addition, under the current regulations, all such disposal units must ceasehave ceased operating and initiateinitiated closure by October 31, 2020. APS initiated an assessment of corrective measures on January 14, 2019 and expects such assessment will continue through mid- to late-2020.late-2021. As part of this assessment, APS continues to gather additional groundwater data and perform remedial evaluations as to the CCR disposal units at Cholla and Four Corners undergoing corrective action. In addition, APS will solicit input from the public, host public hearings, and select remedies as part of this process. Based on the work performed to date, APS currently estimates that its share of corrective action and monitoring costs at Four Corners will likely range from $10 million to $15 million, which would be incurred over 30 years. The analysis needed to perform a similar cost estimate for Cholla remains ongoing at this time. 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.

Clean Power Plan/Affordable Clean Energy Regulations. On June 19, 2019, EPA took final action on its proposals to repeal EPA'sEPA’s 2015 Clean Power Plan (“CPP”) and replace those regulations with a new rule, the Affordable Clean Energy (“ACE”) regulations. EPA originally finalized the CPP on August 3, 2015, and thosesuch rules would have had far broader impact on the electric power sector than the ACE regulations. The ACE regulations had been stayed pending judicial review.

Thereview and on January 19, 2021, the U.S. Court of Appeals for the D.C. Circuit vacated the ACE regulations are based upon measures that can be implementedand remanded them back to improve the heat rate of steam-electricEPA to develop new existing power plants, specifically coal-fired EGUs. In contrastplant carbon regulations consistent with the CPP, EPA's ACE regulations would not involve utility-level generation dispatch shifting away from coal-fired generation and toward renewable energy resources and natural gas-fired combined cycle power plants. EPA’s ACE regulations provide states and EPA regions such as the Navajo Nation with three years to develop plans establishing source-specific standards of performance based upon applicationcourt’s ruling. That ruling endorsed an expansive view of the ACE rule’s heat-rate improvement emission guidelines.federal Clean Air Act consistent with EPA’s 2015 CPP. While corresponding New Source Review (“NSR”) reform regulations were proposed as part of EPA’s initial ACE proposal, the finalized ACE regulations did not include such reform measures. EPA announced that it will be taking final action on EPA's NSR reform proposal for EGUsBiden administration has expressed an intent to regulate carbon emissions in this sector more aggressively under the near future.

WeClean Air Act, we cannot at this time predict the outcome of EPA's regulatory actions repealing and replacing the CPP. Various state governments, industry organizations, and environmental and public-health public interest groups have filed lawsuitspending EPA rulemaking proceedings in the D.C. Circuit challenging the legality of EPA’s action, both in repealing the CPP and issuing the ACE regulations. In addition,response to the extent that thecourt’s recent ACE regulations go into effect as finalized, it is not yet clear how the state of Arizona or EPA will implement these regulations as applied todecision.

51

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

APS’s coal-fired EGUs. In light of these uncertainties, APS is still evaluating the impact of the ACE regulations on its coal-fired generation fleet.

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 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.
Federal Agency Environmental Lawsuit Related to Four Corners

On April 20, 2016, several environmental groups filed a lawsuit against the Office of Surface Mining Reclamation and Enforcement ("OSM") and other federal agencies in the District of Arizona in connection with their issuance of the approvals that extended the life of Four Corners and the adjacent mine.  The lawsuit alleges that these federal agencies violated both the Endangered Species Act ("ESA") and the National Environmental Policy Act ("NEPA") in providing the federal approvals necessary to extend operations at the Four Corners Power Plant and the adjacent Navajo Mine past July 6, 2016.  APS filed a motion to intervene in the proceedings, which was granted on August 3, 2016.

On September 15, 2016, NTEC, the company that owns the adjacent mine, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC's tribal sovereign immunity. On September 11, 2017, the Arizona District Court issued an order granting NTEC's motion, dismissing the litigation with prejudice, and terminating the proceedings. On November 9, 2017, the environmental group plaintiffs appealed the district court order dismissing their lawsuit. On July 29, 2019, the Ninth Circuit Court of Appeals affirmed the September 2017 dismissal of the lawsuit, after which the environmental group plaintiffs petitioned the Ninth Circuit for rehearing on September 12, 2019. The Ninth Circuit denied this petition for rehearing on December 11, 2019. On March 24 , 2020, the environmental group plaintiffs filed a Petition for a Writ of Certiorari with the U.S. Supreme Court seeking review of the Ninth Circuit decision. We cannot at this time predict the outcome of this request for further review.

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

On July 16, 2018, several environmental groups filed a petition for review before the EPA Environmental Appeals Board ("EAB"(“EAB”) concerning the NPDES wastewater discharge permit for Four Corners, which was reissued on June 12, 2018.The environmental groups allege that the permit was reissued in contravention of several requirements under the Clean Water Act and did not contain required provisions concerning EPA’s 2015 revised effluent limitation guidelines for steam-electric EGUs, 2014 existing-source regulations governing cooling-water intake structures, and effluent limits for surface seepage and subsurface discharges from coal-ash disposal facilities.To address certain of these issues through a reconsidered permit, EPA took action on December 19, 2018 to withdraw the NPDES permit reissued in June 2018.Withdrawal of the permit moots the EAB appeal, and EPA filed a motion to dismiss on that basis.The EAB thereafter dismissed the environmental group appeal on February 12, 2019.EPA then issued a revised final NPDES permit for Four Corners on September 30, 2019. This permit is now subject to a petition for review before the EAB, basedBased upon a November 1, 2019 filing by several environmental groups.groups, the EAB again took up review of the Four Corners NPDES Permit.

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Oral argument on this appeal 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. We cannot predict the outcome of this reviewthese appeal proceedings and, if such appeal is successful, whether the reviewthat outcome will have a material impact on our 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 had the option to purchase thepurchased this 7% interest and ultimately purchased the interest on July 3, 2018.2018 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 March 31, 2020,2021, the note has a remaining balance of $40$23 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.

In connection with the sale, Pinnacle West guaranteed certain obligations that NTEC will have to the other owners of Four Corners, such as NTEC'sNTEC’s 7% share of capital expenditures and operating and maintenance expenses. Pinnacle West'sWest’s guarantee is secured by a portion of APS'sAPS’s payments to be owed to NTEC under the 2016 Coal Supply Agreement.

The 2016 Coal Supply Agreement contained alternate pricing terms for the 7% interest in the event NTEC did not purchase the interest. Until the time that NTEC purchased the 7% interest, the alternate pricing provisions were applicable to 4CA as the holder of the 7% interest. These terms included a formula under which NTEC must make certain payments to 4CA for reimbursement of operations and maintenance costs and
52

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
a specified rate of return, offset by revenue generated by 4CA’s power sales. The amount under this formula for calendar year 2018 (up to the date that NTEC purchased the 7% interest) was approximately $10 million, which was due to 4CA on December 31, 2019. Such payment was satisfied in January 2020 by NTEC directing to 4CA a prepayment from APS of future coal payment obligations.obligations of which the prepayment has been fully utilized as of June 2020.

Financial Assurances

In the normal course of business, we obtain standby letters of credit and surety bonds from financial institutions and other third parties. These instruments guarantee our own future performance and provide third parties with financial and performance assurance in the event we do not perform. These instruments support commodity contract collateral obligations and other transactions. As of March 31, 2020,2021, standby letters of credit totaled $1.7$5.2 million and will expirewould have expired in 2020.2021, subsequently in April of 2021 an extension was effective that reset the expiration dates to 2022. As of March 31, 2020,2021, surety bonds expiring through 20202022 totaled $14$16 million. The underlying liabilities insured by these instruments are reflected on our balance sheets, where applicable. Therefore, no additional liability is reflected for the letters of credit and surety bonds themselves.

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

Pinnacle West has issued parental guarantees and has provided indemnification under certain surety bonds for APS which were not material at March 31, 2020.2021. In connection with the sale of 4CA's4CA’s 7% interest to NTEC, Pinnacle West is guaranteeing certain obligations that NTEC will have to the other owners of Four

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Corners. (See "Four“Four Corners -— 4CA Matter"Matter” above for information related to this guarantee.)guarantee). Pinnacle West has not needed to perform under this guarantee. A maximum obligation is not explicitly stated in the guarantee and, therefore, the overall maximum amount of the obligation under such guarantee cannot be reasonably estimated; however, we consider the fair value of this guarantee, including expected credit losses, to be immaterial.

In connection with BCE’s acquisition of minority ownership positions in the Clear Creek and Nobles 2 wind farms, Pinnacle West has issued parental guarantees to guarantee the obligations of BCE subsidiaries to make required equity contributions to fund project construction (the “Equity Contribution Guarantees”) and to make production tax credit funding payments to borrowers of the projects (the “PTC Guarantees”). The amounts guaranteed by Pinnacle West reduceare reduced as payments are made under the respective guaranteedguarantee agreements. The Equity Contribution Guarantees remaining as of March 31, 2021 are currently anticipated to be terminated upon completion of construction of the respective projects, which is anticipated to occur prior to December 31, 2020,immaterial in amount (approximately $2 million) and the PTC Guarantees (approximately $40$38 million as of March 31, 2020)2021) are currently expected to be terminated ten years following the commercial operation date of the applicable project.

53
9.
Other Income and Other Expense
The following table provides detail of Pinnacle West's Consolidated other income and other expense for the three months ended March 31, 2020 and 2019 (dollars in thousands):

 Three Months Ended
March 31,
 2020 2019
Other income: 
  
Interest income$3,277
 $2,302
Debt return on Four Corners SCR deferrals (Note 4)3,140

4,844
Debt return on Ocotillo modernization project (Note 4)6,144
 —
Miscellaneous8
 23
Total other income$12,569
 $7,169
Other expense: 
  
Non-operating costs$(2,658) $(2,704)
Investment gains — net60
 (238)
Miscellaneous(2,186) (1,416)
Total other expense$(4,784) $(4,358)


COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

9.    Other Income and Other Expense
The following table provides detail of Pinnacle West’s Consolidated other income and other expense (dollars in thousands):
 Three Months Ended
March 31,
 20212020
Other income:  
Interest income$1,948 $3,277 
Debt return on Four Corners SCR deferrals (Note 4)4,086 3,140 
Debt return on Ocotillo modernization project (Note 4)6,392 6,144 
Miscellaneous3 8 
Total other income$12,429 $12,569 
Other expense:
Non-operating costs(1,937)(2,658)
Investment gains (losses) — net(343)60 
Miscellaneous(1,573)(2,186)
Total other expense$(3,853)$(4,784)

The following table provides detail of APS’s other income and other expense for the three months ended March 31, 2020 and 2019 (dollars in thousands):
 Three Months Ended
March 31,
 2020 2019
Other income: 
  
Interest income$2,341
 $1,550
Debt return on Four Corners SCR deferrals (Note 4)3,140
 4,844
Debt return on Ocotillo modernization project (Note 4)6,144
 —
Miscellaneous8
 22
Total other income$11,633
 $6,416
Other expense: 
  
Non-operating costs$(2,482) $(2,467)
Miscellaneous(2,186) (1,411)
Total other expense$(4,668) $(3,878)


 Three Months Ended
March 31,
 20212020
Other income:  
Interest income$1,481 $2,341 
Debt return on Four Corners SCR deferrals (Note 4)4,086 3,140 
Debt return on Ocotillo modernization project (Note 4)6,392 6,144 
Miscellaneous1 8 
Total other income$11,960 $11,633 
Other expense:  
Non-operating costs(1,778)(2,482)
Miscellaneous(1,572)(2,186)
Total other expense$(3,350)$(4,668)

10.

54

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
10.    Earnings Per Share
 
The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share for the three months ended March 31, 2020 and 2019 (in thousands, except per share amounts):
 Three Months Ended March 31,
 20212020
Net income attributable to common shareholders$35,641 $29,993 
Weighted average common shares outstanding — basic112,829 112,594 
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units264 268 
Weighted average common shares outstanding — diluted113,093 112,862 
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders — basic$0.32 $0.27 
Net income attributable to common shareholders — diluted$0.32 $0.27 
 Three Months Ended March 31,
 2020 2019
Net income attributable to common shareholders$29,993
 $17,918
Weighted average common shares outstanding — basic112,594
 112,337
Net effect of dilutive securities:   
Contingently issuable performance shares and restricted stock units268
 398
Weighted average common shares outstanding — diluted112,862
 112,735
Earnings per weighted-average common share outstanding   
Net income attributable to common shareholders — basic$0.27
 $0.16
Net income attributable to common shareholders — diluted$0.27
 $0.16


11.    Fair Value Measurements
11.
Fair Value Measurements
 
We classify our assets and liabilities that are carried at fair value within the fair value hierarchy.  This hierarchy ranks the quality and reliability of the inputs used to determine fair values, which are then classified and disclosed in one of three categories.  The three levels of the fair value hierarchy are:
 
Level 1 — UnadjustedInputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date.

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

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

55

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

Recurring Fair Value Measurements
 
We apply recurring fair value measurements to cash equivalents, derivative instruments, and investments held in the nuclear decommissioning trusttrusts and other special use funds. On an annual basis, we apply fair value measurements to plan assets held in our retirement and other benefit plans.  See Note 8 in the 20192020 Form 10-K for fair value discussion of plan assets held in our retirement and other benefit plans.
 
Cash Equivalents
 
Cash equivalents represent certain investments in money market funds that are valued using quoted prices in active markets.

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

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

counterparties and the overall diversification of the portfolio.  We maintain credit policies that management believes minimize overall credit risk.
 
Certain non-exchange traded commodity contracts are valued based on unobservable inputs due to the long-term nature of contracts, characteristics of the product, or the unique location of the transactions.  Our long-dated energy transactions consist of observable valuations for the near-term portion and unobservable valuations for the long-term portions of the transaction.  We rely primarily on broker quotes to value these instruments.  When our valuations utilize broker quotes, we perform various control procedures to ensure the quote has been developed consistent with fair value accounting guidance.  These controls include assessing the quote for reasonableness by comparison against other broker quotes, reviewing historical price relationships, and assessing market activity.  When broker quotes are not available, the primary valuation technique used to calculate the fair value is the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at more illiquid delivery points.
 
When the unobservable portion is significant to the overall valuation of the transaction, the entire transaction is classified as Level 3. 
 
56

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Investments Held in Nuclear Decommissioning TrustTrusts and Other Special Use Funds

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

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

Fixed Income Securities

Fixed income securities issued by the U.S. Treasury are valued using quoted active market prices and are typically classified as Level 1.  Fixed income securities issued by corporations, municipalities, and other agencies, including mortgage-backed instruments, are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield curves and spreads relative to such yield curves.  These fixed income instruments are classified as Level 2.  Whenever possible, multiple market quotes are obtained which enables a cross-check validation.  A primary price source is identified based on asset type, class, or issue of securities.

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


COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Equity Securities

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

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


57

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Fair Value Tables
 
The following table presents the fair value at March 31, 2021 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
 Level 1Level 2Level 3Other Total
Assets      
Risk management activities — derivative instruments:
Commodity contracts$0 $14,353 $15,340 $(3,882)(a)$25,811 
Nuclear decommissioning trust:
Equity securities22,160 0 0 (15,538)(b)6,622 
U.S. commingled equity funds0 0 0 648,199 (c)648,199 
U.S. Treasury debt175,707 0 0 —  175,707 
Corporate debt0 143,876 0 —  143,876 
Mortgage-backed securities0 110,073 0 —  110,073 
Municipal bonds0 64,479 0 —  64,479 
Other fixed income0 10,743 0 —  10,743 
Subtotal nuclear decommissioning trust197,867 329,171 0 632,661 1,159,699 
Other special use funds:
Equity securities19,211 0 0 1,401 (b)20,612 
U.S. Treasury debt323,589 0 0 — 323,589 
Municipal bonds0 13,305 0 — 13,305 
Subtotal other special use funds342,800 13,305 0 1,401 357,506 
Total assets$540,667 $356,829 $15,340 $630,180 $1,543,016 
Liabilities      
Risk management activities — derivative instruments:      
Commodity contracts$0 $(11,668)$(924)$2,597 (a)$(9,995)

(a)Represents counterparty netting, margin, and collateral. See Note 7.
(b)Represents net pending securities sales and purchases.
(c)Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.


58

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table presents the fair value at December 31, 2020 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
 
 Level 1Level 2Level 3Other Total
Assets      
Risk management activities — derivative instruments:
Commodity contracts$0 $9,016 $4 $(4,271)(a)$4,749 
Nuclear decommissioning trust:      
Equity securities29,796 0 0 (17,828)(b)11,968 
U.S. commingled equity funds0 0 0 610,055 (c)610,055 
U.S. Treasury debt164,514 0 0 — 164,514 
Corporate debt0 149,509 0 —  149,509 
Mortgage-backed securities0 99,623 0 —  99,623 
Municipal bonds0 89,705 0 —  89,705 
Other fixed income0 13,061 0 —  13,061 
Subtotal nuclear decommissioning trust194,310 351,898 0 592,227 1,138,435 
Other special use funds:
Equity securities37,337 0 0 504 (b)37,841 
U.S. Treasury debt203,220 0 0 — 203,220 
Municipal bonds0 13,448 0 — 13,448 
Subtotal other special use funds240,557 13,448 0 504 254,509 
Total assets$434,867 $374,362 $4 $588,460 $1,397,693 
Liabilities      
Risk management activities — derivative instruments:      
Commodity contracts$0 $(20,498)$(1,107)$2,986 (a)$(18,619)
 Level 1 Level 2 Level 3 Other   Total
Assets 
  
  
  
    
Cash equivalents$26,130
 $—
 $—
 $—
   $26,130
Risk management activities — derivative instruments:           
Commodity contracts—
 2,325
 502
 (719) (a) 2,108
Nuclear decommissioning trust:           
Equity securities11,452
 —
 —
 2,090
 (b) 13,542
U.S. commingled equity funds—
 —
 —
 416,463
 (c) 416,463
U.S. Treasury debt152,951
 —
 —
 —
   152,951
Corporate debt—
 112,667
 —
 —
   112,667
Mortgage-backed securities—
 115,790
 —
 —
   115,790
Municipal bonds—
 98,605
 —
 —
   98,605
Other fixed income—
 10,408
 —
 —
   10,408
Subtotal nuclear decommissioning trust164,403
 337,470
 —
 418,553
   920,426
            
Other special use funds:           
Equity securities6,752
 —
 —
 1,331
 (b) 8,083
U.S. Treasury debt238,637
 —
 —
 —
 
 238,637
Municipal bonds—
 6,003
 —
 —
   6,003
Subtotal other special use funds245,389
 6,003
 —
 1,331
   252,723
            
Total assets$435,922
 $345,798
 $502
 $419,165
   $1,201,387
Liabilities 
  
  
  
    
Risk management activities — derivative instruments: 
  
  
  
    
Commodity contracts$—
 $(79,583) $(8,124) $346
 (a) $(87,361)


(a)Represents counterparty netting, margin, and collateral. See Note 7.
(a)Represents counterparty netting, margin, and collateral. See Note 7.
(b)Represents net pending securities sales and purchases.
(c)
(b)Represents net pending securities sales and purchases.
(c)Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.



COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table presents the fair value at December 31, 2019 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):hierarchy.
 Level 1 Level 2 Level 3 Other   Total
Assets 
  
  
  
    
Risk management activities — derivative instruments:           
Commodity contracts$—
 $551
 $33
 $(69) (a) $515
Nuclear decommissioning trust: 
  
  
  
    
Equity securities10,872
 —
 —
 2,401
 (b) 13,273
U.S. commingled equity funds—
 —
 —
 518,844
 (c) 518,844
U.S. Treasury debt160,607
 —
 —
 —
   160,607
Corporate debt—
 115,869
 —
 —
   115,869
Mortgage-backed securities—
 118,795
 —
 —
   118,795
Municipal bonds—
 73,040
 —
 —
   73,040
Other fixed income—
 10,347
 —
 —
   10,347
Subtotal nuclear decommissioning trust171,479
 318,051
 —
 521,245
   1,010,775
            
Other special use funds:           
Equity securities7,142
 —
 —
 474
 (b) 7,616
U.S. Treasury debt232,848
 —
 —
 —
   232,848
Municipal bonds—
 4,631
 —
 ���
   4,631
Subtotal other special use funds239,990
 4,631
 —
 474
   245,095
            
Total assets$411,469
 $323,233
 $33
 $521,650
   $1,256,385
Liabilities 
  
  
  
    
Risk management activities — derivative instruments: 
  
  
  
    
Commodity contracts$—
 $(67,992) $(3,429) $(711) (a) $(72,132)

(a)Represents counterparty netting, margin, and collateral. See Note 7.
(b)Represents net pending securities sales and purchases.
(c)Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.

Fair Value Measurements Classified as Level 3
 
The significant unobservable inputs used in the fair value measurement of our energy derivative contracts include broker quotes that cannot be validated as an observable input primarily due to the long-term nature of the quote or other characteristics of the product.  Significant changes in these inputs in isolation would result in significantly higher or lower fair value measurements.  Changes in our derivative contract fair values, including changes relating to unobservable inputs, typically will not impact net income due to regulatory accounting treatment (see Note 4).
 
Because our forward commodity contracts classified as Level 3 are currently in a net purchase position, we would expect price increases of the underlying commodity to result in increases in the net fair value of the

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

related contracts.  Conversely, if the price of the underlying commodity decreases, the net fair value of the related contracts would likely decrease.
 
59

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Other unobservable valuation inputs include credit and liquidity reserves which do not have a material impact on our valuations; however, significant changes in these inputs could also result in higher or lower fair value measurements.
 
Financial Instruments Not Carried at Fair Value
 
The carrying value of our short-term borrowings approximate fair value and are classified within Level 2 of the fair value hierarchy. See Note 3 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 $40$22.7 million as of March 31, 20202021 and $44$27.1 million as of December 31, 2019,2020, as presented on the Condensed 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 8 for more information on 4CA matters.

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

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

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

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

Active Union Employee Medical Account -— APS has investments restricted for paying active union employee medical costs. These investments may be used to pay active union employee medical costs incurred in the current and future periods. In 2020 and 2019, APS was reimbursed $14 million and $15 million, respectively, for prior year active union employee medical claims from the active union employee medical account. The account is invested primarily in fixed income securities. In accordance with the ratemaking treatment, APS has deferred the unrealized gains and losses (including credit losses) in other regulatory liabilities. Activities relating to active union employee medical account investments are included within the other special use funds in the table below. 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 5).
60

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

APS

The following tables present the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS's Nuclear Decommissioning TrustsAPS’s nuclear decommissioning trusts and other special use fund assets at March 31, 2020 and December 31, 2019 (dollars in thousands):  
March 31, 2020March 31, 2021
Fair Value 
Total
Unrealized
Gains
 
Total
Unrealized
Losses
 Fair ValueTotal
Unrealized
Gains		Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning Trusts Other Special Use Funds Total Investment Type:Nuclear Decommissioning TrustsOther Special Use FundsTotal
Equity securities$427,915
 $6,752
 $434,667
 $234,695
 $(1,201)Equity securities$670,359 $19,211 $689,570 $457,442 $0 
Available for sale-fixed income securities490,421
 244,640
 735,061
(a)41,455
 (3,527)Available for sale-fixed income securities504,878 336,894 841,772 (a)27,338 (3,203)
Other2,090
 1,331
 3,421
(b)—
 —
Other(15,538)1,401 (14,137)(b)0 0 
Total$920,426
 $252,723
 $1,173,149
 $276,150
 $(4,728)Total$1,159,699 $357,506 $1,517,205 $484,780 $(3,203)

(a)As of March 31, 2020, the amortized cost basis of these available-for-sale investments is $697 million.
(b)Represents net pending securities sales and purchases.
(a)As of March 31, 2021, the amortized cost basis of these available-for-sale investments is $818 million.
(b)Represents net pending securities sales and purchases.
December 31, 2020
 Fair ValueTotal
Unrealized
Gains		Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning TrustsOther Special Use FundsTotal
Equity securities$639,851 $37,337 $677,188 $421,666 $0 
Available for sale-fixed income securities516,412 216,668 733,080 (a)46,581 (398)
Other(17,828)504 (17,324)(b)0 0 
Total$1,138,435 $254,509 $1,392,944 $468,247 $(398)

(a)As of December 31, 2020, the amortized cost basis of these available-for-sale investments is $687 million.
(b)Represents net pending securities sales and purchases.
61
 December 31, 2019
 Fair Value 
Total
Unrealized
Gains
 
Total
Unrealized
Losses
Investment Type:Nuclear Decommissioning Trusts Other Special Use Funds Total  
Equity securities$529,716
 $7,142
 $536,858
 $337,681
 $—
Available for sale-fixed income securities478,658
 237,479
 716,137
(a)25,795
 (669)
Other2,401
 474
 2,875
(b)—
 —
Total$1,010,775
 $245,095
 $1,255,870
 $363,476
 $(669)

(a)As of December 31, 2019, the amortized cost basis of these available-for-sale investments is $691 million.
(b)Represents net pending securities sales and purchases.


COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table sets forth APS'sAPS’s realized gains and losses relating to the sale and maturity of available-for-sale debt securities and equity securities, and the proceeds from the sale and maturity of these investment securities for the three months ended March 31, 2020 and 2019 (dollars in thousands):
 Three Months Ended March 31,
 Nuclear Decommissioning TrustsOther Special Use FundsTotal
2021
Realized gains$2,968 $0 $2,968 
Realized losses(4,148)0 (4,148)
Proceeds from the sale of securities (a)234,728 145,250 379,978 
2020
Realized gains$3,313 $0 $3,313 
Realized losses(2,227)0 (2,227)
Proceeds from the sale of securities (a)178,196 16,891 195,087 
 Three Months Ended March 31,
 Nuclear Decommissioning Trusts Other Special Use Funds Total
2020     
Realized gains$3,313
 $—
 $3,313
Realized losses(2,227) —
 (2,227)
Proceeds from the sale of securities (a)178,196
 16,891
 195,087
2019     
Realized gains$1,103
 $—
 $1,103
Realized losses(1,405) —
 (1,405)
Proceeds from the sale of securities (a)122,593
 56,455
 179,048

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

(a)Proceeds are reinvested in the Nuclear Decommissioning Trusts and other special use funds, excluding amounts reimbursed to the Company for active union employee medical claims from the active union employee medical account.
Fixed Income Securities Contractual Maturities

The fair value of APS'sAPS’s fixed income securities, summarized by contractual maturities, at March 31, 2020,2021, is as follows (dollars in thousands):
 Nuclear Decommissioning TrustCoal Reclamation Escrow AccountActive Union Employee Medical AccountTotal
Less than one year$25,048 $26,259 $40,469 $91,776 
1 year – 5 years147,347 34,936 160,324 342,607 
5 years – 10 years137,479 2,708 63,477 203,664 
Greater than 10 years195,004 8,721 0 203,725 
Total$504,878 $72,624 $264,270 $841,772 
 Nuclear Decommissioning Trust Coal Mine Reclamation Escrow Account Active Union Employee Medical Account Total
Less than one year$11,911
 $37,498
 $40,872
 $90,281
1 year – 5 years137,509
 18,487
 143,565
 299,561
5 years – 10 years112,834
 —
 —
 112,834
Greater than 10 years228,167
 4,218
 —
 232,385
Total$490,421
 $60,203
 $184,437
 $735,061


62
13.    New Accounting Standards

ASU 2016-13, Financial Instruments: Measurement of Credit Losses

In June 2016, a new accounting standard was issued that amends the measurement of credit losses on certain financial instruments. The new standard requires entities to use a current expected credit loss model to measure impairment of certain investments in debt securities, trade accounts receivables, and other financial instruments. Since the issuance of the new standard, various guidance has been issued that amends the new standard, including clarifications of certain aspects of the standard and targeted transition relief, among other changes. The new standard and related amendments were effective for us on January 1, 2020, and must be adopted using a modified retrospective approach for certain aspects of the standard, and a prospective approach for other aspects of the standard. We adopted the standard on January 1, 2020 using primarily the modified retrospective approach. While the adoption of this guidance changed our process and methodology for

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

determining credit losses and resulted in additional disclosures, these changes did not have a material impact on our financial statements. See Note 2 for related disclosures.
14.13.     Changes in Accumulated Other Comprehensive Loss

The following table shows the changes in Pinnacle West'sWest’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component (dollars in thousands):
 Pension and Other Postretirement Benefits Derivative Instruments Total
Three Months Ended March 31
Balance December 31, 2020$(60,725)$(2,071)$(62,796)
OCI (loss) before reclassifications0 262 262 
Amounts reclassified from accumulated other comprehensive loss1,022  (a)0 1,022 
Balance March 31, 2021$(59,703)$(1,809)$(61,512)
Balance December 31, 2019$(56,522)$(574)$(57,096)
OCI (loss) before reclassifications0 292 292 
Amounts reclassified from accumulated other comprehensive loss1,205  (a)20  (b)1,225 
Balance March 31, 2020$(55,317)$(262)$(55,579)

(a)    These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 5.
(b)    These amounts primarily represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 7.

63

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table shows the changes in APS’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three months ended March 31, 20202021 and 20192020 (dollars in thousands):
 Pension and Other Postretirement Benefits Derivative Instruments Total
Three Months Ended March 31
Balance December 31, 2020$(40,918)$0 $(40,918)
Amounts reclassified from accumulated other comprehensive loss927  (a)0 927 
Balance March 31, 2021$(39,991)$0 $(39,991)
Balance December 31, 2019$(34,948)$(574)$(35,522)
OCI (loss) before reclassifications0 292 292 
Amounts reclassified from accumulated other comprehensive loss1,013  (a)20  (b)1,033 
Balance March 31, 2020$(33,935)$(262)$(34,197)

(a) These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 5.
(b) These amounts primarily represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 7.

64
  Pension and Other Postretirement Benefits    Derivative Instruments    Total
Balance December 31, 2019$(56,522)   $(574)   $(57,096)
OCI (loss) before reclassifications—
   292
   292
Amounts reclassified from accumulated other comprehensive loss1,205
  (a) 20
 (b) 1,225
Balance March 31, 2020$(55,317)   $(262)   $(55,579)


   
   
Balance December 31, 2018$(45,997)   $(1,711)   $(47,708)
Amounts reclassified from accumulated other comprehensive loss879
  (a) 328
 (b) 1,207
Balance March 31, 2019$(45,118)   $(1,383)   $(46,501)

(a)These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 5.
(b)These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 7.


COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table shows the changes in APS's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three months ended March 31, 2020 and 2019 (dollars in thousands): 
  Pension and Other Postretirement Benefits    Derivative Instruments    Total
Balance December 31, 2019$(34,948)   $(574)   $(35,522)
OCI (loss) before reclassifications—
   292
   292
Amounts reclassified from accumulated other comprehensive loss1,013
  (a) 20
  (b) 1,033
Balance March 31, 2020$(33,935)   $(262)   $(34,197)


   
   
Balance December 31, 2018$(25,396)   $(1,711)   $(27,107)
Amounts reclassified from accumulated other comprehensive loss752
  (a) 328
  (b) 1,080
Balance March 31, 2019$(24,644)   $(1,383)   $(26,027)

(a)These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost.  See Note 5.
(b)These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 7.

15.14.     Income Taxes
Income Taxes
 
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'sCompany’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. For the quarter ended March 31, 2020, theThe Company recorded $14 million of income tax benefit related to the amortization of these non-depreciation related net excess deferred tax liabilities.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. For the quarter ended March 31, 2020, theThe Company recorded $6 million and $6 million of income tax benefit related to amortization of these depreciation related liabilities.net excess deferred tax liabilities as of March 31, 2021 and March 31, 2020, respectively. See Note 4 for more details.
In August 2018, U.S. Treasury proposed regulations that clarified bonus depreciation transition rules under the Tax Act for regulated public utility property placed in service after September 27, 2017 and before January 1, 2018.  However, these proposed regulations were ambiguous with respect to regulated public utility property placed in service on or after January 1, 2018. In September 2019, U.S. Treasury issued final

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

regulations, which replaced the August 2018 proposed regulations. These final regulations did not materially impact any tax position taken by the Company for property placed in service after September 27, 2017 and before January 1, 2018.

Along with the September 2019 final regulations, U.S. Treasury also issued new proposed regulations which clarify bonus depreciation transition rules under the Tax Act for property placed in service by regulated public utilities after December 31, 2017. The proposed regulations provide that certain regulated public utility property which was under construction prior to September 28, 2017 and placed in service between January 1, 2018 and December 31, 2020 would continue to be eligible for bonus depreciation under the rules and bonus depreciation phase-downs in effect prior to enactment of the Tax Act. 

Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax.  As a result, there is no0 income tax expense associated with the VIEs recorded on the Pinnacle West Consolidated and APS Consolidated Statements of Income. See Note 6 for additional details related to the Palo Verde sale leaseback VIEs.

As of the balance sheet date, the tax year ended December 31, 20162017 and all subsequent tax years remain subject to examination by the IRS.  With a few exceptions, the Company is no longer subject to state income tax examinations by tax authorities for years before 2015.2016.

16.
Asset Retirement Obligations

In the first quarter of 2020, APS recognized an asset retirement obligation ("ARO") for its share of corrective action and water monitoring costs at Four Corners and the Navajo Plant (see additional details in Notes 4 and 8), which resulted in a decrease to the ARO of $11 million for Four Corners and an increase to the ARO of $5 million for the Navajo Plant.

The following schedule shows the change in our asset retirement obligations for the three months ended March 31, 2020 (dollars in thousands): 

 2020
Asset retirement obligations at January 1, 2020$657,218
Changes attributable to: 
Accretion expense10,219
Settlements(2,295)
Estimated cash flow revisions(5,821)
Asset retirement obligations at March 31, 2020$659,321


In accordance with regulatory accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal.  See detail of regulatory liabilities in Note 4.

65

ITEM 2.         MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
INTRODUCTION
 
The following discussion should be read in conjunction with Pinnacle West’s Condensed Consolidated Financial Statements and APS’s Condensed Consolidated Financial Statements and the related Combined Notes that appear in Item 1 of this report.  For information on factors that may cause our actual future results to differ from those we currently seek or anticipate, see "Forward-Looking Statements"“Forward-Looking Statements” at the front of this report and "Risk Factors"“Risk Factors” in Part 1, Item 1A of the 20192020 Form 10-K, and Part II, Item 1A of this report.
 
OVERVIEW

Business Overview

Pinnacle West is an investor-owned electric utility holding company based in Phoenix, Arizona with consolidated assets of about $19$20 billion. For over 130 years, Pinnacle West and our affiliates have provided energy and energy-related products to people and businesses throughout Arizona.

Pinnacle West derives essentially all of our revenues and earnings from our principal subsidiary, APS. APS is Arizona’s largest and longest-serving electric company that generates safe, affordable and reliable electricity for approximately 1.3 million retail customers in 11 of Arizona’s 15 counties. APS is also the operator and co-owner of Palo Verde -— a primary source of electricity for the southwest United States and the largest nuclear power plant in the United States.

COVID-19 Pandemic

The current COVID-19 pandemic has ledcontinues to economic disruption and volatility in financial markets worldwide.be an evolving situation. The Company is operating under long-standing crisispandemic and business continuity plans that exist to address situations including pandemics like COVID-19. We are focused on ensuring the health and safety of our employees, contractors and the general public by helping limit the spread of this virus and ensuring continued, safe and reliable electric service for APS customers.

We have identified business-critical positions in both our operations and support organizations, and identifiedwith backup personnel who are intendedready to provide supportassist if neededan issue were to arise. Additionally, efforts to ensure the health and safety of our employees have resulted in bifurcated control rooms, thus reducing the number of employees in mission-critical locations. We also established COVID-19 safety protocols, social distancing practices including limiting one employee per vehicle and offering virtual options whenever possible. The Company also took rapid action to implement an all Company COVID-19 hotline, a focused COVID-19 team, and procured on-site COVID-19 testing at key facilities early in the pandemic. Through this testing, case management and contact tracing, the Company has been able to significantly limit COVID-19 transmission in the workplace. As a result of these efforts, we have been able to maintain operations with a reduced workforce. the continuity of the essential services that we provide to our customers, while also managing the spread of the virus and promoting the health, physical and mental well-being and safety of our employees, customers and communities.

Essential planned work and capital investments are continuing during the pandemic but certain non-essential planned workwith priority to support fire mitigation and summer preparedness. APS has been postponedcontinuous discussions with suppliers on manpower and supply issues pertaining to later in 2020. The Company conducted a contract review to confirm adequacy of needed summer resourcesCOVID-19 and has measures in place to continue to monitor resource needs and supply chain adequacy. At this time, the CompanyAPS does not believe it has any material supply chain risks due to COVID-19 that would impact its ability to serve customers’ needs. Although it is still too early
66

The Company’s operations and maintenance expenses, exclusive of bad debt expense, increased by approximately $3 million for the period ended March 31, 2021 due to predict, ifcosts for personal protective equipment and other health and safety-related costs related to COVID-19.  We expect the impactsCompany’s operation and maintenance expenses will continue to be impacted for 2021 by the need for additional personal protective equipment and other health and safety-related costs related to COVID-19.

While the total expected impact of COVID-19 weon future sales is currently unknown, APS has experienced higher electric residential sales and lower electric commercial and industrial sales since the outset of the pandemic. APS expects sales trends to normalize somewhat in 2021 as business activity continues to recover and more people return to work. Based on past experience, a 1% variation in our annual kWh sales projections under normal business conditions can result in increases or decreases in annual net income of approximately $20 million.

The Coronavirus Aid, Relief, and Economic Security (CARES) Act allows employers to defer payments of the employer share of Social Security payroll taxes that would have otherwise been owed from March 13th27, 2020 through April 30th continue throughDecember 31, 2020. We deferred the endcash payment of the second quarter, we would anticipateemployer’s portion of Social Security payroll taxes for the period July 1, 2020 through December 31, 2020 that was approximately $18 million. We will pay half of this cash deferral by December 31, 2021 and the remainder by December 31, 2022.

On June 30, 2020, FERC issued an order granting a net 7% decrease in weather normalized retail electricity sales comparedwaiver request related to the second quarter 2019.

Asexisting AFUDC rate calculation beginning March 1, 2020 through February 28, 2021.  On February 23, 2021, this waiver was extended until September 30, 2021. The order provides a resultsimplified 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 COVID-19 pandemic,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 mid-Marchboth 2020 and 2021, but does not impact prior years.  Furthermore, the commercial paper markets failed to function normally and we were unable to utilize commercial paper aschange in the composite rate calculation does not impact our primary method of acquiring short-term capital, which resulted in us drawing on our revolving credit facilities during the first quarter of 2020.  In mid-April 2020, we were again able to utilize the commercial paper market and we have used the commercial paper proceeds to pay down the revolving credit facilities by approximately $220 million through May 1, 2020.  We doaccounting treatment for these costs. The change did not believe this will have a material impact on our financial position, results of operations or cash flows.statements. See Note 1.



Due to the COVID-19 pandemic, APS has voluntarily suspended disconnections of customers for nonpayment and waived late payment fees beginning March 13, 2020 until December 31, 2020. In addition,The suspension of disconnection of customers for nonpayment ended on January 1, 2021 and customers were automatically placed on eight-month payment arrangements if they had past due balances at the end of the disconnection period of $75 or greater. APS has waived allwill continue to waive late payment fees during this current moratorium.until October 15, 2021. APS has experienced and is continuing to experience an increase in bad debt expense associated with the COVID-19 pandemic, the Summer Disconnection Moratorium and the related write-offs of customer delinquent accounts. APS currently estimates that the Summer Disconnection Moratorium, (see Note 4 for discussion of the Summer Disconnection Moratorium), the suspension of disconnections during the COVID-19 pandemic and the increased bad debt expense associated with both eventsthis will result in a negative impact to its 20202021 operating results of approximately $20 million to $30 million pre-tax above the impact of disconnections on its operating results for years that did not have the Summer Disconnection Moratorium or COVID-19 pandemic. APS is anticipating an increase in bad debt expense associated with the COVID-19 pandemic, but it still believes that costs associated with the Summer Disconnection Moratorium and the COVID-19 disconnection suspensions and related bad debt expense with both events will fall within this estimated $20 to $30 million range. These estimated impact amounts for 2021 depend on certain current assumptions, including, but not limited to, customer behaviors, population and employment growth, and the impacts of COVID-19 on the economy not extending into 2021. APS also established a customer support fund of $1.5 million to assist customers with a one-time credit of up to $100 on their bill with a priority given to customers on limited-income service plans and also is providing $1.25 million to assist local non-profits and community organizations working to mitigate the virus' impact. Additionally, due to COVID-19, APS delayed the reset of the EIS adjustor and suspended the discontinuation of TEAM Phase II to the first billing cycle in May 2020 rather than April 2020 (seeeconomy. See Note 4 for discussion of EIS and TEAM Phase II).4.

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 hashad been collected through the DSM Adjustor Clause,Charge, but not allocated for current DSM
67

programs, directly to customers through a bill credit in June 2020 (see Note 4 for discussion4). APS has refunded approximately $43 million to customers. The additional $7 million over the approved amount of $36 million was the result of the kWh credit being based on historic consumption, which was different than actual consumption in the refund period. This difference was recorded to the DSM Adjustor Clause). Also, onbalancing account and will be addressed in subsequent DSM filings. Additionally, due to COVID-19, APS delayed the reset of the EIS adjustor and suspended the discontinuation of TEAM Phase II to the first billing cycle in May 5,2020 rather than April 2020. In February 2021, APS delayed the annual reset of the PSA. Rather than the increase being effective February 2021, the PSA reset will be implemented with 50% of the increase effective April 2021 and the remaining 50% increase effective November 2021. See Note 4.

In 2020, APS voluntarilyspent 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 a series of voluntary commitments of funds that are not recoverable through rates throughout 2020 of approximately $8.8 million. An additional $3.6 million in bill credits for limited income customers was ordered by the ACC in December 2020 of which 50%, up to contribute $5.3a maximum of $2.5 million, of non-ratepayerwas committed to be funds to provide assistance to residential and businessthat are not recoverable through rates with the remaining being deferred for potential future recovery in rates. Included in the COVID Customer Support Fund were programs that assisted customers that have been impacted byhad a delinquency of two or more months with 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.

More detailed discussion of the recent impacts and future uncertainties related to the COVID‑19 pandemic can be found throughout this Management'sManagement’s Discussion and Analysis of Financial Condition and Results of Operations and the Combined Notes to Pinnacle West'sWest’s and APS'sAPS’s financial statements that appear in Item 1of this report and "Risk Factors" in Part II, Item 1A1 of this report.

Strategic Overview

Our strategy is to deliver shareholder value by creating a sustainable energy future for Arizona by serving our customers with a clean, affordable, reliable and customer-focused plan.

affordable energy.

Clean Energy Commitment

We are committed to doing our part to make the future clean and carbon-free. Our vision for APS and Arizona presents an opportunity to engage with customers, communities, employees, policymakers, shareholders and others to achieve a shared, sustainable vision for Arizona. This goal is based on sound science and supports continued growth and economic development while maintaining reliability and affordable prices for APS'sAPS’s customers.

APS'sAPS’s new clean energy goals consist of three parts:
•A 2050 goal to provide 100% clean, carbon-free electricity;
•A 2030 target of achieving a resource mix that is 65% clean energy, with 45% of the generation portfolio coming from renewable energy; and
•A commitment to end APS’s use of coal-fired generation by 2031.


68


APS'sAPS’s ability to successfully execute its clean energy commitment is dependent upon a number of important external factors, some of which include a supportive regulatory environment, sales and customer growth, development of clean energy technologies and continued access to capital markets.

2050 Goal: 100% Clean, Carbon-Free Electricity. Achieving a fully clean, carbon-free energy mix by 2050 is our aspiration. The 2050 goal will involve new thinking and depends on improved and new technologies.

2030 Goal: 65% Clean Energy. APS has an energy mix that is already 50% clean with existing plans to add more renewables and energy storage before 2025. By building on those plans, APS intends to attain an energy mix that is 65% clean by 2030, with 45% of APS'sAPS’s generation portfolio coming from renewable energy. “Clean” is measured as percent of energy mix which includes all carbon-free resources like nuclear and demand-side management, and “renewable” is expressed as a percent of retail sales. This target will serve as a checkpoint for our resource planning, investment strategy, and customer affordability efforts as APS moves toward 100% clean, carbon-free energy mix by 2050.

2031 Goal: End APS'sAPS’s Use of Coal-Fired Generation. TheOur commitment to end APS'sAPS’s use of coal-fired generation by 2031 will require APS to cease use of coal-generation at Four Corners. APS has permanently retired more than 1,000 MW of coal-fired electric generating capacity. These closures and other measures taken by APS have resulted in a total reduction of carbon emissions of 26%33% since 2005. In addition, APS has committed to end the use of coal at its remaining Cholla units by 2025.

APS understands that the transition away from coal-fired power plants toward a clean energy future will pose unique economic challenges for the communities around these plants. We worked collaboratively with stakeholders and leaders of the Navajo Nation to consider the impacts of ceasing operation of APS coal-fired power plants on the communities surrounding those facilities to propose a comprehensive Coal Community Transition (“CCT”) plan. The proposed framework provides substantial financial and economic development support to build new economic opportunities and addresses a transition strategy for plant employees. We are committed to continuing our long-running partnership with the Navajo Nation in other areas as well, including expanding electrification and developing tribal renewable projects. Our proposed CCT plan supports the Navajo Nation, where the Four Corners Power Plant is located, the communities surrounding the Cholla Power Plant and the Hopi Tribe, which is impacted by closure of the Navajo Plant. The CCT plan is currently pending ACC approval. See Note 4 for a discussion of the CCT plan.

In March 2021, APS announced that it had agreed on the terms of an agreement among the owners of Four Corners to operate Four Corners seasonally beginning in Fall 2023, subject to the necessary approvals. Under seasonal operation, APS is planning that one of Four Corners’ two remaining units will operate only throughout the summer season of June through October when customers’ energy needs are the highest across the region. APS believes that operating Four Corners seasonally will bring environmental benefits and ensure continued service reliability for its customers, especially during Arizona’s hot summer months, as APS transitions to ceasing to use coal-fired generation by 2031. By moving to seasonal operations, Four Corners will become a more flexible resource that supports increasing amounts of clean energy, helping to compensate for the intermittent output of renewable resources. This change also helps ensure reliability of a critical energy source while reducing operations and maintenance costs. APS estimates that the shift to seasonal operations will reduce annual carbon emissions at Four Corners by an estimated 20-25%, as compared to current conditions.

Renewables. APS intends to strengthen its already diverse energy mix by increasing its investments in carbon-free resources. Its near-term actions include competitive solicitations to procure clean energy resources such as solar, wind, energy storage, demand response and DSM resources, including energy efficiency resources that enable renewable additions andall of which lead to a cleaner grid.grid.

69

APS has a diverse portfolio of existing and planned renewable resources, including solar, wind, geothermal, biomass and biogas. APS'sAPS’s clean energy strategy includes executing purchased power contracts for new facilities, ongoing development of distributed energy resources and procurement of new facilities to be owned by APS. The following table summarizes the resources in APS'sAPS’s renewable energy portfolio that are in operation and under development as of March 31, 2020.2021. Agreements for the development and completion of future resources are subject to various conditions, including successful siting, permitting and interconnection of the projects to the electric grid.

 Net Capacity in Operation
(MW)		Net Capacity Planned / Under
Development (MW)
Total APS Owned: Solar246 — 
Purchased Power Agreements:  
Solar310 160 
Wind (a)289 110 
Geothermal10 — 
Biomass14 — 
Biogas3 — 
Total Purchased Power Agreements626 270 
Total Distributed Energy: Solar (b) 1,122 45 (c)
Total Renewable Portfolio1,994 315 

 
Net Capacity in Operation
(MW)
 
Net Capacity Planned / Under
Development (MW)
 
Total APS Owned: Solar243
 —
 
Purchased Power Agreements: 
  
 
Solar310
 —
 
Solar + Energy Storage—
 50
 
Wind289
 —
 
Geothermal10
 —
 
Biomass14
 —
 
Biogas3
 —
 
Total Purchased Power Agreements626
 50
 
Total Distributed Energy: Solar (a) 995
 37
(b)
Total Renewable Portfolio1,864
 87
 

(a)Includes 90 MW wind power purchase agreement that is currently in operation that will be decommissioned in 2021 and rebuilt in the same year, together with an additional 110 MW, for a total of 200 MW, as a result of a power purchase agreement executed in September 2020.
(b)        Includes rooftop solar facilities owned by third parties. Distributed generation is produced in Direct Current and is converted to ACAlternating Current for reporting purposes.
(b)
(c)    Applications received by APS that are not yet installed and online.

APS has developed and owns solar resources through the ACC-approved AZ Sun Program.  APS invested approximately $675 million in the AZ Sun Program.
In September 2019, APS issued two Requests for Proposal ("RFP") in September 2019. The firsta RFP seeks competitive proposals for up to 150 MW of APS-owned solar resources to be in service by 2021. This solar generation will be designed with the flexibility to add energy storage as a future option. A second RFP requeststhat requested up to 250 MW of wind resources to be in service as soon as possible, but no later than 2022.As a result of this RFP, APS executed a 200 MW power purchase agreement for a wind resource that is expected to be in service in the fourth quarter of 2021. Also in September 2019, APS issued a RFP that sought competitive proposals for up to 150 MW of APS-owned solar resources, designed with the flexibility to add energy storage as a future option. Negotiations pursuant to this RFP were terminated in March 2021. In December 2020, APS issued two additional RFPs: one to acquire both renewable energy and additional peaking capacity resources, and the other to install more battery energy storage at two existing APS solar plants. In April 2021, the RFPs that were issued in December 2020 were expanded to seek development of a solar generating resource to be sited on APS land and owned by APS.

Palo Verde. Palo Verde, the nation’s largest carbon-free, clean energy resource, will continue to be a foundational part of APS'sAPS’s resource portfolio. The plant currently supplies nearly 70% of our clean energy and provides the foundation for the reliable and affordable service for APS customers. Palo Verde is not just the cornerstone of our current clean energy mix, it also is a significant provider of clean energy to the southwest United States. The plant’splant is a critical asset to the Southwest, generating more than 32 million megawatt-hours annually – enough power for more than 4 million people. Its continued operation is important to a carbon-free and clean energy future for Arizona and the region, as a reliable, continuous, affordable resource and as a large contributor to the local economy.

70

Affordable

Affordable

We believe it is APS'sAPS’s responsibility to deliver electric services to customers in the most cost-effective manner. Since January 2018 through April 2021, the average residential bill decreased by 7.8%6.2%, or $11.68.$9.28 due to net reductions in cost recovery adjustor mechanisms.

Building upon existing cost management efforts, APS launched a customer affordability initiative in 2019. The initiative was implemented company-wide to thoughtfully and deliberately assess our business processes and organizational approaches to completing high-value work and internal efficiencies. Through the initiative and existing cost management practices, in 2020, APS identifiedmet its goal of $20 million in possible cost savings for 2020.savings. In 2021, APS continues to drive this initiative to identify opportunities to streamline its business processes and deliver sustainable cost savings.

Participation in the EIM continues to be an effective tool for creating savings for ourAPS’s customers from the real-time, voluntary market. OverAPS continues to expect that its participation in EIM will lower its fuel and purchased-power costs, improve visibility and situational awareness for system operations in the past three years, the EIM has delivered approximately $140 million in gross benefitsWestern Interconnection power grid, and improve integration of APS’s renewable resources. APS continues to APS customers. APSevaluate opportunities that benefit our customers and is in discussions with the EIM operator, CAISO,California Independent System Operator, Inc. (“CAISO”), and other EIM participants about the feasibility of creating a voluntary day-ahead market to achieve more cost savings and use the region’s renewable resources more efficiently.



Reliable

Reliable

While our energy mix evolves, the obligation to deliver reliable service to our customers remains. Excluding voluntary outagesNotwithstanding the challenges presented by the COVID-19 pandemic as well as the hottest summer on record, APS continued to provide reliable service to its customers in 2020, setting a new all-time high peak energy demand of 7,660 MW, exceeding the prior peak set in 2017 by nearly 300 MW and proactive fire mitigation efforts, APS finished 2019 with its best score for frequency of customer power outages.achieved strong reliability results.

Planned investments will support operating and maintaining the grid, updating technology, accommodating customer growth and enabling more renewable energy resources. Our advanced distribution management system allows operators to locate outages, control line devices remotely and helps them coordinate more closely with field crews to safely maintain an increasingly dynamic grid. The system also integrates a new meter data management system that increases grid visibility and gives customers access to more of their energy usage data.

Wildfire safety remains a critical focus for APS and other utilities. We increased investment in fire mitigation efforts to clear defensible space around our infrastructure, build partnerships with government entities and first responders and educate customers and communities. These programs contribute to customer reliability, responsible forest management and safe communities.

The new units at our modernized Ocotillo power plantPower Plant provide cleaner-running and more efficient units. They support reliability by responding quickly to the variability of solar generation and delivering energy in the late afternoon and early evening, when solar production declines as the sun sets and customer demand peaks.

In February 2021, Texas experienced extreme cold weather. Wellheads and gas production infrastructure froze, sharply reducing gas supply at the same time as demand for gas was at a record high due to the frigid weather. As a result, natural gas prices and market electricity prices spiked to historic highs, with gas prices exceeding 100 times the prices seen the preceding weeks. In addition, APS experienced
71

interruptions or curtailments with six of our natural gas suppliers due to the weather event in Texas. These interruptions and curtailments did not impact APS’s ability to deliver power to its customers. APS does not believe that the Texas event materially impacted its financial position, results of operations, or cash flows.
Customer-Focused
In April 2021, the CAISO sought FERC authorization for certain tariff changes intended to try to address risks associated with high heat weather events. Although APS is generally supportive of some of these changes, others would change the load, export, and wheeling priorities in a way that would unfairly benefit California entities at the expense of non-California entities. As such, APS intends to formally oppose these changes in front of FERC. APS cannot predict the outcome of these proceedings. Nor can PNW or APS predict whether energy shortages, market priorities, and/or price spikes due to extreme weather conditions will have an impact on its financial position, results of operations or cash flows.

APS’s key elements to delivering reliable power include resource planning, sufficient reserve margins, customer partnerships to manage peak demand, fire mitigation, and operational preparedness. Seasonal readiness procedures at APS also include walkdowns to ensure good material conditions and critical control system surveys. APS also plans for the unexpected by conducting emergency operations drills and coordinating on fire and emergency management with federal, state, and local agencies.
Customer-Focused

Customers are at the core of what APS does every day and APS is committed to providing options that make it easier forits focus remains on its customers and the communities it serves. It is APS’s goal to do business with them. In 2019, APS launched its redesigned aps.com website and mobile app, giving customers upgraded access to their energy usage data and billing information. APS's Customer Care team is using speech analytics to enrich advisors’ interactions with customers over the telephone, and customers can also communicate with APS throughachieve an online chat.industry-leading best-in-class customer experience.

APS expanded financial help for its most vulnerable customers in 2019, allocating $2.75 million in crisis bill assistance and increasing the individual benefit for qualifying customers from $400 to $800 per year. The APS Solar Communities program has allowed more than 600 limited- and moderate-income customers to support clean energy and save money by hosting APS-owned solar systems on their residences in exchange for a monthly bill credit.

APS continues to develop and deploy innovative programs that connect customers with advanced technologies to help them manage their bills and encourage energy use during midday, when solar power is most abundant. Three energy storage programs incorporating smart thermostats, connected water heaters and batteries are helping customers shift energy use to times when they can take advantage of low-cost, abundant energy and reduce peak demand on APS's system.

In 2020, APS is convening an advisory paneladopted a number of changes to improve customer experience. It transitioned to a 24/7 care center operation to better serve its customers around the clock. APS improved its call center performance, answering nearly 75% of its more than 1.5 million telephone calls in 30 seconds or less. APS has also made many improvements to gainits digital experience through its aps.com site, and its overall digital experience continues to improve for its customers. APS has also implemented a deeper understanding ofproject to redesign and improve its customer bills, completing the customer experience through their individual perspectives. A groupresearch portion of this project in the first quarter of 2021.

APS also convened a customer advisory board and stakeholder committee in 2020 to serve as a vehicle for gathering valuable qualitative insights, directly from customers and stakeholders, that intends to keep APS apprised of customer service advisors,needs, wants, and perspectives. Additionally, the customer advisory board is leveraged to identify and diagnose potential customer pain points and to help shape and co-create customer solutions. The customer advisory board completed two engagements in conjunction with local human services agencies, will provide in-personthe first quarter of 2021, addressing rate plan simplification and bill redesign.

APS is also providing assistance to residential and business customers that have been impacted by the COVID-19 pandemic. See “COVID-19 Pandemic” above for more information about customer support in communities APS serves.during COVID-19.


72


EmergingDeveloping Clean Energy Technologies

Energy Storage

APS deploys a number of advanced technologies on its system, including energy storage. Storage can provide capacity, improve power quality, be utilized for system regulation, integrate renewable generation, and in certain circumstances, be used to defer certain traditional infrastructure investments. Energy storage can also aid in integrating higher levels of renewables by storing excess energy when system demand is low and renewable production is high and then releasing the stored energy during peak demand hours later in the day and after sunset. APS is utilizing grid-scale energy storage projects to benefit customers, to increase renewable utilization, and to further our understanding of how storage works with other advanced technologies and the grid. We are preparing for additional energy storage in the future.

In early 2018, APS entered into a 15-year power purchase agreement for a 65 MW solar facility that charges a 50 MW solar-fueled battery. Service under thisthe agreement iswas scheduled to begin in 2021.2021; however, APS terminated the agreement, effective February 16, 2021, because project development could not be sufficiently advanced to support the expected in-service date. In 2018, APS issued a request for proposalan RFP for approximately 106 MW of energy storage to be located at up to five of its AZ Sun sites. Based upon ourits evaluation of the RFP responses, APS decided to expand the initial phase of battery deployment to 141 MW by adding a sixth AZ Sun site. In February 2019, we contracted for the 141 MW and originally anticipated suchThese battery storage facilities couldare expected to be in service by mid-2020.June 2022. Additionally, in February 2019, APS signed two 20-year PPAs for energy storage totaling 150 MW. In April 2019, a battery module in APS’s McMicken battery energy storage facility experienced an equipment failure, which prompted an internal investigation to determine the cause. The results of theAPS has now completed its investigation will inform the timing of our utilization and implementation of batteries on our system. Due to the April 2019 event, APS is working with the counterparty for the AZ Sun sites to determine appropriate timing and path forward for such facilities. Additionally, in February 2019, APS signed two 20-year power purchase agreements for energy storage totaling 150 MW. Service under these power purchase agreements is also dependent on the results of the McMicken battery incident and is working with all counterparties to ensure that the learnings from the investigation, and requiresthe corresponding safety requirements, are incorporated into all battery storage projects going forward, including the projects associated with the two above-referenced PPAs. These PPAs were also subject to ACC approval from the ACCin order to allow for cost recovery of these agreements through the PSA. APS received the requested ACC approval on January 12, 2021, and service under both agreements is expected to begin in 2022.

We currently plan to install at least 850 MW of energy storage by 2025, including the 150 MW of energy storage projects under power purchase agreementsPPAs and AZ Sun retrofits described above. The additional 700 MW of APS-ownedremaining energy storage is expected to be made up of resources solicited through current and future RFPs. Currently, APS has two RFPs in the retrofits associated with ourmarket that seek energy storage resources: (i) a battery storage RFP for projects to be located at the remaining two AZ Sun sites as described above, along with currentthat were not included in the 2018 RFP referenced in the preceding paragraph; and future RFPs for(ii) an ‘all source’ RFP that solicits both standalone energy storage and solarrenewable energy plus energy storage projects. Given the April 2019 event, we continueresources. Such resources are expected to evaluate the appropriate timingbe in service during 2023 and path forward to support the overall capacity goals for our system and associated energy storage requirements. Currently, APS is pursuing an RFP for battery-ready solar resources up to 150 MW with results expected in the first half of 2020.2024.

Electric Vehicles

APS plans to makeis making electric vehicle charging more accessible for its customers and helphelping Arizona businesses, schools and governments electrify their fleets. In 2019,2020, APS implementedexpanded its Take Charge AZ Pilot Program.Program and installed 84 dual-plug Level 2 charging stations at business customer locations with more stations expected to be added through 2021. The program provides charging equipment, installation, and maintenance to business customers, government agencies, and multifamily housing communities. Rates are designedIn addition to encouragethe Level 2 charging overnightstations, APS will begin construction of direct current fast charging stations that will be owned and during daytime off-peak hours when solar energyoperated by APS at five locations in Arizona. This project is abundant.

projected to be completed by the end of 2021 with each location including 2-150 kilowatt and 2-350 kilowatt DC fast charging stations. These stations will be accessible through the Electrify America charging network.

The ACC ordered the state’s public service corporations, including APS, to develop a long-term, comprehensive Statewide Transportation Electrification Plan (“TE Plan”) for Arizona. The TE Plan is intended
73

to provide a roadmap for Transportation Electrification in Arizona, focused on realizing the associated air quality and economic development benefits for all residents in the state along with understanding the impact of electric vehicle charging on the grid. APS is actively participating in this process, which was submitted in April 2021 to the ACC for review and approval.

Hydrogen Production

Palo Verde, in partnership with Idaho National Laboratory (“INL”) and two other utilities,Energy Harbor Corporation and Xcel Energy Incorporated, has been chosen by the DOE'sDOE’s Office of Nuclear Energy to participate in a hydrogen production project with the goal to improve the long-term economic competitiveness of the nuclear power industry. The multi-phase project is planned for 2020 through 2022, will look2023. In the first phase, INL performed a technical and economic assessment of using electricity generated at how hydrogen producedPalo Verde to produce hydrogen.

Based on the experience from Palo Verde energy may be used as energy storageVerde’s utility partners’ demonstration projects and from the Palo Verde-specific technical and economic assessment performed by INL, PNW Hydrogen LLC, a subsidiary of Pinnacle West, recently submitted a request for use in reverse-operable electrolysis or peaking gas turbines during timesfunding to the DOE’s Office of the day when photovoltaic solar energy


sources are unavailable and energy reserves in the southwest United States are low. It could also be usedNuclear Energy to support moving forward with a rapidly increasing hydrogen transportation fuel market.

Experience from the pilot project will offer insights into methods for flexible transitions between electricity and hydrogen generation missions in solar-dominated electricity markets, and demonstrate how hydrogen may be used as energy storage to provide electricity during operating periods when solar is not available.

production pilot.

Carbon Capture


Carbon capture technologies can isolate CO2CO2 and either sequester it permanently in geologic formations or convert it for use in products. Currently, almost all existing fossil fuel generators do not control carbon emissions the way they control emissions of other air pollutants such as sulfur dioxide or oxides of nitrogen. Carbon capture technologies are still in the demonstration phase and while they show promise, they are still being tested in real-world conditions. These technologies could offer the potential to keep in operation existing generators that otherwise would need to be retired. APS will continue to monitor this emerging technology.


Regulatory Overview

On October 31, 2019, APS filed an application with the ACC forseeking an annual increase in annual retail base rates of $69 million. This amount includes recovery of the deferral and rate base effects of the Four Corners SCR project that is currently the subject of a separate proceeding (see “SCR Cost Recovery” in Note 4). 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. The proposed total annual revenue increase in APS'sAPS’s application is $184 million. The average annual customer bill impact of APS’s request is an increase of 5.6% (the average annual bill impact for a typical APS residential customer is 5.4%).

The principal provisions of APS'sAPS’s application are:were:

•a test year comprised of twelve months ended June 30, 2019, adjusted as described below;
•an original cost rate base of $8.87 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   Capital Structure Cost of Capital 
Long-term debtLong-term debt 45.3%4.10%Long-term debt 45.3 %4.1%
Common stock equityCommon stock equity 54.7%10.15%Common stock equity 54.7 %10.15 %
Weighted-average cost of capitalWeighted-average cost of capital   7.41%Weighted-average cost of capital   7.41 %
 
74

•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 Base Fuel Rate of $0.030168 per kWh;
•authorization to defer until APS'sAPS’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;
•a number of proposed rate and program changes for residential customers, including:
▪a super off-peak period during the winter months for APS’s time-of-use with demand rates;
▪additional $1.25 million in funding for APS's limited-income crisis bill program; and
▪a flat bill/subscription rate pilot program;
▪a super off-peak period during the winter months for APS’s time-of-use with demand rates;
▪additional $1.25 million in funding for APS’s limited-income crisis bill program; and
▪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;


•recovery of the deferral and rate base effects of the construction and operating costs of the Ocotillo modernization project (see Note 4 discussion of the 2017 Settlement Agreement); and
•continued recovery of the remaining investment and other costs related to the retirement and closure of the Navajo Plant (see Note 4 for details related to the resulting regulatory asset).

On October 2, 2020, the ACC Staff, the Residential Utility Consumer Office (“RUCO”) and other intervenors filed their initial written testimony with the ACC in this rate case.The ACC Staff recommends, among other things, a (i) $89.7 million revenue increase, (ii) average annual customer bill increase of 2.7%, (iii) 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)recovery of the deferral and rate base effects of the construction and operating costs of the Four Corners SCR project and (vi) recovery of the rate base effects of the construction and ongoing consideration of the deferral of the Ocotillo modernization project.RUCO recommends, among other things, a (i) $20.8 million revenue decrease, (ii) average annual customer bill decrease of 0.63%, (iii) return on equity of 8.74%, (iv) a 0% return on the increment of fair value rate base, (v)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) 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 requestedfiled 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 (“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) the 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: (i) $100 million that will be paid over 10 years to the Navajo Nation for a sustainable transition to a post-coal economy, which would be funded by customers, (ii) $1.25 million that will be paid over five years to the Navajo Nation to fund an economic development organization, which would be funds not recoverable through rates, (iii) $10 million to facilitate electrification projects within the Navajo Nation, which would be funded equally by funds not recoverable through rates and by customers, (iv) $2.5 million per year in transmission revenue sharing to be paid to the Navajo Nation beginning after the closure of the Four Corners Power Plant through 2038, which would be funds not recoverable through rates, (v) $12 million that will be paid over five years to the Navajo County Communities surrounding Cholla Power Plant, which would primarily be funded by customers, and (vi) $3.7
75

million that will be paid over five years to the Hopi Tribe related to APS’s ownership interests in the Navajo Generating Station, which would primarily be funded by customers.

On December 4, 2020, the ACC Staff and intervenors filed surrebuttal testimony. The ACC Staff reduced its recommended rate increase become effective December 1, 2020.  to $59.8 million, or an average annual customer bill increase of 1.82%. In RUCO’s surrebuttal, the recommended revenue decrease changed to $50.1 million, or an average annual customer bill decrease of 1.52%.

The hearing forconcluded on March 3, 2021 and the post-hearing briefing schedule concluded on April 30, 2021. In May 2021, the ACC will be discussing whether to re-open the evidentiary record in APS’s pending rate case to take additional evidence on topics raised by certain ACC Commissioners, including adjustor cost recovery mechanisms. APS believes that the rate case record is sufficient, and adjustors provide substantial benefits to customers by supporting critical programs and reflecting changes in utility costs that can be promptly passed along to customers. Pending this decision, the next steps in this rate case was delayed by 75 days, atare that the requestAdministrative Law Judge will issue a Recommended Order and Opinion and then the ACC will review and consider the matter, which is anticipated to be in the third quarter of 2021. Unfavorable ACC Staff and is currently scheduled to begin September 30, 2020.intervenor positions and recommendations, including modifications or elimination of APS's adjustor cost recovery mechanisms could have a material impact on APS’s financial statements if ultimately adopted by the ACC. APS cannot predict the outcome or timing of its request.this proceeding.

See Note 4 for information regarding additional regulatory matters.

Arizona Attorney General Matter

APS received civil investigative demands from the Office of the Arizona Attorney General, Civil Litigation Division, Consumer Protection & Advocacy Section (“Attorney General”) seeking information pertaining to the rate plan comparison tool offered to APS customers and other related issues including implementation of rates from the 2017 Settlement Agreement and its Customer Education and Outreach Plan associated with the 2017 Settlement Agreement. APS fully cooperated with the Attorney General’s Office in this matter. On February 22, 2021 APS entered into a consent agreement with the Attorney General as a way to settle the matter. The settlement results in APS paying $24.75 million, $24 million of which is being returned to customers as restitution. While this matter has been resolved with the Attorney General, APS cannot predict whether additional inquiries or actions may be taken by the ACC.

Financial Strength and Flexibility 

Pinnacle West and APS currently have ample borrowing capacity under their respective credit facilities, and may readily access these facilities ensuring adequate liquidity for each company.  Capital expenditures will be funded with internally generated cash and external financings, which may include issuances of long-term debt and Pinnacle West common stock.
 
76

Other Subsidiaries

Bright Canyon Energy. On July 31, 2014, Pinnacle West announced its creation of a wholly-owned subsidiary, BCE.  BCE'sBCE’s strategy is to develop, own, operate and acquire energy infrastructure in a manner that leverages the Company’s core expertise in the electric energy industry.  In 2014, BCE formed a 50/50 joint venture with BHE U.S. Transmission LLC, a subsidiary of Berkshire Hathaway Energy Company.  The joint venture, named TransCanyon, is pursuing independent electric transmission opportunities within the eleven11 states that comprise the Western Electricity Coordinating Council, excluding opportunities related to transmission service that would otherwise be provided under the tariffs of the retail service territories of the venture partners’ utility affiliates.

On December 20, 2019, BCE acquired minority ownership positions in two wind farms under development by Tenaska Energy, Inc. and Tenaska Energy Holdings, LLC, the 242 MW Clear Creek wind farm in Missouri (“Clear Creek”) and the 250 MW Nobles 2 wind farm in Minnesota.Minnesota (“Nobles 2”). Clear Creek achieved commercial operation in May 2020 and Nobles 2 achieved commercial operation in December 2020. Both wind farms are expected to achieve commercial operation in 2020 and deliver power under long-term power purchase agreements. BCE indirectly owns 9.9% of the Clear Creek project and 5.1% of the Nobles 2 project.2.

El Dorado. El Dorado is a wholly-owned subsidiary of Pinnacle West. El Dorado owns debt investments and minority interests in several energy-related investments and Arizona community-based ventures.  El Dorado committed to a $25 million investment in the Energy Impact Partners fund, which is an organization that focuses on fostering innovation and supporting the transformation of the utility industry. The investment will be made by El Dorado as investments are selected by the Energy Impact Partners fund.

Key Financial Drivers
 
In addition to the continuing impact of the matters described above, many factors influence our financial results and our future financial outlook, including those listed below.  We closely monitor these factors to plan for the Company’s current needs, and to adjust our expectations, financial budgets and forecasts appropriately.
 
Electric Operating Revenues.  For the years 20172018 through 2019,2020, retail electric revenues comprised approximately 95% of our total operating revenues.  Our electric operating revenues are affected by customer growth or decline, variations in weather from period to period, customer mix, average usage per customer and


the impacts of energy efficiency programs, distributed energy additions, electricity rates and tariffs, the recovery of PSA deferrals and the operation of other recovery mechanisms.  These revenue transactions are affected by the availability of excess generation or other energy resources and wholesale market conditions, including competition, demand and prices.
 
Actual and Projected Customer and Sales Growth. Retail customers in APS’s service territory increased 2.2%2.1% for the three-month period ended March 31, 20202021 compared with the prior-year period. For the three years 20172018 through 2019,2020, APS’s customer growth averaged 1.8%2.0% per year. We currently project annual customer growth to be 1.5 -1.5% to 2.5% for 20202021 and for 20202021 through 20222023 based on our assessment of steady population growth in Arizona.

Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, increased 0.8%0.5% for the three-month period ended March 31, 20202021 compared with the prior-year period. Steady economic growth andWhile steady customer growth werewas offset by energy savings driven by customer conservation, energy efficiency, and distributed renewable generation initiatives.  initiatives, the main drivers of positive sales for this period were continued strong residential sales due to work-from-home policies, a gradual improvement in sales to commercial and industrial
77

customers, and the ramp-up of new data center customers. Though the total expected impact of COVID-19 on future sales is currently unknown, APS has experienced higher electric residential sales and lower electric commercial and industrial sales since the outset of the pandemic. APS expects sales trends to normalize somewhat into 2021 as business activity continues to recover and more people return to work.

For the three years 20172018 through 2019,2020, annual retail electricity sales were about flat, adjusted to exclude the effects of weather variations. We currently project that annual retail electricity sales in kWh will increase in the range of 1.0 - 2.0%0.5% to 1.5% for 20202021 and increase on average in the range of 1.0 -1.0% to 2.0% during 20202021 through 2022,2023, including the effects of customer conservation, energy efficiency and distributed renewable generation initiatives, but excluding the effects of weather variations and excluding the impacts of several new, large data centersmanufacturing facilities opening operations in Metro Phoenix.

Although it is still too early to predict, if the impacts of COVID-19 we experienced from March 13th through April 30th continue through the end of the second quarter, we would anticipate a net 7% decrease in weather normalized retail electricity sales compared to the second quarter 2019.  The impact of the new, large data centers could raisemanufacturing facilities is likely to increase the range of expected annual sales growth rate over the 2020 toas early as 2022, period, but demand from these customers remains uncertain at this time.point. This projected sales growth range also includes our estimated contributions of several large data centers, but not all, and we will continue to estimate contributions and evaluate sales guidance as these customers develop more usage history. These estimates could be further impacted by slower than expected growth of the Arizona economy, slower than expected ramp-up of the new data centers, or acceleration of the expected effects of customer conservation, energy efficiency, distributed renewable generation initiatives, or customer and sales growth not resuming and the economy not normalizing in 2020 after COVID-19.initiatives.

Actual sales growth, excluding weather-related variations, may differ from our projections as a result of numerous factors, such as economic conditions, customer growth, usage patterns and energy conservation, ramp-up of data centers, impacts of energy efficiency programs and growth in distributed generation, and responses to retail price changes.  Based on past experience, a 1% variation in our annual kWh sales projections attributable to such economic factors under normal business conditions can result in increases or decreases in annual net income of approximately $20 million.

Weather.  In forecasting the retail sales growth numbers provided above, we assume normal weather patterns based on historical data.  Historically, extreme weather variations have resulted in annual variations in net income in excess of $25 million.  However, our experience indicates that the more typical variations from normal weather can result in increases or decreases in annual net income of up to $15 million.
 
Fuel and Purchased Power Costs. Fuel and purchased power costs included on our Condensed Consolidated Statements of Income are impacted by our electricity sales volumes, existing contracts for purchased power and generation fuel, our power plant performance, transmission availability or constraints, prevailing market prices, new generating plants being placed in service in our market areas, changes in our generation resource allocation, our hedging program for managing such costs and PSA deferrals and the related amortization.

Operations and Maintenance Expenses. Operations and maintenance expenses are impacted by customer and sales growth, power plant operations, maintenance of utility plant (including generation,


transmission, and distribution facilities), inflation, unplanned outages, planned outages (typically scheduled in the spring and fall), renewable energy and demand side management related expenses (which are offset by the same amount of operating revenues) and other factors.

Depreciation and Amortization Expenses.  Depreciation and amortization expenses are impacted by net additions to utility plant and other property (such as new generation, transmission, and distribution facilities), and changes in depreciation and amortization rates.  See "Liquidity“Liquidity and Capital Resources"Resources” below for information regarding the planned additions to our facilities.

78

Property Taxes.  Taxes other than income taxes consist primarily of property taxes, which are affected by the value of property in-service and under construction, assessment ratios, and tax rates.  The average property tax rate in Arizona for APS, which owns essentially all of our property, was 10.9%10.8% of the assessed value for 2020, 10.9% for 2019 and 11.0% for 2018 and 11.2% for 2017.2018. We expect property taxes to increase as we add new generating units and continue with improvements and expansions to our existing generating units and transmission and distribution facilities. 

Pension and other postretirement non-service credits - net.  Pension and other postretirement non-service credits can be impacted by changes in our actuarial assumptions. The most relevant actuarial assumptions are the discount rate used to measure our net periodic costs/credit, the expected long-term rate of return on plan assets used to estimate earnings on invested funds over the long-term, the mortality assumptions and the assumed healthcare cost trend rates. We review these assumptions on an annual basis and adjust them as necessary.

Interest Expense.  Interest expense is affected by the amount of debt outstanding and the interest rates on that debt (see Note 3).  The primary factors affecting borrowing levels are expected to be our capital expenditures, long-term debt maturities, equity issuances and internally generated cash flow.  An allowance for borrowed funds used during construction offsets a portion of interest expense while capital projects are under construction.  We stop accruing AFUDC on a project when it is placed in commercial operation.
 
Income Taxes.  Income taxes are affected by the amount of pretax book income, income tax rates, certain deductions and non-taxable items, such as AFUDC.  In addition, income taxes may also be affected by the settlement of issues with taxing authorities. On December 22, 2017, the Tax Act was enacted and was generally effective on January 1, 2018. Changes impacting the Company include a reduction in the corporate tax rate to 21%, revisions to the rules related to tax bonus depreciation, limitations on interest deductibility and an associated exception for certain public utilities, and requirements that certain excess deferred tax amounts of regulated utilities be normalized. (SeeSee Note 1514 for details of the impacts on the Company as of March 31, 2020.)2021. In APS'sAPS’s 2017 rate case decision, the ACC approved a Tax Expense Adjustor Mechanism which will be used to pass through the income tax effects to retail customers of the Tax Act. (See Note 4 for details of the TEAM.)

RESULTS OF OPERATIONS

Pinnacle West’s only reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily sales supplied under traditional cost basedcost-based rate regulation) and related activities and includes electricity generation, transmission and distribution.



Operating Results — Three-month period ended March 31, 20202021 compared with three-month period ended March 31, 2019.2020.

Our consolidated net income attributable to common shareholders for the three months ended March 31, 20202021 was $30$36 million, compared with consolidated net income attributable to common shareholders of $18$30 million for the prior-year period.  The results reflect an increase of approximately $12$6 million for the regulated electricity segment primarily due to higher revenue driven by lower operationsrefunds in the current year related to the Tax Act, the effects of weather and maintenance expense,higher transmission revenue, higher pension and other postretirement non-service credits, andpartially offset by higher income taxes, including lower income tax expense due to amortization of excess deferred taxes as a result of the Tax Act, partially offset by lower revenue due to the refunds provided to customers resulting from the Tax Act and milder weather. COVID-19 did not have a material impact on our results ofhigher operations for the period ended March 31, 2020, but we will continue to monitor its impact on our results of operations.and maintenance expense.  

79

The following table presents net income attributable to common shareholders by business segment compared with the prior-year period:

 Three Months Ended
March 31,		 
 20212020Net Change
 (dollars in millions)
Regulated Electricity Segment:   
Operating revenues less fuel and purchased power expenses$497 $472 $25 
Operations and maintenance(229)(221)(8)
Depreciation and amortization(158)(154)(4)
Taxes other than income taxes(59)(57)(2)
Pension and other postretirement non-service credits - net28 14 14 
All other income and expenses, net15 16 (1)
Interest charges, net of allowance for borrowed funds used during construction(57)(55)(2)
Income taxes4 20 (16)
Less income related to noncontrolling interests (Note 6)(5)(5)— 
Regulated electricity segment income36 30 6 
All other— — — 
Net Income Attributable to Common Shareholders$36 $30 $6 
 Three Months Ended
March 31,		  
 2020 2019 Net Change
 (dollars in millions)
Regulated Electricity Segment: 
  
  
Operating revenues less fuel and purchased power expenses$472
 $509
 $(37)
Operations and maintenance(221) (245) 24
Depreciation and amortization(154) (149) (5)
Taxes other than income taxes(57) (55) (2)
Pension and other postretirement non-service credits - net14
 5
 9
All other income and expenses, net16
 14
 2
Interest charges, net of allowance for borrowed funds used during construction(55) (54) (1)
Income taxes20
 (2) 22
Less income related to noncontrolling interests (Note 6)(5) (5) —
Regulated electricity segment income30
 18
 12
All other—
 —
 —
Net Income Attributable to Common Shareholders$30
 $18
 $12



Operating revenues less fuel and purchased power expenses.  Regulated electricity segment operating revenues less fuel and purchased power expenses were $37$25 million lowerhigher for the three months ended March 31, 20202021 compared with the prior-year period.  The following table summarizes the major components of this change:

 Increase (Decrease)
 Operating
revenues		Fuel and
purchased
power expenses		Net change
(dollars in millions)
Lower refunds in the current year related to the Tax Act (Note 4)$19 $— $19 
Effects of weather5 1 4 
Higher transmission revenues (Note 4)4 — 4 
Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals6 7 (1)
Miscellaneous items, net— 1 (1)
Total$34 $9 $25 
 Increase (Decrease)
 
Operating
revenues
 
Fuel and
purchased
power expenses
 Net change
 (dollars in millions)
Amortization of excess deferred taxes (Note 4)$(23) $—
 $(23)
Effects of weather(17) (5) (12)
Lower renewable energy regulatory surcharges, partially offset by operations and maintenance costs(4) 1
 (5)
Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals(35) (38) 3
Higher retail revenue due to higher customer growth, offset by the impacts of energy efficiency, distributed generation and changes in customer usage patterns2
 2
 —
Miscellaneous items, net(2) (2) —
Total$(79) $(42) $(37)

Operations and maintenance.  Operations and maintenance expenses decreased $24increased $8 million for the three months ended March 31, 20202021 compared with the prior-year period primarily because of:

A decrease•An increase of $10$7 million in fossil generation costs primarily due to lowerhigher planned outages and lowerhigher operating costs duecosts;

80

•An increase of $6 million related to the Navajo plant closure (see Note 4);employee benefits;

•A decrease of $6 million primarily related to costs for renewable energy and similar regulatory programs, which are partially offset in operating revenues and purchased power;

A decrease of $3$4 million in nuclear generation costs; and

•A decrease of $3 million related to employee benefit costs; and

A decrease of $2$1 million for other miscellaneous factors.

Depreciation and amortization. Depreciation and amortization expenses were $5$4 million higher for the three months ended March 31, 20202021 compared to the prior-year period primarily due to increased plant in service of $13$5 million, partially offset by the regulatory deferrals for the Ocotillo modernization project and the Four Corners SCR project of $8$1 million.

Pension and other postretirement non-service credits, net.Pension and other postretirement non-service credits, net were $9$14 million higher for the three months ended March 31, 20202021 compared to the prior-year period primarily due to higheractual market returns exceeding estimated returns in 2019.2020.

Income taxes.  Income taxes were $22$16 million lowerhigher for the three months ended March 31, 20202021 compared with the prior-year period primarily due to lower amortization of excess deferred taxes (see Note 15).and higher pre-tax income, partially offset by a net operating loss carryback benefit that the Company recognized during the first quarter of 2021.





LIQUIDITY AND CAPITAL RESOURCES
 
Overview
 
Pinnacle West’s primary cash needs are for dividends to our shareholders and principal and interest payments on our indebtedness.  The level of our common stock dividends and future dividend growth will be dependent on declaration by our Board of Directors and based on a number of factors, including our financial condition, payout ratio, free cash flow and other factors.
 
Our primary sources of cash are dividends from APS and external debt and equity issuances.  An ACC order requires APS to maintain a common equity ratio of at least 40%.  As defined in the related ACC order, the common equity ratio is defined as total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt.  At March 31, 2020,2021, APS’s common equity ratio, as defined, was 53%51%.  Its total shareholder equity was approximately $5.9$6.3 billion, and total capitalization was approximately $11.1$12.2 billion.  Under this order, APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $4.4$4.9 billion, assuming APS’s total capitalization remains the same.  This restriction does not materially affect Pinnacle West’s ability to meet its ongoing cash needs or ability to pay dividends to shareholders.
 
APS’s capital requirements consist primarily of capital expenditures and maturities of long-term debt.  APS funds its capital requirements with cash from operations and, to the extent necessary, external debt financing and equity infusions from Pinnacle West.

81

Summary of Cash Flows
 
Our consolidated change in cash and cash equivalents for the period ended March 31, 2021 compared to December 31, 2020 was a decrease of $43 million. The change is primarily driven by an increase in cash used for capital expenditures, which is partially offset by cash retained as a result of lower operations and maintenance cost, higher receipts of electric revenues and lower long-term debt repayments. The following tables present net cash provided by (used for) operating, investing and financing activities for the three months ended March 31, 2020 and 2019 (dollars in millions):
 
Pinnacle West Consolidated
 Three Months Ended
March 31,		Net
 20212020Change
Net cash flow provided by operating activities$202 $184 $18 
Net cash flow used for investing activities(348)(341)(7)
Net cash flow provided by financing activities103 210 (107)
Net change in cash and cash equivalents$(43)$53 $(96)
 Three Months Ended
March 31,		 Net
 2020 2019 Change
Net cash flow provided by operating activities$184
 $173
 $11
Net cash flow used for investing activities(341) (254) (87)
Net cash flow provided by financing activities210
 81
 129
Net change in cash and cash equivalents$53
 $—
 $53

Arizona Public Service Company
Three Months Ended
March 31,		 Net Three Months Ended
March 31,		Net
2020 2019 Change 20212020Change
Net cash flow provided by operating activities$194
 $188
 $6
Net cash flow provided by operating activities$203 $194 $9 
Net cash flow used for investing activities(343) (260) (83)Net cash flow used for investing activities(352)(343)(9)
Net cash flow provided by financing activities192
 72
 120
Net cash flow provided by financing activities106 192 (86)
Net change in cash and cash equivalents$43
 $—
 $43
Net change in cash and cash equivalents$(43)$43 $(86)
 


Operating Cash Flows
 
Three-month period ended March 31, 20202021 compared with three-month period ended March 31, 2019.2020. Pinnacle West’s consolidated net cash provided by operating activities was $202 million in 2021, compared to $184 million in 2020, compared to $173 million in 2019, an increase of $11$18 million in net cash provided by operating activities primarily due to $41 million lower pension contributions,payments for operations and maintenance cost, $32 million higher cash receipts from electric revenues, partially offset by $52 million higher fuel and purchased power costs and interest expense, partially offset by lower cash receipts from electric revenues.other changes in working capital.

Retirement plans and other postretirement benefits. Pinnacle West sponsors a qualified defined benefit pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries.  The requirements of the Employee Retirement Income Security Act of 1974 ("ERISA"(“ERISA”) require us to contribute a minimum amount to the qualified plan.  We contribute at least the minimum amount required under ERISA regulations, but no more than the maximum tax-deductible amount.  The minimum required funding takes into consideration the value of plan assets and our pension benefit obligations.  Under ERISA, the qualified pension plan was 117%124% funded as of January 1, 20202021 and 112%117% as of January 1, 2019.2020.  Under GAAP, the qualified pension plan was 104% funded as of January 1, 2021 and 97% funded as of January 1, 2020 and 90% funded as of January 1, 2019.2020. See Note 5 for additional details. The assets in the plan are comprised of fixed-income, equity, real estate, and short-term investments.  Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions.  We have not made voluntary contributions to our pension plan year-to-date in 2020.2021. The minimum required contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions up to $100 million per year during the 2020-2022 period.in 2021 and zero in 2022 and 2023. We
82

do not expect to make any contributions over the next three yearsthis period to our other postretirement benefit plans. We continue to monitor COVID-19 and its impact on our retirement plans and other postretirement benefits but we believe, due to our liability driven investment strategy, which helps to minimize the impact of market volatility on our plan’s funded status, our pension plan’s funded status, as measured for GAAP purposes, is still above 90%95% funded as of April 30, 2020.March 31, 2021.

The Coronavirus Aid, Relief, and Economic Security (CARES) Act allows employers to defer payments of the employer share of Social Security payroll taxes that would have otherwise been owed from March 27, 2020 through December 31, 2020. We deferred the cash payment of the employer’s portion of Social Security payroll taxes for the period July 1, 2020 through December 31, 2020 that was approximately $18 million. We will pay half of this cash deferral by December 31, 2021 and the remainder by December 31, 2022.

Investing Cash Flows
 
Three-month period ended March 31, 20202021 compared with three-month period ended March 31, 2019.2020. Pinnacle West’s consolidated net cash used for investing activities was $348 million in 2021, compared to $341 million in 2020, compared to $254 million in 2019, an increase of $87$7 million primarily related to increased capital expenditures.
 


Capital Expenditures.  The following table summarizes the estimated capital expenditures for the next three years:

Capital Expenditures
(dollars in millions) 
Estimated for the Year Ended
December 31,
 202120222023
APS   
Generation:   
Clean:
Nuclear Generation$114 $116 $125 
Renewables and Energy Storage Systems (“ESS”) (a)200 276 281 
Other Generation (b)203 190 187 
Distribution577 556 549 
Transmission185 181 179 
Other (c)221 181 179 
Total APS$1,500 $1,500 $1,500 
 
Estimated for the Year Ended
December 31,
 2020 2021 2022
APS 
  
  
Generation: 
  
  
Clean:     
Nuclear Generation$129
 $123
 $123
Renewables and Energy Storage Systems ("ESS") (a)121
 490
 671
Environmental45
 53
 44
Other Generation141
 154
 121
Distribution556
 444
 446
Transmission181
 201
 205
Other (b)158
 185
 115
Total APS$1,331
 $1,650
 $1,725


(a)APS Solar Communities program, energy storage, renewable projects, and other clean energy projects
(b)Primarily information systems and facilities projects

(a)APS Solar Communities program, energy storage, renewable projects, and other clean energy projects
(b)Includes generation environmental projects
(c)Primarily information systems and facilities projects

Generation capital expenditures are comprised of various additions and improvements to APS’s clean resources, including nuclear plants, renewables and ESS. Generation capital expenditures also include improvements to existing fossil plants. Examples of the types of projects included in the forecast of generation capital expenditures are additions of renewable and energy storage, and upgrades and capital replacements of various nuclear and fossil power plant equipment, such as turbines, boilers and environmental equipment.  We
83

are monitoring the status of environmental matters, which, depending on their final outcome, could require modification to our planned environmental expenditures.

Distribution and transmission capital expenditures are comprised of infrastructure additions and upgrades, capital replacements, and new customer construction.  Examples of the types of projects included in the forecast include power lines, substations, and line extensions to new residential and commercial developments.

Capital expenditures will be funded with internally generated cash and external financings, which may include issuances of long-term debt and Pinnacle West common stock.

Financing Cash Flows and Liquidity
 
Three-month period ended March 31, 20202021 compared with three-month period ended March 31, 2019.2020. Pinnacle West’s consolidated net cash provided by financing activities was $103 million in 2021, compared to $210 million in 2020, compared to $81 million in 2019, an increasea decrease of $129$107 million in net cash provided.  The increasedecrease in net cash provided by financing activities includes a net increasedecrease in short-term borrowingsborrowing of $403 million, partially offset by $150 million in higher issuances of long-term debt and lower long-term debt repayments of $350$150 million.

APS’s consolidated net cash provided by financing activities was $106 million in 2021, compared to $192 million in 2020, a decrease of $86 million in net cash provided.  The decrease in net cash provided by financing activities includes a net decrease in short-term borrowing of $231 million, partially offset by $497 million in lower issuanceslong-term debt repayments of long-term debt.$150 million.


Significant Financing Activities.  On April 22, 2020,21, 2021, the Pinnacle West Board of Directors declared a dividend of $0.7825$0.83 per share of common stock, payable on June 1, 20202021 to shareholders of record on May 4, 2020.3, 2021.

Available Credit Facilities. Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs, to finance indebtedness, and other general corporate purposes.

On May 5, 2020, Pinnacle West refinanced its 364-day $50 million term loan agreement that would have matured on May 7, 2020 with a new 364-day $31 million term loan agreement that matures onwould have matured May 4, 2021. Borrowings under the agreement bearbore interest at LIBOREurodollar Rate plus 1.40% per annum. At March 31, 2020,2021, Pinnacle West had $33$15 million in outstanding borrowings under the prior agreement.current agreement, all of which was repaid on April 27, 2021.

On December 23, 2020, Pinnacle West entered into a $150 million term loan facility that matures June 2022. The proceeds were received on January 4, 2021 and used for general corporate purposes. We recognized the term loan facility as long-term debt upon settlement on January 4, 2021.

At March 31, 2020,2021, Pinnacle West had a $200 million revolving credit facility that matures in July 2023. 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'sWest’s senior unsecured debt credit ratings. The facility is available to support Pinnacle West'sWest’s $200 million commercial paper program, for bank borrowings or for issuances of letters of credits. At March 31, 2020,2021, Pinnacle West had $100 millionno outstanding borrowings under its credit facility, no letters of credit outstanding and no$0.3 million of outstanding commercial paper borrowings.

On January 15, 2020, APS repaid at maturity the remaining $150 million of the $250 million aggregate principal amount of its 2.2% Senior Notes.
84

At March 31, 2020,2021, APS had two revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in June 2022 and a $500 million facility that matures in July 2023.  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. These facilities are available to support APS’s $500$750 million commercial paper program, for bank borrowings or for issuances of letters of credit.  At March 31, 2020,2021, APS had no commercial paper outstanding and $430 million outstanding borrowings or letters of credit under its revolving credit facilities.

As a resultfacilities, no letters of the COVID-19 pandemic, in mid-March 2020 thecredit outstanding, and $199.5 million of outstanding commercial paper markets failed to function normally and we were unable to utilize commercial paper as our primary method of acquiring short-term capital, which resulted in us drawing on our revolving credit facilities during the first quarter of 2020.  In mid-April 2020, we were again able to utilize the commercial paper market and we have used the commercial paper proceeds to pay down the revolving credit facilities by approximately $220 million through May 1, 2020.  We do not believe this will have a material impact on our financial position, results of operations or cash flows.borrowings.

See "Financial Assurances"“Financial Assurances” in Note 8 for a discussion of separate outstanding letters of credit and surety bonds.
 
Other Financing Matters. See Note 7 for information related to the change in our margin and collateral accounts.



Debt Provisions

Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios.  Pinnacle West and APS comply with these covenants.  For both Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total consolidated capitalization not exceed 65%.  At March 31, 2020,2021, the ratio was approximately 53%54% for Pinnacle West and 48%49% for APS.  Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could "cross-default"“cross-default” other debt.  See further discussion of "cross-default"“cross-default” provisions below.

Neither Pinnacle West’s nor APS’s financing agreements contain "rating triggers"“rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade.  However, our bank credit agreements contain a pricing grid in which the interest rates we pay for borrowings thereunder are determined by our current credit ratings.
 
All of Pinnacle West’s loan agreements contain "cross-default"“cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements.  All of APS’s bank agreements contain "cross-default"“cross-default” provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under certain other material agreements.  Pinnacle West and APS do not have a material adverse change restriction for credit facility borrowings.

On November 27, 2018,December 17, 2020, the ACC issued a financing order that, subject to specified parameters and procedures, increased APS’s long-term debt limit from $5.1$5.9 billion to $5.9$7.5 billion, and authorized APS’s short-term debt limitauthorization equal to athe 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 March 27, 2020, APS filed an application with the ACC to increase the long-term debt limit from $5.9 billion to $7.5 billion and to continue its authorization of short-term debt granted in the 2018 financing order.  If the ACC does not approve this application by December 31, 2020, this could impact APS’s ability to enter into new long-term debt obligations.
85



Credit Ratings

The ratings of securities of Pinnacle West and APS as of May 1, 2020April 28, 2021 are shown below.  We are disclosing these credit ratings to enhance understanding of our cost of short-term and long-term capital and our ability to access the markets for liquidity and long-term debt.  The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained.  There is no assurance that these ratings will continue for any given period of time.  The ratings may be revised or withdrawn entirely by the rating agencies if, in their respective judgments, circumstances so warrant.  Any downward revision or withdrawal may adversely affect the market price of Pinnacle West’s or APS’s securities and/or result in an increase in the cost of, or limit access to, capital.  Such revisions may also result in substantial additional cash or other collateral requirements related to certain derivative instruments, insurance policies, natural gas transportation, fuel supply, and other energy-related contracts.  At this time, we believe we have sufficient available liquidity resources to respond to a downward revision to our credit ratings.

Moody’sStandard & Poor’sFitch
Pinnacle West
Corporate credit ratingA3A-A-
Senior unsecuredA3BBB+A-
Commercial paperP-2A-2F2
OutlookNegativeStableNegative
APS
Corporate credit ratingA2A-A-
Senior unsecuredA2A-A
Commercial paperP-1A-2F2
OutlookNegativeStableNegative
 
Off-Balance SheetsSheet Arrangements

See Note 6 for a discussion of the impacts on our financial statements of consolidating certain VIEs.
 
Contractual Obligations

As of March 31, 2021, our fuel and purchased power commitments have increased from the information provided in our 2020 Form 10-K. The increase is primarily due to new purchased power and energy storage commitments of approximately $550 million. The majority of the changes relate to 2026 and thereafter.

Other than the item described above, there have been no material changes, as of March 31, 2021, outside the normal course of business in contractual obligations from the information provided in our 20192020 Form 10-K. See Note 3 for discussion regarding changes in our short-term and long-term debt obligations.


86

CRITICAL ACCOUNTING POLICIES
 
In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period.  Some of those judgments can be subjective and complex, and actual results could differ from those estimates.  There have been no changes to our critical accounting policies since our 20192020 Form 10-K.  See "Critical“Critical Accounting Policies"Policies” in Item 7 of the 20192020 Form 10-K for further details about our critical accounting policies.




OTHER ACCOUNTING MATTERS

On January 1, 2020 we adopted ASU 2016-13, and related amendments, pertaining to the measurement of credit losses on financial instruments. See Note 13 for additional information related to new accounting standards.


MARKET AND CREDIT RISKS

Market Risks

Our operations include managing market risks related to changes in interest rates, commodity prices, investments held by our nuclear decommissioning trust,Nuclear Decommissioning Trusts, other special use funds and benefit plan assets.

Interest Rate and Equity Risk

We have exposure to changing interest rates.  Changing interest rates will affect interest paid on variable-rate debt and the market value of fixed income securities held by our nuclear decommissioning trust,Nuclear Decommissioning Trusts, other special use funds (see Note 11 and Note 12), and benefit plan assets.  The nuclear decommissioning trust,Nuclear Decommissioning Trusts, other special use funds and benefit plan assets also have risks associated with the changing market value of their equity and other non-fixed income investments.  Nuclear decommissioning and benefit plan costs are recovered in regulated electricity prices.

Commodity Price Risk

We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity and natural gas.  Our risk management committee, consisting of officers and key management personnel, oversees company-wide energy risk management activities to ensure compliance with our stated energy risk management policies.  We manage risks associated with these market fluctuations by utilizing various commodity instruments that may qualify as derivatives, including futures, forwards, options and swaps.  As part of our risk management program, we use such instruments to hedge purchases and sales of electricity and fuels.natural gas.  The changes in market value of such contracts have a high correlation to price changes in the hedged commodities.

The following table shows the net pretax changes in mark-to-market of our derivative positions for the three months ended March 31, 2020 and 2019 (dollars in millions):
 Three Months Ended
March 31,
 20212020
Mark-to-market of net positions at beginning of period$(13)$(71)
Decrease (Increase) in regulatory asset30 (14)
Recognized in OCI:
Mark-to-market losses realized during the period— — 
Change in valuation techniques— — 
Mark-to-market of net positions at end of period$17 $(85)

87
 Three Months Ended
March 31,
 2020 2019
Mark-to-market of net positions at beginning of period$(71) $(58)
Decrease (Increase) in regulatory asset(14) 12
Recognized in OCI:   
Mark-to-market losses realized during the period—
 —
Change in valuation techniques—
 —
Mark-to-market of net positions at end of period$(85) $(46)




The table below shows the fair value of maturities of our derivative contracts (dollars in millions) at March 31, 20202021 by maturities and by the type of valuation that is performed to calculate the fair values, classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  See Note 1, "Derivative Accounting"“Derivative Accounting” and "Fair“Fair Value Measurements,"Measurements” in Item 8 of our 20192020 Form 10-K and Note 11 for more discussion of our valuation methods.
Source of Fair Value20212022202320242025Total 
Fair 
Value
Observable prices provided by other external sources$3 $1 $(1)$— $— $3 
Prices based on unobservable inputs14 — — — — 14 
Total by maturity$17 $1 $(1)$— $— $17 
Source of Fair Value 2020 2021 2022 2023 2024 
Total 
Fair 
Value
Observable prices provided by other external sources $(46) $(13) $(12) $(6) $—
 $(77)
Prices based on unobservable inputs (5) —
 —
 —
 (3) (8)
Total by maturity $(51) $(13) $(12) $(6) $(3) $(85)

The table below shows the impact that hypothetical price movements of 10% would have on the market value of our risk management assets and liabilities included on Pinnacle West’s Condensed Consolidated Balance Sheets at March 31, 2020 and December 31, 2019 (dollars in millions):

March 31, 2021December 31, 2020
 Gain (Loss)Gain (Loss)
 Price Up 10%Price Down 10%Price Up 10%Price Down 10%
Mark-to-market changes reported in:    
Regulatory asset (liability) (a)    
Electricity$6 $(6)$4 $(4)
Natural gas45 (45)49 (49)
Total$51 $(51)$53 $(53)

 March 31, 2020 December 31, 2019
 Gain (Loss) Gain (Loss)
 Price Up 10% Price Down 10% Price Up 10% Price Down 10%
Mark-to-market changes reported in: 
  
  
  
Regulatory asset (a) 
  
  
  
Electricity$1
 $(1) $—
 $—
Natural gas53
 (53) 55
 (55)
Total$54
 $(54) $55
 $(55)
(a)These contracts are economic hedges of our forecasted purchases of natural gas and electricity.  The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged.  To the extent the amounts are eligible for inclusion in the PSA, the amounts are recorded as either a regulatory asset or liability.

(a)These contracts are economic hedges of our forecasted purchases of natural gas and electricity.  The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged.  To the extent the amounts are eligible for inclusion in the PSA, the amounts are recorded as either a regulatory asset or liability.

Credit Risk

We are exposed to losses in the event of non-performance or non-payment by counterparties.  See Note 7 for a discussion of our credit valuation adjustment policy.


Item 3.        QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
See "Key“Key Financial Drivers"Drivers” and "Market“Market and Credit Risks"Risks” in Item 2 above for a discussion of quantitative and qualitative disclosures about market risks.
 

88

Item 4.         CONTROLS AND PROCEDURES
 
(a)                                Disclosure Controls and Procedures
 
The term "disclosure“disclosure controls and procedures"procedures” means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the "Exchange Act"“Exchange Act”) (15 U.S.C. 78a et seq.), is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms.  Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to a company’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
 
Pinnacle West’s management, with the participation of Pinnacle West’s Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of Pinnacle West’s disclosure controls and procedures as of March 31, 2020.2021.  Based on that evaluation, Pinnacle West’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, Pinnacle West’s disclosure controls and procedures were effective.
 
APS’s management, with the participation of APS’s Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of APS’s disclosure controls and procedures as of March 31, 2020.2021.  Based on that evaluation, APS’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, APS’s disclosure controls and procedures were effective.
 
(b)                                Changes in Internal Control Over Financial Reporting
 
The term "internal“internal control over financial reporting"reporting” (defined in SEC Rule 13a-15(f)) refers to the process of a company that is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.
 
No change in Pinnacle West’s or APS’s internal control over financial reporting occurred during the fiscal quarter ended March 31, 20202021 that materially affected, or is reasonably likely to materially affect, Pinnacle West’s or APS’s internal control over financial reporting.


89

PART II — OTHER INFORMATION

Item 1.        LEGAL PROCEEDINGS
 
See "Business“Business of Arizona Public Service Company — Environmental Matters"Matters” in Item 1 of the 20192020 Form 10-K with regard to pending or threatened litigation and other disputes.matters.
 
See Note 4 for ACC and FERC-related matters.
 
See Note 8 for information regarding environmental matters, Superfund-related matters and Superfund-related matters.other disputes.

Item 1A.    RISK FACTORS
 
In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A — Risk Factors in the 20192020 Form 10-K, which could materially affect the business, financial condition, cash flows or future results of Pinnacle West and APS.  The risks described in the 20192020 Form 10-K are not the only risks facing Pinnacle West and APS.  Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect the business, financial condition, cash flows and/or operating results of Pinnacle West and APS. 

The risk factor below is an update to our 2019 Form 10-K.

The outbreak of the Coronavirus (“COVID-19”) pandemic could negatively affect our business. 

The recent outbreak of COVID-19 is a rapidly developing situation around the globe that has led to economic disruption and volatility in the financial markets. The continued spread of COVID-19 and efforts to contain the virus could decrease demand for energy, lower economic growth, impact our employees and contractors, cause disruptions in our supply chain, increase certain costs, further increase volatility in the capital markets (and result in increases in the cost of capital or an inability to access the capital markets or draw on available credit facilities), delay the completion of capital or other construction projects and other operations and maintenance activities, delay payments or increase uncollectable accounts or cause other unpredictable events, each of which could adversely affect our business, results of operations, cash flows or financial condition.

In the near term, as a result of the COVID-19 pandemic, in mid-March 2020 we drew on our revolving credit facilities as a result of the commercial paper markets failing to function normally.  Additionally, in March and April 2020 we experienced a net decrease in weather normalized retail electricity sales as compared to 2019. APS is also anticipating an increase in bad debt expense associated with the COVID-19 pandemic that will result in a negative impact to our 2020 operating results. Despite our efforts to manage the impacts, the degree to which the COVID-19 pandemic and related actions ultimately impact our business, financial position, results of operations and cash flows will depend on factors beyond our control including the duration, spread and severity of the outbreak, the actions taken to contain COVID-19 and mitigate its public health effects, the impact on the U.S. and global economies and demand for energy, and how quickly and to what extent normal economic and operating conditions resume.

Item 5.    OTHER INFORMATION

Labor Union Matter

None.
Approximately 1,300 APS employees are union employees, represented by the International Brotherhood of Electrical Workers ("IBEW"). In March 2020, the Company concluded negotiations with the


IBEW and approved an extension of the contract that was set to expire on April 1, 2020 and that will now expire on April 1, 2023. Under the extension, union members received wage increases for 2020, 2021, and 2022.


90

Item 6.         EXHIBITS

(a) Exhibits
Exhibit No.Registrant(s)Description
Exhibit No.10.1Registrant(s)Description
10.1Pinnacle West
Form of Performance Share Award Agreement under the Pinnacle West Capital Corporation 2012 Long-Term Incentive PlanAPS
10.2Pinnacle West
31.1Pinnacle West
31.2Pinnacle West
31.3APS
31.4APS
32.1*Pinnacle West
32.2*APS
101.INS
Pinnacle West
APS
XBRL Instance Document - the instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
101.SCH
Pinnacle West
APS
XBRL Taxonomy Extension Schema Document
101.CAL
Pinnacle West
APS
XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB
Pinnacle West
APS
XBRL Taxonomy Extension Label Linkbase Document
101.PRE
Pinnacle West
APS
XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF
Pinnacle West
APS
XBRL Taxonomy Definition Linkbase Document
104
Pinnacle West
APS
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

*Furnished herewith as an Exhibit.

91

In addition, Pinnacle West and APS hereby incorporate the following Exhibits pursuant to Exchange Act Rule 12b-32 and Regulation §229.10(d) by reference to the filings set forth below:
 
Exhibit No.Registrant(s)DescriptionPreviously Filed as Exhibit(1)Date Filed
3.1
Pinnacle West3.1 to Pinnacle West/APS February 25, 2020 Form 8-K Report, File Nos. 1-8962 and 1-44732/25/2020
3.2
Pinnacle West3.1 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File Nos. 1-8962 and 1-44738/7/2008
3.3
APSArticles of Incorporation, restated as of May 25, 19884.2 to APS’s Form S-3 Registration Nos. 33-33910 and 33-55248 by means of September 24, 1993 Form  8-K Report, File No. 1-44739/29/1993
3.4
APS3.1 to Pinnacle West/APS May 22, 2012 Form 8-K Report, File Nos. 1-8962 and 1-44735/22/2012
3.5
APS3.4 to Pinnacle West/APS December 31, 2008 Form 10-K, File Nos. 1-8962 and 1-44732/20/2009

(1)  Reports filed under File Nos. 1-4473 and 1-8962 were filed in the office of the Securities and Exchange Commission located in Washington, D.C.

92

SIGNATURES
 
Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
PINNACLE WEST CAPITAL CORPORATION
(Registrant)
Dated:May 5, 2021PINNACLE WEST CAPITAL CORPORATION
By:(Registrant)
Dated:May 8, 2020By:/s/ Theodore N. Geisler
Theodore N. Geisler
Senior Vice President and
Chief Financial Officer
(Principal Financial Officer and
Officer Duly Authorized to sign this Report)
ARIZONA PUBLIC SERVICE COMPANY
(Registrant)
Dated:May 8, 20205, 2021By:/s/ Theodore N. Geisler
Theodore N. Geisler
Senior Vice President and
Chief Financial Officer
(Principal Financial Officer and
Officer Duly Authorized to sign this Report)


90
93