PINNACLE WEST CAPITAL CORP, 10-Q filed on 5/8/2020
Quarterly Report
v3.20.1
Document and Entity Information - shares
3 Months Ended
Mar. 31, 2020
May 01, 2020
Entity Information [Line Items]    
Entity Shell Company false  
Entity Interactive Data Current Yes  
Security Exchange Name NYSE  
Trading Symbol PNW  
Title of 12(b) Security Common Stock  
Entity Tax Identification Number 86-0512431  
Entity Address, Address Line One 400 North Fifth Street, P.O. Box 53999  
Entity Address, City or Town Phoenix  
Entity Address, State or Province AZ  
Entity Address, Postal Zip Code 85072-3999  
City Area Code (602)  
Local Phone Number 250-1000  
Entity File Number 1-8962  
Document Transition Report false  
Document Quarterly Report true  
Entity Registrant Name PINNACLE WEST CAPITAL CORPORATION  
Entity Central Index Key 0000764622  
Document Type 10-Q  
Document Period End Date Mar. 31, 2020  
Amendment Flag false  
Current Fiscal Year End Date --12-31  
Entity Current Reporting Status Yes  
Entity Filer Category Large Accelerated Filer  
Entity Emerging Growth Company false  
Entity Small Business false  
Entity Common Stock, Shares Outstanding (in shares)   112,493,458
Document Fiscal Year Focus 2020  
Document Fiscal Period Focus Q1  
Entity Incorporation, State or Country Code AZ  
APS    
Entity Information [Line Items]    
Entity Shell Company false  
Entity Interactive Data Current Yes  
Entity Tax Identification Number 86-0011170  
Entity Address, Address Line One 400 North Fifth Street, P.O. Box 53999  
Entity Address, City or Town Phoenix  
Entity Address, State or Province AZ  
Entity Address, Postal Zip Code 85072-3999  
City Area Code (602)  
Local Phone Number 250-1000  
Entity File Number 1-4473  
Entity Registrant Name ARIZONA PUBLIC SERVICE COMPANY  
Entity Central Index Key 0000007286  
Document Type 10-Q  
Document Period End Date Mar. 31, 2020  
Amendment Flag false  
Current Fiscal Year End Date --12-31  
Entity Current Reporting Status Yes  
Entity Filer Category Non-accelerated Filer  
Entity Emerging Growth Company false  
Entity Small Business false  
Entity Common Stock, Shares Outstanding (in shares)   71,264,947
Document Fiscal Year Focus 2020  
Document Fiscal Period Focus Q1  
Entity Incorporation, State or Country Code AZ  
v3.20.1
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($)
shares in Thousands, $ in Thousands
3 Months Ended
Mar. 31, 2020
Mar. 31, 2019
OPERATING REVENUES (NOTE 2) $ 661,930 $ 740,530
OPERATING EXPENSES    
Fuel and purchased power 188,521 230,588
Operations and maintenance 221,318 245,634
Depreciation and amortization 154,079 148,707
Taxes other than income taxes 56,768 55,090
Other expenses 822 427
Total 621,508 680,446
OPERATING INCOME 40,422 60,084
OTHER INCOME (DEDUCTIONS)    
Allowance for equity funds used during construction 7,697 11,188
Pension and other postretirement non-service credits - net 13,911 5,114
Other income (Note 9) 12,569 7,169
Other expense (Note 9) (4,784) (4,358)
Total 29,393 19,113
INTEREST EXPENSE    
Interest charges 59,234 60,653
Allowance for borrowed funds used during construction (4,076) (6,665)
Total 55,158 53,988
INCOME BEFORE INCOME TAXES 14,657 25,209
INCOME TAXES (20,209) 2,418
NET INCOME 34,866 22,791
Less: Net income attributable to noncontrolling interests (Note 6) 4,873 4,873
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 29,993 $ 17,918
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING    
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares) 112,594 112,337
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares) 112,862 112,735
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING    
Net income attributable to common shareholders - basic (in dollars per share) $ 0.27 $ 0.16
Net income attributable to common shareholders - diluted (in dollars per share) $ 0.27 $ 0.16
APS    
OPERATING REVENUES (NOTE 2) $ 661,930 $ 740,530
OPERATING EXPENSES    
Fuel and purchased power 188,521 230,588
Operations and maintenance 218,265 240,375
Depreciation and amortization 154,058 148,685
Taxes other than income taxes 56,758 55,078
Other expenses 822 427
Total 618,424 675,153
OPERATING INCOME 43,506 65,377
OTHER INCOME (DEDUCTIONS)    
Allowance for equity funds used during construction 7,697 11,188
Pension and other postretirement non-service credits - net 14,262 5,499
Other income (Note 9) 11,633 6,416
Other expense (Note 9) (4,668) (3,878)
Total 28,924 19,225
INTEREST EXPENSE    
Interest charges 55,736 56,665
Allowance for borrowed funds used during construction (4,076) (6,665)
Total 51,660 50,000
INCOME BEFORE INCOME TAXES 20,770 34,602
INCOME TAXES (19,448) 1,453
NET INCOME 40,218 33,149
Less: Net income attributable to noncontrolling interests (Note 6) 4,873 4,873
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 35,345 $ 28,276
v3.20.1
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($)
$ in Thousands
3 Months Ended
Mar. 31, 2020
Mar. 31, 2019
NET INCOME $ 34,866 $ 22,791
Derivative instruments:    
Net unrealized gain, net of tax expense 292 0
Reclassification of net realized loss, net of tax benefit 20 328
Pension and other postretirement benefits activity, net of tax expense 1,205 879
Total other comprehensive income 1,517 1,207
COMPREHENSIVE INCOME 36,383 23,998
Less: Comprehensive income attributable to noncontrolling interests 4,873 4,873
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 31,510 19,125
APS    
NET INCOME 40,218 33,149
Derivative instruments:    
Net unrealized gain, net of tax expense 292 0
Reclassification of net realized loss, net of tax benefit 20 328
Pension and other postretirement benefits activity, net of tax expense 1,013 752
Total other comprehensive income 1,325 1,080
COMPREHENSIVE INCOME 41,543 34,229
Less: Comprehensive income attributable to noncontrolling interests 4,873 4,873
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 36,670 $ 29,356
v3.20.1
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) - USD ($)
$ in Thousands
3 Months Ended
Mar. 31, 2020
Mar. 31, 2019
Net unrealized loss, net of tax expense $ 292 $ 0
Reclassification of net realized loss, net of tax benefit 394 108
Pension and other postretirement benefits activity, net of tax expense (benefit) 108 288
APS    
Net unrealized loss, net of tax expense 292 0
Reclassification of net realized loss, net of tax benefit 394 108
Pension and other postretirement benefits activity, net of tax expense (benefit) $ 237 $ 247
v3.20.1
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($)
$ in Thousands
Mar. 31, 2020
Dec. 31, 2019
CURRENT ASSETS    
Cash and cash equivalents $ 63,139 $ 10,283
Customer and other receivables 258,874 266,426
Accrued unbilled revenues 93,434 128,165
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 receivable 20,599 21,727
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 assets 82,573 61,958
Total current assets 1,078,307 1,030,030
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 assets 97,822 96,953
Total investments and other assets 1,270,971 1,352,823
PROPERTY, PLANT AND EQUIPMENT    
Plant in service and held for future use 19,930,983 19,836,292
Accumulated depreciation and amortization (6,784,467) (6,637,857)
Net 13,146,516 13,198,435
Construction work in progress 942,258 808,133
Intangible assets, net of accumulated amortization 279,238 290,564
Nuclear fuel, net of accumulated amortization 168,457 123,500
Total property, plant and equipment 14,637,407 14,522,538
DEFERRED DEBITS    
Regulatory assets (Note 4) 1,302,448 1,304,073
Operating lease right-of-use assets 144,380 145,813
Assets for other postretirement benefits (Note 5) 96,243 90,570
Other 32,004 33,400
Total deferred debits 1,575,075 1,573,856
TOTAL ASSETS 18,561,760 18,479,247
CURRENT LIABILITIES    
Current maturities of long-term debt (Note 3) 650,000 800,000
Accounts payable 301,325 346,448
Accrued taxes 194,732 144,899
Accrued interest 53,608 53,534
Common dividends payable 0 87,982
Short-term borrowings (Note 3) 563,000 114,675
Customer deposits 54,965 64,908
Liabilities from risk management activities (Note 7) 54,784 38,946
Liabilities for asset retirements 10,095 11,025
Operating lease liabilities 12,360 12,713
Regulatory liabilities (Note 4) 279,105 234,912
Other current liabilities 121,514 168,323
Total current liabilities 2,295,488 2,078,365
Long-term debt less current maturities (Note 3) 4,833,324 4,832,558
DEFERRED CREDITS AND OTHER    
Deferred income taxes 2,016,770 1,992,339
Regulatory liabilities (Note 4) 2,067,801 2,267,835
Liabilities for asset retirements 649,226 646,193
Liabilities for pension benefits (Note 5) 273,284 280,185
Liabilities from risk management activities (Note 7) 32,577 33,186
Customer advances 212,545 215,330
Unrecorded Unconditional Purchase Obligation 166,796 165,695
Deferred investment tax credit 196,002 196,468
Unrecognized tax benefits 6,400 6,189
Operating lease liabilities 51,198 51,872
Other 163,517 159,844
Total deferred credits and other 5,836,116 6,015,136
COMMITMENTS AND CONTINGENCIES (SEE NOTE 8)
EQUITY    
Common stock, no par value; authorized 150,000,000 shares, 112,563,610 and 112,540,126 issued at respective dates 2,664,387 2,659,561
Treasury stock at cost; 72,302 and 103,546 shares at respective dates (7,000) (9,427)
Total common stock 2,657,387 2,650,134
Retained earnings 2,867,610 2,837,610
Accumulated other comprehensive loss (55,579) (57,096)
Total shareholders’ equity 5,469,418 5,430,648
Noncontrolling interests (Note 6) 127,414 122,540
Total equity 5,596,832 5,553,188
TOTAL LIABILITIES AND EQUITY 18,561,760 18,479,247
APS    
CURRENT ASSETS    
Cash and cash equivalents 53,351 10,169
Customer and other receivables 258,457 255,479
Accrued unbilled revenues 93,434 128,165
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 receivable 8,724 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 assets 57,471 38,895
Total current assets 1,031,125 981,492
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 assets 44,681 43,781
Total investments and other assets 1,217,830 1,299,651
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)
Net 13,146,294 13,198,208
Construction work in progress 942,258 808,133
Intangible assets, net of accumulated amortization 279,082 290,409
Nuclear fuel, net of accumulated amortization 168,457 123,500
Total property, plant and equipment 14,637,029 14,522,156
DEFERRED DEBITS    
Regulatory assets (Note 4) 1,302,448 1,304,073
Operating lease right-of-use assets 142,647 144,024
Assets for other postretirement benefits (Note 5) 92,391 86,736
Other 31,282 32,591
Total deferred debits 1,568,768 1,567,424
TOTAL ASSETS 18,454,752 18,370,723
CURRENT LIABILITIES    
Current maturities of long-term debt (Note 3) 200,000 350,000
Accounts payable 294,037 338,006
Accrued taxes 190,571 136,328
Accrued interest 51,042 52,619
Common dividends payable 0 88,000
Short-term borrowings (Note 3) 430,000 0
Customer deposits 54,965 64,908
Liabilities from risk management activities (Note 7) 54,784 38,946
Liabilities for asset retirements 10,095 11,025
Operating lease liabilities 12,224 12,549
Regulatory liabilities (Note 4) 279,105 234,912
Other current liabilities 133,497 164,736
Total current liabilities 1,710,320 1,492,029
Long-term debt less current maturities (Note 3) 4,833,743 4,833,133
DEFERRED CREDITS AND OTHER    
Deferred income taxes 2,057,824 2,033,096
Regulatory liabilities (Note 4) 2,067,801 2,267,835
Liabilities for asset retirements 649,226 646,193
Liabilities for pension benefits (Note 5) 255,749 262,243
Liabilities from risk management activities (Note 7) 32,577 33,186
Customer advances 212,545 215,330
Unrecorded Unconditional Purchase Obligation 166,796 165,695
Deferred investment tax credit 196,002 196,468
Unrecognized tax benefits 40,399 40,188
Operating lease liabilities 49,442 50,092
Other 141,984 136,432
Total deferred credits and other 5,870,345 6,046,758
COMMITMENTS AND CONTINGENCIES (SEE NOTE 8)
EQUITY    
Common stock 178,162 178,162
Additional paid-in capital 2,721,696 2,721,696
Retained earnings 3,047,269 3,011,927
Accumulated other comprehensive loss (34,197) (35,522)
Total shareholders’ equity 5,912,930 5,876,263
Noncontrolling interests (Note 6) 127,414 122,540
Total equity 6,040,344 5,998,803
Total capitalization 10,874,087 10,831,936
TOTAL LIABILITIES AND EQUITY 18,454,752 18,370,723
Variable Interest Entity, Primary Beneficiary [Member]    
PROPERTY, PLANT AND EQUIPMENT    
Total property, plant and equipment 100,938 101,906
Variable Interest Entity, Primary Beneficiary [Member] | APS    
PROPERTY, PLANT AND EQUIPMENT    
Total property, plant and equipment 100,938 101,906
EQUITY    
Noncontrolling interests (Note 6) $ 127,414 $ 122,540
v3.20.1
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - $ / shares
Mar. 31, 2020
Dec. 31, 2019
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]    
Common stock, par value (in dollars per share)
Common stock, authorized shares (in shares) 150,000,000 150,000,000
Common stock, issued shares (in shares) 112,563,610 112,540,126
Treasury stock at cost, shares (in shares) 72,302 103,546
v3.20.1
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($)
$ in Thousands
3 Months Ended
Mar. 31, 2020
Mar. 31, 2019
CASH FLOWS FROM OPERATING ACTIVITIES    
NET INCOME $ 34,866 $ 22,791
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation and amortization including nuclear fuel 173,168 167,801
Deferred fuel and purchased power (5,785) 16,709
Deferred fuel and purchased power amortization (1,808) 12,872
Allowance for equity funds used during construction (7,697) (11,188)
Deferred income taxes (18,086) 3,620
Deferred investment tax credit (465) (353)
Stock compensation 6,282 12,074
Increase (Decrease) in Accounts and Notes Receivable (25,575) (15,476)
Changes in current assets and liabilities:    
Accrued unbilled revenues 34,731 23,093
Materials, supplies and fossil fuel 5,445 (13,057)
Income tax receivable 1,128 0
Increase (Decrease) in Prepaid Expense 20,202 10,115
Accounts payable (5,192) 26,593
Accrued taxes 49,833 45,130
Other current liabilities (63,096) (86,250)
Change in other long-term assets 81,143 (65,470)
Change in other long-term liabilities (106,212) 13,706
Net cash flow provided by operating activities 183,628 173,432
CASH FLOWS FROM INVESTING ACTIVITIES    
Capital expenditures (340,014) (259,792)
Contributions in aid of construction 3,152 7,938
Allowance for borrowed funds used during construction (4,076) (6,665)
Proceeds from nuclear decommissioning trust sales and other special use funds 195,087 179,048
Investment in nuclear decommissioning trust and other special use funds (195,658) (179,618)
Other 349 4,576
Net cash flow used for investing activities (341,160) (254,513)
CASH FLOWS FROM FINANCING ACTIVITIES    
Issuance of long-term debt 0 497,324
Short-term borrowing and payments — net (76,675) 172,650
Short-term debt borrowings 751,690 0
Short-term debt repayments (226,690) (5,000)
Repayment of long-term debt (150,000) (500,000)
Dividends paid on common stock (86,257) (80,897)
Common stock equity issuance - net of purchases (1,680) (2,653)
Net cash flow provided by financing activities 210,388 81,424
NET INCREASE IN CASH AND CASH EQUIVALENTS 52,856 343
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 10,283 5,766
CASH AND CASH EQUIVALENTS AT END OF PERIOD 63,139 6,109
APS    
CASH FLOWS FROM OPERATING ACTIVITIES    
NET INCOME 40,218 33,149
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation and amortization including nuclear fuel 173,147 167,779
Deferred fuel and purchased power (5,785) 16,709
Deferred fuel and purchased power amortization (1,808) 12,872
Allowance for equity funds used during construction (7,697) (11,188)
Deferred income taxes (17,782) (1,205)
Deferred investment tax credit (465) (353)
Increase (Decrease) in Accounts and Notes Receivable (15,045) (16,541)
Changes in current assets and liabilities:    
Accrued unbilled revenues 34,731 23,093
Materials, supplies and fossil fuel 5,445 (13,057)
Income tax receivable (1,411) 0
Increase (Decrease) in Prepaid Expense 18,164 9,598
Accounts payable (4,038) 30,774
Accrued taxes 54,243 54,234
Other current liabilities (49,149) (81,627)
Change in other long-term assets 82,178 (64,516)
Change in other long-term liabilities (105,117) 14,525
Net cash flow provided by operating activities 193,591 188,132
CASH FLOWS FROM INVESTING ACTIVITIES    
Capital expenditures (340,014) (259,446)
Contributions in aid of construction 3,152 7,938
Allowance for borrowed funds used during construction (4,076) (6,665)
Proceeds from nuclear decommissioning trust sales and other special use funds 195,087 179,048
Investment in nuclear decommissioning trust and other special use funds (195,658) (179,618)
Other (900) (1,140)
Net cash flow used for investing activities (342,409) (259,883)
CASH FLOWS FROM FINANCING ACTIVITIES    
Issuance of long-term debt 0 497,324
Short-term borrowing and payments — net 0 157,500
Short-term debt borrowings 540,000 0
Short-term debt repayments (110,000) 0
Repayment of long-term debt (150,000) (500,000)
Dividends paid on common stock (88,000) (82,700)
Net cash flow provided by financing activities 192,000 72,124
NET INCREASE IN CASH AND CASH EQUIVALENTS 43,182 373
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 10,169 5,707
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 53,351 $ 6,080
v3.20.1
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited) - USD ($)
$ in Thousands
Total
Common Stock
Treasury Stock
Retained Earnings
Accumulated Other Comprehensive Income (Loss)
Noncontrolling Interests
APS
APS
Common Stock
APS
Additional Paid-In Capital
APS
Retained Earnings
APS
Accumulated Other Comprehensive Income (Loss)
APS
Noncontrolling Interests
Beginning balance (in shares) at Dec. 31, 2018   112,159,896 58,135         71,264,947        
Balance at beginning of period at Dec. 31, 2018 $ 5,348,705 $ 2,634,265 $ (4,825) $ 2,641,183 $ (47,708) $ 125,790 $ 5,786,797 $ 178,162 $ 2,721,696 $ 2,788,256 $ (27,107) $ 125,790
Increase (Decrease) in Shareholders' Equity                        
Net Income 22,791     17,918   4,873 33,149     28,276   4,873
Other comprehensive income (loss) 1,207       1,207   1,080       1,080  
Dividends on common stock (15)     (15)                
Issuance of common stock (in shares)   180,426                    
Issuance of common stock 9,798 $ 9,798                    
Purchase of treasury stock (in shares) [1]     (75,791)                  
Purchase of treasury stock [1] (6,882)   $ (6,882)                  
Reissuance of treasury stock for stock-based compensation and other (in shares)     70,655                  
Reissuance of treasury stock for stock-based compensation and other 6,121   $ 6,121 0                
Ending balance (in shares) at Mar. 31, 2019   112,340,322 63,271         71,264,947        
Balance at end of period at Mar. 31, 2019 $ 5,381,725 $ 2,644,063 $ (5,586) 2,659,086 (46,501) 130,663 5,821,026 $ 178,162 2,721,696 2,816,532 (26,027) 130,663
Beginning balance (in shares) at Dec. 31, 2019 112,540,126 112,540,126 103,546         71,264,947        
Balance at beginning of period at Dec. 31, 2019 $ 5,553,188 $ 2,659,561 $ (9,427) 2,837,610 (57,096) 122,540 5,998,803 $ 178,162 2,721,696 3,011,927 (35,522) 122,540
Increase (Decrease) in Shareholders' Equity                        
Net Income 34,866     29,993   4,873 40,218     35,345   4,873
Other comprehensive income (loss) 1,517       1,517   1,325       1,325  
Dividends on common stock 8     8                
Issuance of common stock (in shares)   23,484                    
Issuance of common stock 4,826 $ 4,826                    
Purchase of treasury stock (in shares) [1]     (20,724)                  
Purchase of treasury stock [1] (2,086)   $ (2,086)                  
Reissuance of treasury stock for stock-based compensation and other (in shares)     51,968                  
Reissuance of treasury stock for stock-based compensation and other $ 4,513   $ 4,513 0                
Other       (1)   1 (2)     (3)   1
Ending balance (in shares) at Mar. 31, 2020 112,563,610 112,563,610 72,302         71,264,947        
Balance at end of period at Mar. 31, 2020 $ 5,596,832 $ 2,664,387 $ (7,000) $ 2,867,610 $ (55,579) $ 127,414 $ 6,040,344 $ 178,162 $ 2,721,696 $ 3,047,269 $ (34,197) $ 127,414
[1]
Primarily represents shares of common stock withheld from certain stock awards for tax purposes.
v3.20.1
Consolidation and Nature of Operations
3 Months Ended
Mar. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Consolidation and Nature of Operations
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"), Bright Canyon Energy Corporation ("BCE") and El Dorado Investment Company ("El 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") sale leaseback variable interest entities ("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").  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"), 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 2019 Form 10-K.


Supplemental Cash Flow Information

The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):
 
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 capitalized
53,723

 
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 liabilities
2,311

 
2,293



The following table summarizes supplemental APS cash flow information (dollars in thousands):
 
Three Months Ended
March 31,
 
2020
 
2019
Cash paid during the period for:
 
 
 
Income taxes, net of refunds
$

 
$

Interest, net of amounts capitalized
52,034

 
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 liabilities
2,311

 
2,293


v3.20.1
Revenue
3 Months Ended
Mar. 31, 2020
Revenue from Contract with Customer [Abstract]  
Revenue Revenue

Sources of Revenue

The following table provides detail of Pinnacle West's consolidated revenue disaggregated by revenue sources (dollars in thousands):
 
 
Three Months Ended March 31,
 
 
2020
2019
Retail Electric Revenue
 
 
 
Residential
 
$
325,073

$
351,566

Non-Residential
 
303,351

332,668

Wholesale energy sales
 
14,668

36,452

Transmission services for others
 
15,927

15,249

Other sources
 
2,911

4,595

Total operating revenues
 
$
661,930

$
740,530



Retail Electric Revenue. Pinnacle West's retail electric revenue is generated by wholly owned regulated subsidiary APS'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' 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.

Wholesale Energy Sales and Transmission Services for Others. Revenues from wholesale energy sales and transmission services for others represent energy and transmission sales to wholesale customers. These activities primarily consist of managing fuel and purchased power risks in connection with the cost of serving our retail customers' energy requirements. We may also sell into the wholesale markets generation that is not needed for APS’s retail load. Our wholesale activities and tariff rates are regulated by the United States Federal Energy Regulatory Commission ("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, 2020 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, 2020 and 2019, our revenues that do not qualify as revenue from contracts with customers were $14 million and $20 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, 2020 or December 31, 2019.

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. The allowance 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
increase in the number of customers needing to utilize longer-term payment plans to avoid service disruption. These changes, among others including the Summer Disconnection Moratorium (defined in Note 4), 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 impact our write-off factor for upcoming 2020 financial statements. 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, 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


v3.20.1
Long-Term Debt and Liquidity Matters
3 Months Ended
Mar. 31, 2020
Debt Disclosure [Abstract]  
Long-Term Debt and Liquidity Matters
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

At March 31, 2020, 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's senior unsecured debt credit ratings. The facility is available to support Pinnacle West's $200 million commercial paper program, for bank borrowings or for issuances of letters of credits. At March 31, 2020, Pinnacle West had $100 million outstanding borrowings under its credit facility, no letters of credit outstanding and no 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.

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, 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 million commercial paper program, for bank borrowings or for issuances of letters of credit.  At March 31, 2020, APS had $430 million outstanding borrowings under its revolving credit facilities and no letters of credit outstanding or commercial paper borrowings.

On November 27, 2018, the ACC issued a financing order in which, subject to specified parameters and procedures, it approved APS’s short-term debt authorization equal to a sum of (i) 7% of APS’s capitalization, and (ii) $500 million (which is required to be used for costs relating to purchases of natural gas and power) and a long-term debt authorization of $5.9 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" 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

APS
5,033,743

 
5,634,265

 
5,183,133

 
5,743,570

Total
$
5,483,324

 
$
6,082,714

 
$
5,632,558

 
$
6,194,392


v3.20.1
Regulatory Matters
3 Months Ended
Mar. 31, 2020
Regulated Operations [Abstract]  
Regulatory Matters Regulatory Matters
 
COVID-19 Pandemic

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.
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 depend on certain assumptions, including 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, due to COVID-19, APS delayed the reset of the Environmental Improvement Surcharge ("EIS") adjustor and suspended the discontinuation of TEAM Phase II to the first billing cycle in May 2020 rather than April 2020 (see below for discussion of EIS and TEAM Phase II).

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 has been collected through the Demand Side Management ("DSM") Adjustor Clause, but not allocated for current DSM programs, directly to customers through a bill credit in June 2020 (see below for discussion of the DSM Adjustor Clause).   Also, on May 5, 2020, APS also voluntarily committed to the ACC to contribute $5.3 million of non-ratepayer funds to provide assistance to residential and business customers that have been impacted by the COVID-19 pandemic.

2019 Retail Rate Case Filing with the Arizona Corporation Commission

On October 31, 2019, APS filed an application with the ACC for an annual increase in retail base rates of $69 million. This amount includes recovery of the deferral and rate base effects of the Four Corners selective catalytic reduction ("SCR") project that 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"). The proposed total revenue increase in APS'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's application are:

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;
authorization to defer until APS's next general rate case the increase or decrease in its Arizona property taxes attributable to tax rate changes after the date the rate application is adjudicated;
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;
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
continued recovery of the remaining investment and other costs related to the retirement and closure of the Navajo Generating Station (the "Navajo Plant") (see "Navajo Plant" below).

APS requested that the increase become effective December 1, 2020.  The hearing for this rate case was delayed by 75 days, at the request of ACC Staff, and is currently scheduled to begin September 30, 2020. APS cannot predict the outcome of its request.

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, limited income advocates and private rooftop solar organizations signed a settlement agreement (the "2017 Settlement Agreement") and filed it with the ACC. The 2017 Settlement Agreement provides for a net retail base rate increase of $94.6 million, excluding the transfer of adjustor balances, consisting of: (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");
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 Solar 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"), 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;
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.

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 Rate Case 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'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.

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;
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;
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.

APS cannot predict the outcome or impact of the rate case filed on October 31, 2019. 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.

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

On 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. The ACC has not yet ruled on the 2020 RES Implementation Plan.

On July 2, 2019, ACC Staff issued draft rules, which propose a RES goal of 45% of retail energy served be renewables by 2035 and 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 amount of the RES goal to be derived from distributed renewable storage, for which utilities would be required to offer performance-based incentives. Nuclear energy would be considered a clean resource under the draft rules. On February 18, 2020, ACC Staff issued revised draft rules which would change the RES and clean energy goals to standards and would provide additional reporting and compliance requirements. Certain ACC Commissioners have proposed different options with different implementation dates of these rules. APS cannot predict the outcome of this matter. See "Energy Modernization Plan" below for more information.

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

On September 1, 2017, APS filed its 2018 DSM Plan, which proposes 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 seeks a requested budget of $52.6 million and requests 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 requests a budget of $34.1 million and continues APS's focus on DSM strategies 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 requests a budget of $51.9 million and continues APS's focus on DSM strategies such as peak demand reduction, load shifting, storage and electrification strategies. The 2020 DSM Plan addresses all components of the 2018 and 2019 DSM plans, which enables the ACC to review the 2020 DSM Plan only. The ACC has not yet ruled on the APS 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 has been collected through the DSM Adjustor Clause, but not allocated for current DSM programs, directly to customers through a bill credit in June 2020. See "COVID-19 Pandemic" above for more information.
 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 2020 and 2019 (dollars in thousands):
 
 
Three Months Ended
March 31,
 
2020
 
2019
Beginning balance
$
70,137

 
$
37,164

Deferred fuel and purchased power costs — current period
5,785

 
(16,709
)
Amounts charged to customers
1,808

 
(12,872
)
Ending balance
$
77,730

 
$
7,583


 
The PSA rate for the PSA year beginning February 1, 2018 is $0.004555 per kWh, consisting of a forward component of $0.002009 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 Component of $(0.002086) per kWh and a Historical 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 March 15, 2019, APS filed an application with the ACC requesting approval to recover the costs related to two energy storage power purchase tolling agreements through the PSA. This application is pending with the ACC. APS cannot predict the outcome of this matter.

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 1st 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 - 14 million per year).  APS’s February 1, 2020 application requested an increase in the charge to $8.75 million, or $2.0 million over the charge in effect for the 2019-2020 rate effective year. On March 19, 2020, due to the COVID-19 pandemic, APS delayed the reset of the EIS adjustor to the first billing cycle in May 2020 rather than April 2020.
 
Transmission Rates, Transmission Cost Adjustor ("TCA") and Other Transmission Matters In July 2008, FERC approved a modification to APS’s Open Access Transmission Tariff to allow APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services.  A large portion of the rate represents charges for
transmission services to serve APS's retail customers ("Retail Transmission Charges").  In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA.  Under the terms of the settlement agreement entered into in 2012 regarding APS's rate case ("2012 Settlement Agreement"), however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC.
 
The formula rate is updated each year effective June 1 on the basis of APS's actual cost of service, as disclosed in APS's FERC Form 1 report for the previous fiscal year.  Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items.  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") 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's annual wholesale transmission rates for all users of its transmission system increased by approximately $4.9 million for the twelve-month period beginning June 1, 2019 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, 2019.

 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 to 2.5 cents for both lost residential and non-residential kWh.  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
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.

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

On 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").  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"). The ACC approved this request on March 13, 2019, effective the first billing cycle in April 2019 through the last billing cycle in March 2020. On March 19, 2020, due to the COVID-19 pandemic, APS delayed the discontinuation of TEAM Phase II until the first billing cycle in May 2020.  Amounts credited to customers after the last billing cycle in March 2020 will be recorded as a part of the balancing account and will be addressed for recovery as part of APS'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 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 related to the amortization of depreciation related excess deferred taxes for periods beginning after December 31, 2020 will be fully incorporated into the 2019 rate case.

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's subsequent rate cases which method (or a combination of methods) is appropriate to determine the actual price to be paid by APS for exported distributed energy.

In addition, the ACC made the following determinations:

Customers who have interconnected a DG system or submitted an application for interconnection for DG systems prior to September 1, 2017, based on APS's 2017 Rate Case Decision, will be grandfathered for a period of 20 years from the date the customer’s interconnection application was accepted by the utility;
Customers with DG solar systems are to be considered a separate class of customers for ratemaking purposes; and
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.

On January 23, 2017, The Alliance for Solar Choice ("TASC") sought rehearing of the ACC'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
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 Retail Rate Case Filing with the Arizona Corporation 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 Arizona Corporation Commissioner Robert Burns

On August 25, 2016, Commissioner 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's obligations to comply with the subpoenas and decline to decide APS'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' 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 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.
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. APS and Pinnacle West 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's CEO, Mr. Guldner, appeared at the ACC's January 14, 2020 Open Meeting regarding ACC 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") 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 generation, baseload security, blockchain technology and other technological developments, retail competition, and other energy-related topics. On April 25, 2019, the ACC Staff issued a set of draft rules in regards to the Energy Modernization Plan and workshops were held on April 29, 2019 regarding these draft rules. On July 2, 2019, the ACC Staff issued a revised set of draft rules, which propose a RES goal of 45% of retail energy served be renewable by 2035 and a goal of 20% of retail sales during peak demand to be from clean energy resources by 2035.  The draft rules also require a certain amount of the RES goal to be derived from distributed renewable storage, for which utilities would be required to offer performance-based incentives.  Nuclear energy would be considered a clean resource under the draft rules. The ACC held various stakeholder meetings and workshops on ACC Staff’s draft energy rules in July through September 2019. On February 18, 2020, 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
changing the IRP planning horizon from 15 years to 10 years. Certain ACC Commissioners have proposed different options with different implementation dates of these rules. 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. See "Energy Modernization Rules" above for information regarding proposed changes to the IRP filings.

Public Utility Regulatory Policies Act

In August 2016, APS filed an application requesting that all of its contracts with 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 a right to sell to the host utility. Host utilities are required to purchase power 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. On December 17, 2019, the ACC denied the application and mandated a minimum contract length of 18 years for qualifying facilities over 100 kW and the rate paid to the qualifying facilities will be based on the long-term avoided cost. APS is in discussions with qualifying facility developers but has not entered into any new qualifying facility agreements that would be subject to the new requirements of the ACC's decision.

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"). 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 issued 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.
Although the emergency rules expired in December 2019, the Summer Disconnection Moratorium will remain in effect through utility tariffs for 2020 and beyond until the ACC adopts permanent rules or determines otherwise.

Due to the COVID-19 pandemic, APS has voluntarily suspended disconnections of customers for nonpayment beginning March 13, 2020. APS currently estimates that 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. 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" 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 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 staff 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 for further consideration and discussion of 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

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’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. APS is providing 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 is not expected to have a material impact on APS'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. APS received a civil investigative demand from the Office of the Arizona Attorney General, Civil Litigation Division, Consumer Protection & Advocacy Section that seeks information pertaining to the rate plan comparison tool offered to APS customers. APS is fully cooperating with the Attorney General’s Office in this matter. APS cannot predict the outcome of these matters.

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 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'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 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") and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if the United States Environmental Protection Agency ("EPA") approved a compromise proposal offered by APS to meet required environmental and emissions standards and rules. On April 14, 2015, the ACC approved APS's plan to retire Unit 2, without expressing any view on the future recoverability of APS's remaining investment in the unit. APS closed Unit 2 on October 1, 2015. In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect on April 26, 2017. In December 2019, PacifiCorp notified APS that it plans to retire Cholla Unit 4 by the end of 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 ($69 million as of March 31, 2020), 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.
Navajo Plant
The co-owners of the Navajo Plant and the Navajo Nation agreed that the Navajo Plant would remain in operation until December 2019 under the existing plant lease. 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.
  
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 ($79 million as of March 31, 2020) 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. APS believes it will be allowed recovery of the net book value, in addition to a return on its investment. In accordance with GAAP, in the second quarter of 2017, APS's remaining net book value of its interest in the Navajo Plant was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery of the remaining net book value of this interest, all or a portion of the regulatory asset will be written off and APS's net income, cash flows, and financial position will be negatively impacted.    
Regulatory Assets and Liabilities 
The detail of regulatory assets is as follows (dollars in thousands): 
 
Amortization Through
 
March 31, 2020
 
December 31, 2019
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Pension
(a)
 
$

 
$
652,691

 
$

 
$
660,223

Retired power plant costs
2033
 
28,182

 
135,349

 
28,182

 
142,503

Income taxes — allowance for funds used during construction ("AFUDC") equity
2050
 
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 taxes
2027
 
8,569

 
56,053

 
8,569

 
58,196

SCR deferral
N/A
 

 
58,258

 

 
52,644

Ocotillo deferral
N/A
 

 
51,767

 

 
38,144

Four Corners cost deferral
2024
 
8,077

 
30,133

 
8,077

 
32,152

Deferred compensation
2036
 

 
37,550

 

 
36,464

Lost fixed cost recovery (b)
2021
 
28,885

 

 
26,067

 

Income taxes — investment tax credit basis adjustment
2048
 
1,098

 
24,920

 
1,098

 
24,981

Palo Verde VIEs (Note 6)
2046
 

 
20,790

 

 
20,635

Coal reclamation
2026
 
1,068

 
17,800

 
1,546

 
17,688

Loss on reacquired debt
2038
 
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 subsidy
2024
 
1,238

 
4,881

 
1,235

 
4,940

AG-1 deferral
2022
 
2,787

 
2,019

 
2,787

 
2,716

Tax expense adjuster mechanism (b)
2020
 
942

 

 
1,612

 

Other
Various
 
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."


The detail of regulatory liabilities is as follows (dollars in thousands):
 
 
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 obligations
2057
 

 
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 fuel
2027
 
6,638

 
49,234

 
6,676

 
51,019

Income taxes — change in rates
2050
 
2,802

 
51,152

 
2,797

 
68,265

Four Corners coal reclamation
2038
 
5,461

 
48,405

 
1,059

 
51,704

Income taxes — deferred investment tax credit
2048
 
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 maintenance
2031
 
184

 
13,515

 
5,698

 
11,319

Active union medical trust
N/A
 

 
7,986

 

 
2,041

Property tax deferral
N/A
 

 
7,968

 

 
7,046

Tax expense adjustor mechanism (b)
2020
 
6,615

 

 
7,018

 

Deferred gains on utility property
2022
 
2,423

 
3,577

 
2,423

 
4,163

FERC transmission true up
2022
 
3,304

 
1,621

 
1,045

 
2,004

Other
Various
 
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.
v3.20.1
Retirement Plans and Other Postretirement Benefits
3 Months Ended
Mar. 31, 2020
Retirement Benefits [Abstract]  
Retirement Plans and Other Postretirement Benefits
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 plan for the employees of Pinnacle West and our subsidiaries.  Pinnacle West uses a December 31 measurement date for its pension and other postretirement benefit plans.  The market-related value of our plan assets is their fair value at the measurement dates.

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

 
Pension Benefits
Other Benefits
 
Three Months Ended
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 obligation
29,761

 
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 loss
9,011

 
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
)

 
Contributions
 
We have not made voluntary contributions to our pension plan year-to-date in 2020. 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. We do not expect to make any contributions over the next three years to our other postretirement benefit plans.
v3.20.1
Palo Verde Sale Leaseback Variable Interest Entities
3 Months Ended
Mar. 31, 2020
Variable Interest Entities [Abstract]  
Palo Verde Sale Leaseback Variable Interest Entities
Palo Verde Sale Leaseback Variable Interest Entities
 
In 1986, APS entered into agreements with three separate VIE lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. APS will retain the assets through 2023 under one lease and 2033 under the other two leases. APS will be required to make payments relating to these leases of approximately $23 million annually for the period 2020 through 2023, and $16 million annually for the period 2024 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' 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, 2020 and 2019 of $5 million for each period, entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders is not impacted by the consolidation.

Our Condensed Consolidated Balance Sheets at March 31, 2020 and December 31, 2019 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 interests
127,414

 
122,540


 
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") 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 million beginning in 2020, and up to $456 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.
v3.20.1
Derivative Accounting
3 Months Ended
Mar. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Derivative Accounting 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.  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.
 
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 had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): 
 
 
 
Quantity
Commodity
 
Unit of Measure
March 31, 2020
 
December 31, 2019
Power
 
GWh
477

 
193

Gas
 
Billion cubic feet
263

 
257


 
Gains and Losses from Derivative Instruments
 
The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the three months ended March 31, 2020 and 2019 (dollars in thousands):
 
 
 
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 no gains or losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.
(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 taxes will be reclassified from accumulated OCI as an offset to the effect of market price changes for the related hedged transactions.  In accordance with the PSA, most of these amounts will be recorded as either a regulatory asset or liability and have no immediate effect on earnings.

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,
Commodity Contracts
 
 
2020
 
2019
Net Gain (Loss) Recognized in Income
 
Fuel and purchased power (a)
 
$
(30,078
)
 
$
8,170


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

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
)