Cover Page
Cover Page - shares | 6 Months Ended | |
Jun. 30, 2021 | Jul. 29, 2021 | |
Entity Information [Line Items] | ||
Document Type | 10-Q | |
Document Quarterly Report | true | |
Document Period End Date | Jun. 30, 2021 | |
Document Transition Report | false | |
Entity File Number | 1-8962 | |
Entity Registrant Name | PINNACLE WEST CAPITAL CORPORATION | |
Entity Tax Identification Number | 86-0512431 | |
Entity Incorporation, State or Country Code | AZ | |
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 | |
Title of 12(b) Security | Common Stock | |
Trading Symbol | PNW | |
Security Exchange Name | NYSE | |
Entity Current Reporting Status | Yes | |
Entity Interactive Data Current | Yes | |
Entity Filer Category | Large Accelerated Filer | |
Entity Small Business | false | |
Entity Emerging Growth Company | false | |
Entity Shell Company | false | |
Entity Common Stock, Shares Outstanding | 112,785,588 | |
Entity Central Index Key | 0000764622 | |
Amendment Flag | false | |
Current Fiscal Year End Date | --12-31 | |
Document Fiscal Year Focus | 2021 | |
Document Fiscal Period Focus | Q2 | |
APS | ||
Entity Information [Line Items] | ||
Document Type | 10-Q | |
Document Period End Date | Jun. 30, 2021 | |
Entity File Number | 1-4473 | |
Entity Registrant Name | ARIZONA PUBLIC SERVICE COMPANY | |
Entity Tax Identification Number | 86-0011170 | |
Entity Incorporation, State or Country Code | AZ | |
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 Current Reporting Status | Yes | |
Entity Interactive Data Current | Yes | |
Entity Filer Category | Non-accelerated Filer | |
Entity Small Business | false | |
Entity Emerging Growth Company | false | |
Entity Shell Company | false | |
Entity Common Stock, Shares Outstanding | 71,264,947 | |
Entity Central Index Key | 0000007286 | |
Amendment Flag | false | |
Current Fiscal Year End Date | --12-31 | |
Document Fiscal Year Focus | 2021 | |
Document Fiscal Period Focus | Q2 |
CONDENSED CONSOLIDATED STATEMEN
CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2021 | Jun. 30, 2020 | Jun. 30, 2021 | Jun. 30, 2020 | |
OPERATING REVENUES (NOTE 2) | $ 1,000,249 | $ 929,590 | $ 1,696,724 | $ 1,591,520 |
OPERATING EXPENSES | ||||
Fuel and purchased power | 269,835 | 238,382 | 468,062 | 426,903 |
Operations and maintenance | 229,690 | 219,392 | 459,745 | 440,710 |
Depreciation and amortization | 158,750 | 152,482 | 316,570 | 306,561 |
Taxes other than income taxes | 59,495 | 56,768 | 118,978 | 113,536 |
Other expenses | 4,093 | 692 | 7,449 | 1,514 |
Total | 721,863 | 667,716 | 1,370,804 | 1,289,224 |
OPERATING INCOME | 278,386 | 261,874 | 325,920 | 302,296 |
OTHER INCOME (DEDUCTIONS) | ||||
Allowance for equity funds used during construction | 9,990 | 8,811 | 19,197 | 16,508 |
Pension and other postretirement non-service credits — net | 28,175 | 14,142 | 55,966 | 28,053 |
Other income (Note 9) | 12,207 | 16,670 | 24,636 | 29,239 |
Other expense (Note 9) | (5,184) | (4,036) | (9,037) | (8,820) |
Total | 45,188 | 35,587 | 90,762 | 64,980 |
INTEREST EXPENSE | ||||
Interest charges | 62,777 | 62,690 | 124,715 | 121,924 |
Allowance for borrowed funds used during construction | (5,199) | (4,749) | (10,193) | (8,825) |
Total | 57,578 | 57,941 | 114,522 | 113,099 |
INCOME BEFORE INCOME TAXES | 265,996 | 239,520 | 302,160 | 254,177 |
INCOME TAXES | 46,560 | 41,061 | 42,210 | 20,852 |
NET INCOME | 219,436 | 198,459 | 259,950 | 233,325 |
Less: Net income attributable to noncontrolling interests (Note 6) | 3,739 | 4,874 | 8,612 | 9,747 |
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS | $ 215,697 | $ 193,585 | $ 251,338 | $ 223,578 |
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING | ||||
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares) | 112,882 | 112,638 | 112,855 | 112,616 |
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares) | 113,223 | 112,879 | 113,158 | 112,871 |
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING | ||||
Net income attributable to common shareholders - basic (in dollars per share) | $ 1.91 | $ 1.72 | $ 2.23 | $ 1.99 |
Net income attributable to common shareholders - diluted (in dollars per share) | $ 1.91 | $ 1.71 | $ 2.22 | $ 1.98 |
APS | ||||
OPERATING REVENUES (NOTE 2) | $ 1,000,249 | $ 929,590 | $ 1,696,724 | $ 1,591,520 |
OPERATING EXPENSES | ||||
Fuel and purchased power | 269,835 | 238,382 | 468,062 | 426,903 |
Operations and maintenance | 226,698 | 216,221 | 453,099 | 434,486 |
Depreciation and amortization | 158,728 | 152,460 | 316,528 | 306,518 |
Taxes other than income taxes | 59,478 | 56,758 | 118,950 | 113,516 |
Other expenses | 4,093 | 692 | 7,449 | 1,514 |
Total | 718,832 | 664,513 | 1,364,088 | 1,282,937 |
OPERATING INCOME | 281,417 | 265,077 | 332,636 | 308,583 |
OTHER INCOME (DEDUCTIONS) | ||||
Allowance for equity funds used during construction | 9,990 | 8,811 | 19,197 | 16,508 |
Pension and other postretirement non-service credits — net | 28,234 | 14,421 | 56,071 | 28,683 |
Other income (Note 9) | 11,563 | 13,272 | 23,523 | 24,905 |
Other expense (Note 9) | (4,261) | (3,859) | (7,611) | (8,527) |
Total | 45,526 | 32,645 | 91,180 | 61,569 |
INTEREST EXPENSE | ||||
Interest charges | 59,930 | 56,802 | 119,318 | 112,538 |
Allowance for borrowed funds used during construction | (5,199) | (4,749) | (10,193) | (8,825) |
Total | 54,731 | 52,053 | 109,125 | 103,713 |
INCOME BEFORE INCOME TAXES | 272,212 | 245,669 | 314,691 | 266,439 |
INCOME TAXES | 48,725 | 43,677 | 51,044 | 24,229 |
NET INCOME | 223,487 | 201,992 | 263,647 | 242,210 |
Less: Net income attributable to noncontrolling interests (Note 6) | 3,739 | 4,874 | 8,612 | 9,747 |
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS | $ 219,748 | $ 197,118 | $ 255,035 | $ 232,463 |
CONDENSED CONSOLIDATED STATEM_2
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2021 | Jun. 30, 2020 | Jun. 30, 2021 | Jun. 30, 2020 | |
NET INCOME | $ 219,436 | $ 198,459 | $ 259,950 | $ 233,325 |
Derivative instruments: | ||||
Net unrealized gain, net of tax benefit (expense) | 870 | (1,549) | 1,132 | (1,257) |
Reclassification of net realized gain, net of tax benefit (expense) | 0 | 262 | 0 | 282 |
Pension and other postretirement benefit activity, net of tax expense (benefit) | 64 | (1,009) | 1,086 | 196 |
Total other comprehensive income | 934 | (2,296) | 2,218 | (779) |
COMPREHENSIVE INCOME | 220,370 | 196,163 | 262,168 | 232,546 |
Less: Comprehensive income attributable to noncontrolling interests | 3,739 | 4,874 | 8,612 | 9,747 |
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS | 216,631 | 191,289 | 253,556 | 222,799 |
APS | ||||
NET INCOME | 223,487 | 201,992 | 263,647 | 242,210 |
Derivative instruments: | ||||
Net unrealized gain, net of tax benefit (expense) | 0 | 0 | 0 | 292 |
Reclassification of net realized gain, net of tax benefit (expense) | 0 | 262 | 0 | 282 |
Pension and other postretirement benefit activity, net of tax expense (benefit) | 159 | (1,090) | 1,086 | (77) |
Total other comprehensive income | 159 | (828) | 1,086 | 497 |
COMPREHENSIVE INCOME | 223,646 | 201,164 | 264,733 | 242,707 |
Less: Comprehensive income attributable to noncontrolling interests | 3,739 | 4,874 | 8,612 | 9,747 |
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS | $ 219,907 | $ 196,290 | $ 256,121 | $ 232,960 |
CONDENSED CONSOLIDATED STATEM_3
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2021 | Jun. 30, 2020 | Jun. 30, 2021 | Jun. 30, 2020 | |
Net unrealized gain, tax benefit (expense) | $ (286) | $ 513 | $ (372) | $ 805 |
Reclassification of net realized gain, tax expense | 0 | 87 | 0 | 481 |
Pension and other postretirement benefits activity, tax benefit (expense) | (21) | 334 | (357) | 90 |
APS | ||||
Net unrealized gain, tax benefit (expense) | 0 | 0 | 0 | 292 |
Reclassification of net realized gain, tax expense | 0 | 87 | 0 | 481 |
Pension and other postretirement benefits activity, tax benefit (expense) | $ (53) | $ 361 | $ (357) | $ 124 |
CONDENSED CONSOLIDATED BALANCE
CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Jun. 30, 2021 | Dec. 31, 2020 |
CURRENT ASSETS | ||
Cash and cash equivalents | $ 14,146 | $ 59,968 |
Customer and other receivables | 357,130 | 313,576 |
Accrued unbilled revenues | 223,918 | 132,197 |
Allowance for doubtful accounts (Note 2) | (22,769) | (19,782) |
Materials and supplies (at average cost) | 340,672 | 314,745 |
Fossil fuel (at average cost) | 25,074 | 19,552 |
Income tax receivable | 0 | 6,792 |
Assets from risk management activities (Note 7) | 82,309 | 2,931 |
Deferred fuel and purchased power regulatory asset (Note 4) | 300,912 | 175,835 |
Other regulatory assets (Note 4) | 119,890 | 115,878 |
Other current assets | 81,901 | 76,627 |
Total current assets | 1,523,183 | 1,198,319 |
INVESTMENTS AND OTHER ASSETS | ||
Nuclear decommissioning trusts (Notes 11 and 12) | 1,223,088 | 1,138,435 |
Other special use funds (Notes 11 and 12) | 358,436 | 254,509 |
Other assets | 112,091 | 92,922 |
Total investments and other assets | 1,693,615 | 1,485,866 |
PROPERTY, PLANT AND EQUIPMENT | ||
Plant in service and held for future use | 21,236,805 | 20,837,885 |
Accumulated depreciation and amortization | (7,278,877) | (7,110,310) |
Net | 13,957,928 | 13,727,575 |
Construction work in progress | 1,062,911 | 937,384 |
Palo Verde sale leaseback, net of accumulated depreciation (Note 6) | 96,101 | 98,036 |
Intangible assets, net of accumulated amortization | 279,911 | 282,570 |
Nuclear fuel, net of accumulated amortization | 109,110 | 113,645 |
Total property, plant and equipment | 15,505,961 | 15,159,210 |
DEFERRED DEBITS | ||
Regulatory assets (Note 4) | 1,173,977 | 1,133,987 |
Operating lease right-of-use assets (Note 15) | 718,948 | 505,064 |
Assets for pension and other postretirement benefits (Note 5) | 407,821 | 502,992 |
Other | 38,073 | 34,983 |
Total deferred debits | 2,338,819 | 2,177,026 |
TOTAL ASSETS | 21,061,578 | 20,020,421 |
CURRENT LIABILITIES | ||
Accounts payable | 377,157 | 318,585 |
Accrued taxes | 183,037 | 159,551 |
Accrued interest | 56,864 | 56,962 |
Common dividends payable | 93,610 | 93,531 |
Short-term borrowings (Note 3) | 504,700 | 169,000 |
Current maturities of long-term debt (Note 3) | 150,000 | 0 |
Customer deposits | 44,419 | 48,340 |
Liabilities from risk management activities (Note 7) | 1,512 | 7,557 |
Liabilities for asset retirements (Note 16) | 15,646 | 15,586 |
Operating lease liabilities (Note 15) | 128,673 | 74,785 |
Regulatory liabilities (Note 4) | 327,612 | 229,088 |
Other current liabilities | 140,038 | 187,448 |
Total current liabilities | 2,023,268 | 1,360,433 |
Long-term debt less current maturities (Note 3) | 6,315,927 | 6,314,266 |
DEFERRED CREDITS AND OTHER | ||
Deferred income taxes | 2,192,169 | 2,135,403 |
Regulatory liabilities (Note 4) | 2,443,312 | 2,450,169 |
Liabilities for asset retirements (Note 16) | 716,344 | 689,497 |
Liabilities for pension benefits (Note 5) | 163,207 | 166,484 |
Liabilities from risk management activities (Note 7) | 0 | 11,062 |
Customer advances | 247,531 | 221,032 |
Coal mine reclamation | 172,357 | 170,097 |
Deferred investment tax credit | 187,720 | 191,372 |
Unrecognized tax benefits | 6,002 | 5,834 |
Operating lease liabilities (Note 15) | 547,164 | 361,336 |
Other | 211,678 | 190,643 |
Total deferred credits and other | 6,887,484 | 6,592,929 |
COMMITMENTS AND CONTINGENCIES (NOTE 8) | ||
EQUITY | ||
Common stock, no par value; authorized 150,000,000 shares, 112,819,703 and 112,760,051 issued at respective dates | 2,692,015 | 2,677,482 |
Treasury stock at cost; 36,153 and 72,006 shares at respective dates | (3,079) | (6,289) |
Total common stock | 2,688,936 | 2,671,193 |
Retained earnings | 3,089,266 | 3,025,106 |
Accumulated other comprehensive loss | (60,578) | (62,796) |
Total shareholders’ equity | 5,717,624 | 5,633,503 |
Noncontrolling interests (Note 6) | 117,275 | 119,290 |
Total equity | 5,834,899 | 5,752,793 |
TOTAL LIABILITIES AND EQUITY | 21,061,578 | 20,020,421 |
APS | ||
CURRENT ASSETS | ||
Cash and cash equivalents | 11,954 | 57,310 |
Customer and other receivables | 357,023 | 312,644 |
Accrued unbilled revenues | 223,918 | 132,197 |
Allowance for doubtful accounts (Note 2) | (22,769) | (19,782) |
Materials and supplies (at average cost) | 340,672 | 314,745 |
Fossil fuel (at average cost) | 25,074 | 19,552 |
Assets from risk management activities (Note 7) | 82,309 | 2,931 |
Deferred fuel and purchased power regulatory asset (Note 4) | 300,912 | 175,835 |
Other regulatory assets (Note 4) | 119,890 | 115,878 |
Other current assets | 51,482 | 47,593 |
Total current assets | 1,490,465 | 1,158,903 |
INVESTMENTS AND OTHER ASSETS | ||
Nuclear decommissioning trusts (Notes 11 and 12) | 1,223,088 | 1,138,435 |
Other special use funds (Notes 11 and 12) | 358,436 | 254,509 |
Other assets | 68,248 | 46,010 |
Total investments and other assets | 1,649,772 | 1,438,954 |
PROPERTY, PLANT AND EQUIPMENT | ||
Plant in service and held for future use | 21,233,344 | 20,834,424 |
Accumulated depreciation and amortization | (7,275,617) | (7,107,058) |
Net | 13,957,727 | 13,727,366 |
Construction work in progress | 1,062,911 | 937,384 |
Palo Verde sale leaseback, net of accumulated depreciation (Note 6) | 96,101 | 98,036 |
Intangible assets, net of accumulated amortization | 279,755 | 282,415 |
Nuclear fuel, net of accumulated amortization | 109,110 | 113,645 |
Total property, plant and equipment | 15,505,604 | 15,158,846 |
DEFERRED DEBITS | ||
Regulatory assets (Note 4) | 1,173,977 | 1,133,987 |
Operating lease right-of-use assets (Note 15) | 717,411 | 503,475 |
Assets for pension and other postretirement benefits (Note 5) | 400,414 | 495,673 |
Other | 37,210 | 34,413 |
Total deferred debits | 2,329,012 | 2,167,548 |
TOTAL ASSETS | 20,974,853 | 19,924,251 |
CURRENT LIABILITIES | ||
Accounts payable | 369,905 | 311,699 |
Accrued taxes | 193,409 | 148,970 |
Accrued interest | 56,202 | 56,322 |
Common dividends payable | 93,500 | 93,500 |
Short-term borrowings (Note 3) | 495,000 | 0 |
Customer deposits | 44,419 | 48,340 |
Liabilities from risk management activities (Note 7) | 1,512 | 7,557 |
Liabilities for asset retirements (Note 16) | 15,646 | 15,586 |
Operating lease liabilities (Note 15) | 128,578 | 74,695 |
Regulatory liabilities (Note 4) | 327,612 | 229,088 |
Other current liabilities | 142,926 | 190,420 |
Total current liabilities | 1,868,709 | 1,176,177 |
Long-term debt less current maturities (Note 3) | 5,819,198 | 5,817,945 |
DEFERRED CREDITS AND OTHER | ||
Deferred income taxes | 2,192,580 | 2,143,673 |
Regulatory liabilities (Note 4) | 2,443,312 | 2,450,169 |
Liabilities for asset retirements (Note 16) | 716,344 | 689,497 |
Liabilities for pension benefits (Note 5) | 146,728 | 148,943 |
Liabilities from risk management activities (Note 7) | 0 | 11,062 |
Customer advances | 247,531 | 221,032 |
Coal mine reclamation | 172,357 | 170,097 |
Deferred investment tax credit | 187,720 | 191,372 |
Unrecognized tax benefits | 39,995 | 39,410 |
Operating lease liabilities (Note 15) | 545,534 | 359,653 |
Other | 182,555 | 160,036 |
Total deferred credits and other | 6,874,656 | 6,584,944 |
COMMITMENTS AND CONTINGENCIES (NOTE 8) | ||
EQUITY | ||
Common stock | 178,162 | 178,162 |
Additional paid-in capital | 2,871,696 | 2,871,696 |
Retained earnings | 3,284,989 | 3,216,955 |
Accumulated other comprehensive loss | (39,832) | (40,918) |
Total shareholders’ equity | 6,295,015 | 6,225,895 |
Noncontrolling interests (Note 6) | 117,275 | 119,290 |
Total equity | 6,412,290 | 6,345,185 |
Total capitalization | 12,231,488 | 12,163,130 |
TOTAL LIABILITIES AND EQUITY | $ 20,974,853 | $ 19,924,251 |
CONDENSED CONSOLIDATED BALANC_2
CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares | Jun. 30, 2021 | Dec. 31, 2020 |
EQUITY | ||
Common stock, authorized shares (in shares) | 150,000,000 | 150,000,000 |
Common stock, issued shares (in shares) | 112,819,703 | 112,760,051 |
Treasury stock at cost, shares (in shares) | 36,153 | 72,006 |
CONDENSED CONSOLIDATED STATEM_4
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2021 | Jun. 30, 2020 | |
CASH FLOWS FROM OPERATING ACTIVITIES | ||
Net Income | $ 259,950 | $ 233,325 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation and amortization including nuclear fuel | 350,536 | 343,173 |
Deferred fuel and purchased power | (135,905) | (26,473) |
Deferred fuel and purchased power amortization | 10,828 | (4,815) |
Allowance for equity funds used during construction | (19,197) | (16,508) |
Deferred income taxes | 30,231 | 22,229 |
Deferred investment tax credit | (3,651) | (3,386) |
Stock compensation | 13,484 | 9,130 |
Changes in current assets and liabilities: | ||
Customer and other receivables | (41,138) | 7,767 |
Accrued unbilled revenues | (91,721) | (63,413) |
Materials, supplies and fossil fuel | (31,449) | 10,295 |
Income tax receivable | 6,792 | 4,605 |
Other current assets | (14,021) | (24,896) |
Accounts payable | 66,558 | 17,772 |
Accrued taxes | 23,486 | 6,588 |
Other current liabilities | (39,638) | (45,334) |
Change in other long-term assets | (118,036) | (4,885) |
Change in other long-term liabilities | 45,241 | (96,142) |
Net cash flow provided by operating activities | 312,350 | 369,032 |
CASH FLOWS FROM INVESTING ACTIVITIES | ||
Capital expenditures | (681,148) | (676,973) |
Contributions in aid of construction | 32,104 | 31,295 |
Allowance for borrowed funds used during construction | (10,193) | (8,825) |
Proceeds from nuclear decommissioning trusts sales and other special use funds | 587,842 | 391,859 |
Investment in nuclear decommissioning trusts and other special use funds | (588,982) | (393,000) |
Other | 10,809 | 3,123 |
Net cash flow used for investing activities | (649,568) | (652,521) |
CASH FLOWS FROM FINANCING ACTIVITIES | ||
Issuance of long-term debt | 150,000 | 1,088,886 |
Short-term borrowing and (repayments) — net | 354,700 | 184,225 |
Short-term debt borrowings under revolving credit facility | 0 | 751,690 |
Short-term debt repayments under revolving credit facility | (19,000) | (758,690) |
Dividends paid on common stock | (183,500) | (172,566) |
Repayment of long-term debt | 0 | (800,000) |
Common stock equity issuance — net of purchases | (176) | (2,204) |
Distributions to noncontrolling interests | (10,628) | (11,372) |
Net cash flow provided by financing activities | 291,396 | 279,969 |
NET DECREASE IN CASH AND CASH EQUIVALENTS | (45,822) | (3,520) |
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD | 59,968 | 10,283 |
CASH AND CASH EQUIVALENTS AT END OF PERIOD | 14,146 | 6,763 |
APS | ||
CASH FLOWS FROM OPERATING ACTIVITIES | ||
Net Income | 263,647 | 242,210 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation and amortization including nuclear fuel | 350,494 | 343,130 |
Deferred fuel and purchased power | (135,905) | (26,473) |
Deferred fuel and purchased power amortization | 10,828 | (4,815) |
Allowance for equity funds used during construction | (19,197) | (16,508) |
Deferred income taxes | 23,161 | 15,233 |
Deferred investment tax credit | (3,651) | (3,386) |
Changes in current assets and liabilities: | ||
Customer and other receivables | (41,963) | 824 |
Accrued unbilled revenues | (91,721) | (63,413) |
Materials, supplies and fossil fuel | (31,449) | 10,295 |
Income tax receivable | 0 | 7,313 |
Other current assets | (12,636) | (19,752) |
Accounts payable | 66,192 | 17,915 |
Accrued taxes | 44,439 | 14,551 |
Other current liabilities | (39,749) | (40,381) |
Change in other long-term assets | (114,154) | (7,356) |
Change in other long-term liabilities | 46,327 | (91,983) |
Net cash flow provided by operating activities | 314,663 | 377,404 |
CASH FLOWS FROM INVESTING ACTIVITIES | ||
Capital expenditures | (681,148) | (676,973) |
Contributions in aid of construction | 32,104 | 31,295 |
Allowance for borrowed funds used during construction | (10,193) | (8,825) |
Proceeds from nuclear decommissioning trusts sales and other special use funds | 587,842 | 391,859 |
Investment in nuclear decommissioning trusts and other special use funds | (588,982) | (393,000) |
Other | 2,986 | (169) |
Net cash flow used for investing activities | (657,391) | (655,813) |
CASH FLOWS FROM FINANCING ACTIVITIES | ||
Issuance of long-term debt | 0 | 591,936 |
Short-term borrowing and (repayments) — net | 495,000 | 219,900 |
Short-term debt borrowings under revolving credit facility | 0 | 540,000 |
Short-term debt repayments under revolving credit facility | 0 | (540,000) |
Dividends paid on common stock | (187,000) | (176,000) |
Repayment of long-term debt | 0 | (350,000) |
Distributions to noncontrolling interests | (10,628) | (11,372) |
Net cash flow provided by financing activities | 297,372 | 274,464 |
NET DECREASE IN CASH AND CASH EQUIVALENTS | (45,356) | (3,945) |
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD | 57,310 | 10,169 |
CASH AND CASH EQUIVALENTS AT END OF PERIOD | $ 11,954 | $ 6,224 |
CONDENSED CONSOLIDATED STATEM_5
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($) $ in Thousands | Total | Common Stock | Treasury Stock | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Noncontrolling Interests | APS | APSCommon Stock | APSAdditional Paid-In Capital | APSRetained Earnings | APSAccumulated Other Comprehensive Income (Loss) | APSNoncontrolling Interests | |
Beginning balance (in shares) at Dec. 31, 2019 | 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 | 233,325 | 223,578 | 9,747 | 242,210 | 232,463 | 9,747 | |||||||
Other comprehensive income (loss) | (779) | (779) | 497 | 497 | |||||||||
Dividends on common stock | (176,079) | (176,079) | (176,000) | (176,000) | |||||||||
Issuance of common stock (in shares) | 50,998 | ||||||||||||
Issuance of common stock | 5,957 | $ 5,957 | |||||||||||
Purchase of treasury stock (in shares) | [1] | (33,070) | |||||||||||
Purchase of treasury stock | [1] | (3,010) | $ (3,010) | ||||||||||
Reissuance of treasury stock for stock-based compensation and other (in shares) | 100,633 | ||||||||||||
Reissuance of treasury stock for stock-based compensation and other | 9,247 | $ 9,247 | |||||||||||
Other | (1) | (1) | |||||||||||
Capital activities by noncontrolling interests | (11,372) | (11,372) | (11,372) | (11,372) | |||||||||
Ending balance (in shares) at Jun. 30, 2020 | 112,591,124 | 35,983 | 71,264,947 | ||||||||||
Balance at end of period at Jun. 30, 2020 | 5,610,477 | $ 2,665,518 | $ (3,190) | 2,885,109 | (57,875) | 120,915 | 6,054,137 | $ 178,162 | 2,721,696 | 3,068,389 | (35,025) | 120,915 | |
Beginning balance (in shares) at Mar. 31, 2020 | 112,563,610 | 72,302 | 71,264,947 | ||||||||||
Balance at beginning 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 | |
Increase (Decrease) in Shareholders' Equity | |||||||||||||
Net Income | 198,459 | 193,585 | 4,874 | 201,992 | 197,118 | 4,874 | |||||||
Other comprehensive income (loss) | (2,296) | (2,296) | (828) | (828) | |||||||||
Dividends on common stock | (176,086) | (176,086) | (176,000) | (176,000) | |||||||||
Issuance of common stock (in shares) | 27,514 | ||||||||||||
Issuance of common stock | 1,131 | $ 1,131 | |||||||||||
Purchase of treasury stock (in shares) | [2] | (12,346) | |||||||||||
Purchase of treasury stock | [2] | (924) | $ (924) | ||||||||||
Reissuance of treasury stock for stock-based compensation and other (in shares) | 48,665 | ||||||||||||
Reissuance of treasury stock for stock-based compensation and other | 4,734 | $ 4,734 | |||||||||||
Other | (1) | (1) | 1 | 2 | (1) | ||||||||
Capital activities by noncontrolling interests | (11,372) | (11,372) | (11,372) | (11,372) | |||||||||
Ending balance (in shares) at Jun. 30, 2020 | 112,591,124 | 35,983 | 71,264,947 | ||||||||||
Balance at end of period at Jun. 30, 2020 | $ 5,610,477 | $ 2,665,518 | $ (3,190) | 2,885,109 | (57,875) | 120,915 | 6,054,137 | $ 178,162 | 2,721,696 | 3,068,389 | (35,025) | 120,915 | |
Beginning balance (in shares) at Dec. 31, 2020 | 112,760,051 | 112,760,051 | 72,006 | 71,264,947 | |||||||||
Balance at beginning of period at Dec. 31, 2020 | $ 5,752,793 | $ 2,677,482 | $ (6,289) | 3,025,106 | (62,796) | 119,290 | 6,345,185 | $ 178,162 | 2,871,696 | 3,216,955 | (40,918) | 119,290 | |
Increase (Decrease) in Shareholders' Equity | |||||||||||||
Net Income | 259,950 | 251,338 | 8,612 | 263,647 | 255,035 | 8,612 | |||||||
Other comprehensive income (loss) | 2,218 | 2,218 | 1,086 | 1,086 | |||||||||
Dividends on common stock | (187,176) | (187,176) | (187,000) | (187,000) | |||||||||
Issuance of common stock (in shares) | 59,652 | ||||||||||||
Issuance of common stock | 14,533 | $ 14,533 | |||||||||||
Purchase of treasury stock (in shares) | [1] | (17,437) | |||||||||||
Purchase of treasury stock | [1] | (1,333) | $ (1,333) | ||||||||||
Reissuance of treasury stock for stock-based compensation and other (in shares) | 53,290 | ||||||||||||
Reissuance of treasury stock for stock-based compensation and other | 4,543 | $ 4,543 | |||||||||||
Other | (1) | (2) | 1 | 0 | (1) | 1 | |||||||
Capital activities by noncontrolling interests | $ (10,628) | (10,628) | (10,628) | (10,628) | |||||||||
Ending balance (in shares) at Jun. 30, 2021 | 112,819,703 | 112,819,703 | 36,153 | 71,264,947 | |||||||||
Balance at end of period at Jun. 30, 2021 | $ 5,834,899 | $ 2,692,015 | $ (3,079) | 3,089,266 | (60,578) | 117,275 | 6,412,290 | $ 178,162 | 2,871,696 | 3,284,989 | (39,832) | 117,275 | |
Beginning balance (in shares) at Mar. 31, 2021 | 112,791,565 | 44,338 | 71,264,947 | ||||||||||
Balance at beginning of period at Mar. 31, 2021 | 5,806,680 | $ 2,687,052 | $ (3,776) | 3,060,752 | (61,512) | 124,164 | 6,386,275 | $ 178,162 | 2,871,696 | 3,252,244 | (39,991) | 124,164 | |
Increase (Decrease) in Shareholders' Equity | |||||||||||||
Net Income | 219,436 | 215,697 | 3,739 | 223,487 | 219,748 | 3,739 | |||||||
Other comprehensive income (loss) | 934 | 934 | 159 | 159 | |||||||||
Dividends on common stock | (187,181) | (187,181) | (187,000) | (187,000) | |||||||||
Issuance of common stock (in shares) | 28,138 | ||||||||||||
Issuance of common stock | 4,963 | $ 4,963 | |||||||||||
Reissuance of treasury stock for stock-based compensation and other (in shares) | 8,185 | ||||||||||||
Reissuance of treasury stock for stock-based compensation and other | 697 | $ 697 | |||||||||||
Other | (2) | (2) | (3) | (3) | |||||||||
Capital activities by noncontrolling interests | $ (10,628) | (10,628) | (10,628) | (10,628) | |||||||||
Ending balance (in shares) at Jun. 30, 2021 | 112,819,703 | 112,819,703 | 36,153 | 71,264,947 | |||||||||
Balance at end of period at Jun. 30, 2021 | $ 5,834,899 | $ 2,692,015 | $ (3,079) | $ 3,089,266 | $ (60,578) | $ 117,275 | $ 6,412,290 | $ 178,162 | $ 2,871,696 | $ 3,284,989 | $ (39,832) | $ 117,275 | |
[1] | Primarily represents shares of common stock withheld from certain stock awards for tax purposes. | ||||||||||||
[2] | Primarily represents shares of common stock withheld from certain stock awards for tax purposes. |
CONDENSED CONSOLIDATED STATEM_6
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Parenthetical) - $ / shares | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2021 | Jun. 30, 2020 | Jun. 30, 2021 | Jun. 30, 2020 | |
Statement of Stockholders' Equity [Abstract] | ||||
Dividends on common stock (in dollars per share) | $ 1.66 | $ 1.57 | $ 1.66 | $ 1.57 |
Consolidation and Nature of Ope
Consolidation and Nature of Operations | 6 Months Ended |
Jun. 30, 2021 | |
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 2020 Form 10-K. On June 30, 2020, the United States Federal Energy Regulatory Commission (“FERC”) issued an order granting a waiver request related to the existing Allowance for Funds Used During Construction (“AFUDC”) rate calculation beginning March 1, 2020 through February 28, 2021. On February 23, 2021, this waiver was extended until September 30, 2021. The order provides a simplified approach that companies may elect to implement in order to minimize the significant distorted effect on the AFUDC formula resulting from increased short-term debt financing during the COVID-19 pandemic. APS has adopted this simplified approach to computing the AFUDC composite rate by using a simple average of the actual historical short-term debt balances for 2019, instead of current period short-term debt balances, and has left all other aspects of the AFUDC formula composite rate calculation unchanged. This change impacts the AFUDC composite rate in both 2020 and 2021 but does not impact prior years. Furthermore, the change in the composite rate calculation does not impact our accounting treatment for these costs. The change will not have a material impact on our financial statements. See Note 1 in our 2020 Form 10-K for information on the accounting treatment for AFUDC. Supplemental Cash Flow Information The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands): Six Months Ended 2021 2020 Cash paid (received) during the period for: Income taxes, net of refunds $ (788) $ (3,028) Interest, net of amounts capitalized 112,010 107,417 Significant non-cash investing and financing activities: Accrued capital expenditures $ 105,515 $ 87,815 Dividends accrued but not yet paid 93,610 88,066 The following table summarizes supplemental APS cash flow information (dollars in thousands): Six Months Ended 2021 2020 Cash paid (received) during the period for: Income taxes, net of refunds $ 3,317 $ — Interest, net of amounts capitalized 107,044 100,991 Significant non-cash investing and financing activities: Accrued capital expenditures $ 105,515 $ 87,815 Dividends accrued but not yet paid 93,500 88,000 |
Revenue
Revenue | 6 Months Ended |
Jun. 30, 2021 | |
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 June 30, Six Months Ended June 30, 2021 2020 2021 2020 Retail Electric Revenue Residential $ 531,717 $ 515,128 $ 872,555 $ 840,201 Non-Residential 420,995 381,121 735,778 684,472 Wholesale Energy Sales 18,007 15,927 35,604 30,595 Transmission Services for Others 22,579 14,766 41,572 30,693 Other Sources 6,951 2,648 11,215 5,559 Total operating revenues $ 1,000,249 $ 929,590 $ 1,696,724 $ 1,591,520 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. See “Allowance for Doubtful Accounts” discussion below for additional details regarding payment terms. Wholesale Energy Sales and Transmission Services for Others. Revenues from wholesale energy sales and transmission services for others represent energy and transmission sales to wholesale customers. These activities primarily consist of managing fuel and purchased power risks in connection with the cost of serving our retail customers’ energy requirements. We may also sell into the wholesale markets generation that is not needed for APS’s retail load. Our wholesale activities and tariff rates are regulated by FERC. In the electricity business, some contracts to purchase energy are settled by netting against other contracts to sell electricity. This is referred to as a book-out, and usually occurs in contracts that have the same terms (product type, quantities, and delivery points) and for which power does not flow. We 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 and six months ended June 30, 2021 were $980 million and $1,663 million, respectively and for the three and six months ended June 30, 2020 were $915 million and $1,563 million, respectively. We have certain revenues that do not meet the specific accounting criteria to be classified as revenues from contracts with customers. For the three and six months ended June 30, 2021 our revenues that do not qualify as revenue from contracts with customers were $20 million and $34 million, respectively, and for the three and six months ended June 30, 2020 were $15 million and $29 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 June 30, 2021 or December 31, 2020. Allowance for Doubtful Accounts The allowance for doubtful accounts represents our best estimate of accounts receivable and accrued unbilled revenues that will ultimately be uncollectible due to credit loss risk. The allowance includes a write-off component that is calculated by applying an estimated write-off factor to retail electric revenues. The write-off factor used to estimate uncollectible accounts is based upon consideration of historical collections experience, the current and forecasted economic environment, changes to our collection policies, and management’s best estimate of future collections success. On March 13, 2020, due to the COVID-19 pandemic we voluntarily suspended disconnections of customers for nonpayment. The suspension of customer disconnections was extended from March 13, 2020 through December 31, 2020. The suspension of disconnection of customers for nonpayment ended on January 1, 2021 and certain customers with past due balances were placed on eight-month payment arrangements. During this time our disconnection policies were also impacted by the Summer Disconnection Moratorium. These circumstances and the on-going COVID-19 pandemic have impacted our allowance for doubtful accounts, including our write-off factor. We continue to monitor the impacts of COVID-19, our disconnection policies, payment arrangements, among other considerations impacting our estimated write-off factor and allowance for doubtful accounts. See Note 4 for additional details. The following table provides a rollforward of Pinnacle West’s allowance for doubtful accounts (dollars in thousands): June 30, 2021 December 31, 2020 Allowance for doubtful accounts, balance at beginning of period $ 19,782 $ 8,171 Bad debt expense 10,048 20,633 Actual write-offs (7,061) (9,022) Allowance for doubtful accounts, balance at end of period $ 22,769 $ 19,782 |
Long-Term Debt and Liquidity Ma
Long-Term Debt and Liquidity Matters | 6 Months Ended |
Jun. 30, 2021 | |
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 On May 5, 2020, Pinnacle West refinanced its 364-day $50 million term loan agreement with a new 364-day $31 million term loan agreement that would have matured May 4, 2021. Borrowings under the agreement bore interest at Eurodollar Rate plus 1.40% per annum. Pinnacle West repaid this agreement on April 27, 2021. On December 23, 2020, Pinnacle West entered into a $150 million term loan facility that matures June 30, 2022. The proceeds were received on January 4, 2021 and used for general corporate purposes. On May 28, 2021, Pinnacle West replaced its $200 million revolving credit facility that would have matured on July 11, 2023, with a new $200 million revolving credit facility that matures on May 28, 2026. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on Pinnacle West’s senior unsecured debt credit ratings and the agreement includes a sustainability-linked pricing metric which permits an interest rate reduction or increase by meeting or missing targets related to specific environmental and employee health and safety sustainability objectives. The facility is available to support Pinnacle West’s general corporate purposes, including support for Pinnacle West's $200 million commercial paper program, for bank borrowings or for issuances of letters of credits. At June 30, 2021, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding under the credit facility and $9.7 million of outstanding commercial paper borrowings. APS On May 28, 2021, APS replaced its two $500 million revolving credit facilities that would have matured in June 2022 and July 2023, with two new $500 million revolving credit facilities that total $1 billion and that mature on May 28, 2026. APS may increase the amount of each facility up to a maximum of $700 million, for a total of $1.4 billion, upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on APS’s senior unsecured debt credit ratings and the agreements include a sustainability-linked pricing metric which permits an interest rate reduction or increase by meeting or missing targets related to specific environmental and employee health and safety sustainability objectives. These facilities are available to support APS’s general corporate purposes, including support for APS's $750 million commercial paper program, for bank borrowings or for issuances of letters of credit. At June 30, 2021, APS had no outstanding borrowings under its revolving credit facilities, no letters of credit outstanding under the credit facilities and $495 million of outstanding commercial paper borrowings. On December 17, 2020, the ACC issued a financing order in which, subject to specified parameters and procedures, it approved APS’s short-term debt authorization equal to the sum of (i) 7% of APS’s capitalization, and (ii) $500 million (which is required to be used for costs relating to purchases of natural gas and power) and a long-term debt authorization of $7.5 billion. 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 June 30, 2021 As of December 31, 2020 Carrying Fair Value Carrying Fair Value Pinnacle West $ 646,729 $ 654,095 $ 496,321 $ 509,050 APS 5,819,198 6,746,984 5,817,945 7,103,791 Total $ 6,465,927 $ 7,401,079 $ 6,314,266 $ 7,612,841 |
Regulatory Matters
Regulatory Matters | 6 Months Ended |
Jun. 30, 2021 | |
Regulated Operations [Abstract] | |
Regulatory Matters | Regulatory Matters COVID-19 Pandemic Due to the COVID-19 pandemic, APS voluntarily suspended disconnections of customers for nonpayment and waived late payment fees beginning March 13, 2020 until December 31, 2020. The suspension of disconnection of customers for nonpayment ended on January 1, 2021 and customers were automatically placed on eight-month payment arrangements if they had past due balances at the end of the disconnection period of $75 or greater. APS will continue to waive late payment fees until October 15, 2021. APS has experienced and is continuing to experience an increase in bad debt expense associated with the COVID-19 pandemic, the Summer Disconnection Moratorium (defined below) and the related write-offs of customer delinquent accounts. In February 2021, due to COVID-19 APS delayed the annual reset of the PSA. Rather than the increase being effective February 2021, the PSA reset was implemented with 50% of the increase effective April 2021 and the remaining 50% increase effective November 2021 (see below for discussion of EIS, TEAM Phase II and PSA). On April 17, 2020, APS filed an application with the ACC requesting a COVID-19 emergency relief package to provide additional assistance to its customers. On May 5, 2020, the ACC approved APS returning $36 million that had been collected through the Demand Side Management (“DSM”) Adjustor Charge, but not allocated for current DSM programs, directly to customers through a bill credit in June 2020. APS has refunded approximately $43 million to customers. The additional $7 million over the approved amount of $36 million was the result of the kWh credit being based on historic consumption, which was different than actual consumption in the refund p eriod. The difference was recorded to the DSM balancing account and was included in the 2021 DSM Implementation Plan, which was approved by the ACC on June 13, 2021 (see below for discussion of the DSM Adjustor Charge). In 2020, APS spent more than $15 million to assist customers and local non-profits and community organizations to help with the impact of the COVID-19 pandemic, with $12.4 million of these dollars directly committed to bill assistance programs (the “COVID Customer Support Fund”). The COVID Customer Support Fund was comprised of a series of voluntary commitments of funds that are not recoverable through rates throughout 2020 of approximately $8.8 million. An additional $3.6 million in bill credits for limited income customers was ordered by the ACC in December 2020 of which 50%, up to a maximum of $2.5 million, was committed to be funds that are not recoverable through rates with the remaining being deferred for potential future recovery in rates. Included in the COVID Customer Support Fund were programs that assisted customers that had a delinquency of two or more months with a one-time credit of $100, an expanded credit of $300 for limited income customers, programs to assist extra small and small non-residential customers with a one-time credit of $1,000, and other targeted programs allocated to assist with other COVID-19 needs in support of utility bill assistance. The December 2020 ACC order further assisted delinquent limited income customers with an additional bill credit of up to $250 or their delinquent balance, whichever was less. APS has distributed all funds for all COVID Customer Support Fund programs combined. Beyond the COVID Customer Support Fund, APS has also provided $2.7 million to assist local non-profits and community organizations working to mitigate the impacts of the COVID-19 pandemic. 2019 Retail Rate Case Filing with the Arizona Corporation Commission In accordance with the requirements of the 2019 rate review order described below, APS filed an application with the ACC on October 31, 2019 seeking an increase in annual retail base rates of $69 million. This amount includes recovery of the deferral and rate base effects of the Four Corners selective catalytic reduction (“SCR”) project that 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 annual 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 were: • a test year comprised of twelve months ended June 30, 2019, adjusted as described below; • an original cost rate base of $8.87 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits; • the following proposed capital structure and costs of capital: Capital Structure Cost of Capital Long-term debt 45.3 % 4.10 % Common stock equity 54.7 % 10.15 % Weighted-average cost of capital 7.41 % • a 1% return on the increment of fair value rate base above APS’s original cost rate base, as provided for by Arizona law; • a rate of $0.030168 per kWh for the portion of APS’s retail base rates attributable to fuel and purchased power costs (“Base Fuel Rate”); • authorization to defer until APS’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). On October 2, 2020, the ACC Staff, the Residential Utility Consumer Office (“RUCO”) and other intervenors filed their initial written testimony with the ACC in this rate case. The ACC Staff recommends, among other things, a (i) $89.7 million revenue increase, (ii) average annual customer bill increase of 2.7%, (iii) return on equity of 9.4%, (iv) a 0.3% or, as an alternative, a 0% return on the increment of fair value rate base greater than original cost , (v) recovery of the deferral and rate base effects of the construction and operating costs of the Four Corners SCR project and (vi) recovery of the rate base effects of the construction and ongoing consideration of the deferral of the Ocotillo modernization project. RUCO recommends, among other things, a (i) $20.8 million revenue decrease, (ii) average annual customer bill decrease of 0.63%, (iii) return on equity of 8.74%, (iv) a 0% return on the increment of fair value rate base, (v) nonrecovery of the deferral and rate base effects of the construction and operating costs of the Four Corners SCR project pending further consideration, and (vi) recovery of the deferral and rate base effects of the construction and operating costs of the Ocotillo modernization project. Upon conclusion of APS's rate case and the completion of the deferral mechanisms, approximately $110 million of on-going operating costs related to the Four Corners SCR project and the Ocotillo modernization project will start to be reflected on APS’s income statement. The filed ACC Staff and intervenor testimony include additional recommendations, some of which materially differ from APS’s filed application. On November 6, 2020, APS filed its rebuttal testimony and the principal provisions which differ from its initial application include, among other things, a (i) $169 million revenue increase, (ii) average annual customer bill increase of 5.14%, (iii) return on equity of 10%, (iv) return on the increment of fair value rate base of 0.8%, (v) new cost recovery adjustor mechanism, the Advanced Energy Mechanism (“AEM”), to enable more timely recovery of clean investments as APS pursues its clean energy commitment, (vi) recognition that securitization is a potentially useful financing tool to recover the remaining book value of retiring assets and effectuate a transition to a cleaner energy future that APS intends to pursue, provided legislative hurdles are addressed, and (vii) a Coal Community Transition (“CCT”) plan related to the closure or future closure of coal-fired generation facilities, of which $25 million would be funds that are not recoverable through rates with a proposal that the remainder be funded by customers over 10 years. The CCT plan includes the following proposed components: (i) $100 million that will be paid over 10 years to the Navajo Nation for a sustainable transition to a post-coal economy, which would be funded by customers, (ii) $1.25 million that will be paid over five years to the Navajo Nation to fund an economic development organization, which would be funds not recoverable through rates, (iii) $10 million to facilitate electrification projects within the Navajo Nation, which would be funded equally by funds not recoverable through rates and by customers, (iv) $2.5 million per year in transmission revenue sharing to be paid to the Navajo Nation beginning after the closure of the Four Corners Power Plant through 2038, which would be funds not recoverable through rates, (v) $12 million that will be paid over five years to the Navajo County Communities surrounding Cholla Power Plant, which would primarily be funded by customers, and (vi) $3.7 million that will be paid over five years to the Hopi Tribe related to APS’s ownership interests in the Navajo Generating Station, which would primarily be funded by customers. The commitment of funds that would not be recoverable through rates of $25 million were recognized in our December 31, 2020 financials. On December 4, 2020, the ACC Staff and intervenors filed surrebuttal testimony. The ACC Staff reduced its recommended rate increase to $59.8 million, or an average annual customer bill increase of 1.82%. In RUCO’s surrebuttal, the recommended revenue decrease changed to $50.1 million, or an average annual customer bill decrease of 1.52%. The hearing concluded on March 3, 2021 and the post-hearing briefing schedule concluded on April 30, 2021. In May 2021, the ACC declined to re-open the evidentiary record in APS’s pending rate case to take additional evidence on topics raised by certain ACC Commissioners, including adjustor cost recovery mechanisms. On August 2, 2021, the Administrative Law Judge issued a Recommended Opinion and Order in APS’s rate case (the “2019 Rate Case ROO”). The 2019 Rate Case ROO recommends, among other things, a (i) $111 million base revenue decrease, (ii) return on equity for original cost rate base of 9.16%, (iii) a 0.15% return on the increment of fair value rate base greater than original cost, with total fair value rate of return further adjusted to include a 0.10% reduction to return on equity resulting in an effective fair value return of 0.05%, (iv) nonrecovery of the deferral and rate base effects of the operating costs and construction of the Four Corners SCR project (see "Four Corners SCR Cost Recovery" below for additional in formation), (v) recovery of the deferral and rate base effects of the operating costs and construction of the Ocotillo modernization project, which includes a reduction in the return on the deferral and (vi) a 15% disallowance of annual amortization of Navajo Plant regulatory asset recovery. The 2019 Rate Case ROO also recommended that the CCT plan include the following components: (i) $50 million that will be paid over 10 years to the Navajo Nation, (ii) $5 million that will be paid over five years to the Navajo County Communities surrounding Cholla Power Plant, and (iii) $1.675 million that will be paid to the Hopi Tribe related to APS’s ownership interests in the Navajo Generating Station. These amounts would be recoverable from APS’s customers through the RES. APS expects to file an exception regarding the disallowance of the SCR cost deferrals and plant investments that was recommended in the 2019 Rate Case ROO and APS is continuing to evaluate any additional exceptions it may file. The 2019 Rate Case ROO will be discussed at an upcoming ACC open meeting. APS cannot predict the outcome of this proceeding. 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, RUCO, limited income advocates and private rooftop solar organizations signed a settlement agreement (the “2017 Settlement Agreement”) and filed it with the ACC. The 2017 Settlement Agreement provides for a net retail base rate increase of $94.6 million, excluding the transfer of adjustor balances, consisting of: (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 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 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. See “Rate Plan Comparison Tool and Investigation” below for information regarding a review and investigation pertaining to the rate plan comparison tool offered to APS customers and other related issues. ACC Review of APS 2017 Rate Case Decision On December 24, 2018, certain ACC Commissioners filed a letter stating that because the ACC had received a substantial number of complaints that the rate increase authorized by the 2017 Rate Case Decision was much more than anticipated, they believe there is a possibility that APS is earning more than was authorized by the 2017 Rate Case Decision. Accordingly, the ACC Commissioners requested the ACC Staff to perform a rate review of APS using calendar year 2018 as a test year. The ACC Commissioners also asked the ACC Staff to evaluate APS’s efforts to educate its customers regarding the new rates approved in the 2017 Rate Case Decision. On June 4, 2019, the ACC Staff filed a proposed order regarding the rate review of the 2017 Rate Case Decision. On June 11, 2019, the ACC Commissioners approved the proposed ACC Staff order with amendments. The key provisions of the amended order include the following: • APS must file a rate case no later than October 31, 2019, using a June 30, 2019 test year; • 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 filed its rate case on October 31, 2019 (see “2019 Retail Rate Case Filing with the Arizona Corporation Commission” above for more information). APS does not believe that the implementation of the other key provisions of the amended order regarding the rate review will have a material impact on its financial position, results of operations or cash flows. On May 19, 2020, the ACC Staff filed a third-party consultant’s report which evaluated the effectiveness of APS’s customer outreach and education program related to the 2017 Rate Case Decision. On May 29, 2020, the Chairman of the ACC filed a letter with the ACC in response to this report and is alleging that APS is out of compliance with the 2017 Rate Case Decision and is over-earning. The Chairman proposed that the current rates should be classified as interim rates and customers held harmless if APS’s activities have caused the rates set in the 2017 Rate Case Decision to not be just and reasonable. Also, on May 29, 2020, a second commissioner filed a letter with the ACC agreeing with the Chairman’s assertions and further asserting that the 2017 Rate Case Decision should be re-opened. On June 18, 2020, at an ACC Open Meeting, the matters raised in these letters were discussed. The ACC did not vote to move forward with any adjustments to APS’s current rates. On November 4, 2020, the ACC voted to administratively close this docket. Cost Recovery Mechanisms APS has received regulatory decisions that allow for more timely recovery of certain costs outside of a general retail rate case through the following recovery mechanisms. Renewable Energy Standard . In 2006, the ACC approved the RES. Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies. In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects. Each year APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget. In 2015, the ACC revised the 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 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. On September 23, 2020, the ACC approved the 2020 RES Implementation Plan, including a waiver of the residential distributed energy requirements for the 2020 implementation year. In addition, the ACC approved the implementation of a new pilot program that incentivizes Arizona households to install at-home battery systems. Recovery of the costs associated with the pilot will be addressed in the 2021 Demand Side Management Implementation Plan (“DSM Plan”). On July 1, 2020, APS filed its 2021 RES Implementation Plan and proposed a budget of approximately $84.7 million. APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the residential distributed energy requirement for 2021 contained in the RES rules. In the 2021 RES Implementation Plan, APS requested $4.5 million to meet revenue requirements associated with the APS Solar Communities program to complete installations delayed as a result of the COVID-19 pandemic in 2020. On June 7, 2021, the ACC approved the 2021 RES Implementation Plan including a waiver of the residential distributed energy requirements for the 2021 implementation year. As part of the approval, the ACC authorized APS to collect $68.3 million through the Renewable Energy Adjustment Charge to support APS's RES programs. On May 21, 2021, the ACC adopted a clean energy rules package which would require APS to meet certain clean energy standards and technology procurement mandates, obtain approval for its action plan included in its IRP, and seek cost recovery in a rate process. The adopted rules included substantial changes since the original Recommended Opinion and Order, and thus will require supplemental rulemaking before taking effect. APS cannot predict the outcome of this matter. See “Energy Modernization Plan” below for more information. On July 1, 2021, APS filed its 2022 RES Implementation Plan and proposed a budget of approximately $93.1 million. APS’s budget proposal supports existing approved projects and commitments and requests a permanent waiver of the residential and non-residential distributed energy requirements for 2022 contained in the RES rules. The ACC has not yet ruled on the 2022 RES Implementation Plan. Demand Side Management Adjustor Charge . The ACC Electric Energy Efficiency Standards require APS to submit a 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 proposed 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 sought a requested budget of $52.6 million and requested a waiver of the Electric Energy Efficiency Standard for 2018. On November 14, 2017, APS filed an amended 2018 DSM Plan, which revised the allocations between budget items to address customer participation levels but kept the overall budget at $52.6 million. On December 31, 2018, APS filed its 2019 DSM Plan, which requested a budget of $34.1 million and focused on DSM strategies to better meet system and customer needs, such as peak demand reduction, load shifting, storage and electrification strategies. On December 31, 2019, APS filed its 2020 DSM Plan, which requested a budget of $51.9 million and continued APS’s focus on DSM strategies such as peak demand reduction, load shifting, storage and electrification strategies. The 2020 DSM Plan addressed all components of the pending 2018 and 2019 DSM plans, which enabled the ACC to review the 2020 DSM Plan only. On May 15, 2020, APS filed an amended 2020 DSM Plan to provide assistance to customers experiencing economic impacts of the COVID-19 pandemic. The amended 2020 DSM Plan requested the same budget amount of $51.9 million. On September 23, 2020, the ACC approved the amended 2020 DSM Plan. On April 17, 2020, APS filed an application with the ACC requesting a COVID-19 emergency relief package to provide additional assistance to its customers. On May 5, 2020, the ACC approved APS returning $36 million that had been collected through the DSM Adjustor Charge, but not allocated for current DSM programs, directly to customers through a bill credit in June 2020. APS has refunded approximately $43 million to customers. The additional $7 million over the approved amount was the result of the kWh credit being based on historic consumption which was different than actual consumption in the refund period. The difference was recorded to the DSM balancing account and was included in the 2021 DSM Implementation Plan, which was approved by the ACC on June 13, 2021. On December 31, 2020, APS filed its 2021 DSM Plan, which requested a budget of $63.7 million and continued APS’s focus on DSM strategies, such as peak demand reduction, load shifting, storage and electrification strategies, as well as enhanced assistance to customers impacted economically by COVID-19. On April 6, 2021, APS filed an amended 2021 DSM Plan that proposed an additional performance incentive for customers participating in the residential energy storage pilot approved in the 2020 RES Implementation Plan. On July 13, 2021, the ACC approved the amended 2021 DSM Plan. On April 20, 2021, APS filed a request to extend the June 1, 2021 deadline to file its 2022 DSM Plan until 120 days after the ACC has taken action on APS's amended 2021 DSM Plan. The ACC approved this request on June 8, 2021. 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 2021 and 2020 (dollars in thousands): Six Months Ended 2021 2020 Beginning balance $ 175,835 $ 70,137 Deferred fuel and purchased power costs — current period 135,905 26,473 Amounts (charged) refunded to customers (10,828) 4,815 Ending balance $ 300,912 $ 101,425 The PSA rate for the PSA year beginning February 1, 2019 was $0.001658 per kWh, as compared to the $0.004555 per kWh for the prior year. This rate was comprised of a forward component of $0.000536 per kWh and a historical component of $0.001122 per kWh. This represented a $0.002897 per kWh decrease compared to 2018. These rates went into effect as filed on February 1, 2019. On November 27, 2019, APS filed its PSA rate for the PSA year beginning February 1, 2020. 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 November 30, 2020, APS filed its PSA rate for the PSA year beginning February 1, 2021. That rate was $0.003544 per kWh and consisted of a forward component of $0.003434 per kWh and a historical component of $0.000110 per kWh. The 2021 PSA rate is a $0.004 per kWh increase, compared to the 2020 PSA year, which is the maximum permitted under the Plan of Administration for the PSA. This left $215.9 million of fuel and purchased power costs above this annual cap which will be reflected in future year resets of the PSA. These rates were to be effective on February 1, 2021 but APS delayed the effectiveness of these rates until the first billing cycle of April 2021 due to concerns of the impact on customers during COVID-19. In March 2021, the ACC voted to implement the 2021 PSA, with 50% of the rate increase effective in April 2021 and the remaining 50% of the increase effective in November 2021. The PSA rate implemented on April 1, 2021 was $0.001544 per kWh and consisted of a forward component of $(0.004444) per kWh and a historical component of $0.005988 per kWh. On November 1, 2021, the remaining increase will be implemented to a rate of $0.003544 per kWh and will consist of a forward component of $(0.004444) per kWh and a historical component of $0.007988 per kWh. As part of this approval, the ACC ordered ACC Staff to conduct a fuel and purchased power procurement audit, which is currently underway, to better understand the factors that contributed to the increase. APS cannot predict the outcome of this audit. On March 15, 2019, APS filed an application with the ACC requesting approval to recover the costs related to two energy storage power purchase tolling agreements through the PSA. On December 29, 2020, the ACC Staff filed its report and recommended the |
Retirement Plans and Other Post
Retirement Plans and Other Postretirement Benefits | 6 Months Ended |
Jun. 30, 2021 | |
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 other postretirement benefit plans for the employees of Pinnacle West and our subsidiaries. The other postretirement benefit plans include a group life and medical plan and a post-65 retiree health reimbursement arrangement (“HRA”). Pinnacle West uses a December 31 measurement date each year for its pension and other postretirement benefit plans. The market-related value of our plan assets is their fair value at the measurement date. Under the HRA, included in the other postretirement benefit plan, the Company provides a subsidy to retirees to defray the cost of a Medicare supplemental policy. In prior years, we had been assuming a 4.75% escalation of these benefits; however, actual escalation has been significantly less than this assumption. Accordingly, during 2020 and for future periods, the escalation assumption was reduced to 2.00%. This escalation factor assumption change, among other factors, resulted in an increase in the over-funded status of the other postretirement benefit plan as of December 31, 2020. As a result, on January 4, 2021, we initiated the transfer of approximately $106 million of assets from the other postretirement benefit plan into the Active Union Employee Medical Account. The Active Union Employee Medical Account is an existing trust account that holds assets restricted for paying active union employee medical costs (see Note 12). The transfer of other postretirement benefit plan assets into the Active Union Employee Medical Account permits access to approximately $106 million of assets for the sole purpose of paying active union employee medical benefits. This transfer of assets into the Active Union Employee Medical Account is consistent with the terms of a similar 2018 transaction. 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 Six Months Ended Three Months Ended Six Months Ended 2021 2020 2021 2020 2021 2020 2021 2020 Service cost — benefits earned during the period $ 14,939 $ 13,859 $ 30,618 $ 28,116 $ 4,341 $ 5,401 $ 8,898 $ 11,118 Non-service costs (credits): Interest cost on benefit obligation 24,614 29,522 49,283 59,283 4,095 6,417 8,257 12,929 Expected return on plan assets (50,706) (46,915) (101,314) (93,721) (10,361) (10,019) (20,722) (20,038) Amortization of: Prior service credit — — — — (9,427) (9,394) (18,854) (18,788) Net actuarial loss (gain) 3,989 8,295 7,974 17,306 (2,641) — (5,046) — Net periodic benefit cost/(benefit) $ (7,164) $ 4,761 $ (13,439) $ 10,984 $ (13,993) $ (7,595) $ (27,467) $ (14,779) Portion of cost/(benefit) charged to expense $ (8,614) $ 271 $ (16,625) $ 1,613 $ (9,608) $ (5,056) $ (19,136) $ (10,512) Contributions We have not made voluntary contributions to our pension plan year-to-date in 2021. The minimum required contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions up to $100 million in 2021 and zero in 2022 and 2023. We do not expect to make any contributions over this period to our other postretirement benefit plans. |
Palo Verde Sale Leaseback Varia
Palo Verde Sale Leaseback Variable Interest Entities | 6 Months Ended |
Jun. 30, 2021 | |
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. Prior to April 1, 2021, the lease terms allowed APS the right to retain the assets through 2023 under one lease and 2033 under the other two leases. On April 1, 2021, APS executed an amended lease agreement with one of the VIE lessor trust entities relating to the lease agreement with the term ending in 2023. The amendment extends the lease term for this lease through 2033 and changes the lease payment. As a result of this amendment, APS will now retain the assets through 2033 under all three lease agreements. APS will be required to make payments relating to the three leases in total of approximately $21 million annually for the period 2021 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 and six months ended June 30, 2021 of $4 million and $9 million, respectively, and for the three and six months ended June 30, 2020 of $5 million and $10 million, respectively, entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders is not impacted by the consolidation. Our Condensed Consolidated Balance Sheets at June 30, 2021 and December 31, 2020 include the following amounts relating to the VIEs (dollars in thousands): June 30, 2021 December 31, 2020 Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation $ 96,101 $ 98,036 Equity — Noncontrolling interests 117,275 119,290 Assets of the VIEs are restricted and may only be used for payment to the noncontrolling interest holders. These assets are reported on our condensed consolidated financial statements. APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the Nuclear Regulatory Commission (“NRC”) 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 $307 million beginning in 2021, and up to $501 million over the lease 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. |
Derivative Accounting
Derivative Accounting | 6 Months Ended |
Jun. 30, 2021 | |
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 natural gas. Derivative instruments that meet certain hedge accounting criteria may be designated as cash flow hedges and are used to limit our exposure to cash flow variability on forecasted transactions. The changes in market value of such instruments have a high correlation to price changes in the hedged transactions. Derivative instruments are also entered into for economic hedging purposes. While economic hedges may mitigate exposure to fluctuations in commodity prices, these instruments have not been designated as accounting hedges. Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our Condensed Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows. Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the balance sheets as an asset or liability and are measured at fair value. See Note 11 for a discussion of fair value measurements. Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery and the quantities represent those transacted in the normal course of business. Derivative instruments qualifying for the normal purchases and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below. 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. The following table shows the outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): Quantity Commodity Unit of Measure June 30, 2021 December 31, 2020 Power GWh 368 368 Gas Billion cubic feet 189 205 Gains and Losses from Derivative Instruments The following table provides information about APS’s gains and losses from derivative instruments in designated cash flow accounting hedging relationships (dollars in thousands): Financial Statement Location Three Months Ended Six Months Ended Commodity Contracts 2021 2020 2021 2020 Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a) Fuel and purchased power (b) $ — $ (349) $ — $ (763) (a) During the three and six months ended June 30, 2021 and 2020, 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 no amounts will be reclassified from accumulated OCI into income. For APS, the delivery period for all derivative instruments in designated cash flow accounting hedging relationships have lapsed. The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments (dollars in thousands): Financial Statement Location Three Months Ended Six Months Ended Commodity Contracts 2021 2020 2021 2020 Net Gain (Loss) Recognized in Income Fuel and purchased power (a) $ 95,116 $ (4,894) $ 121,975 $ (34,971) (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. These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities and other assets lines of our Condensed Consolidated Balance Sheets. As of June 30, 2021: Gross Recognized Derivatives (a) Amounts Net Recognized Derivatives Other (c) Amount Reported on Balance Sheets Current assets $ 83,677 $ (1,368) $ 82,309 $ — $ 82,309 Investments and other assets 27,305 — 27,305 — 27,305 Total assets 110,982 (1,368) 109,614 — 109,614 Current liabilities (1,595) 1,368 (227) (1,285) (1,512) Deferred credits and other — — — — — Total liabilities (1,595) 1,368 (227) (1,285) (1,512) Total $ 109,387 $ — $ 109,387 $ (1,285) $ 108,102 (a) All of our gross recognized derivative instruments were subject to master netting arrangements. (b) No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting. (c) Represents cash collateral that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions or collateral posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $1,285. As of December 31, 2020: Gross Recognized Derivatives (a) Amounts Net Recognized Derivatives Other (c) Amount Current assets $ 5,870 $ (2,939) $ 2,931 $ — $ 2,931 Investments and other assets 3,150 (1,332) 1,818 — 1,818 Total assets 9,020 (4,271) 4,749 — 4,749 Current liabilities (9,211) 2,939 (6,272) (1,285) (7,557) Deferred credits and other (12,394) 1,332 (11,062) — (11,062) Total liabilities (21,605) 4,271 (17,334) (1,285) (18,619) Total $ (12,585) $ — $ (12,585) $ (1,285) $ (13,870) (a) All of our gross recognized derivative instruments were subject to master netting arrangements. (b) No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting. (c) Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $1,285. Credit Risk and Credit Related Contingent Features We are exposed to losses in the event of nonperformance or nonpayment by counterparties and have risk management contracts with many counterparties. As of June 30, 2021, we have two counterparties for which our exposure represents approximately 35% of Pinnacle West’s $110 million of risk management assets. This exposure relates to master agreements with counterparties and both are rated as investment grade. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of our trading counterparties’ debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties. Certain of our derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross-default provisions, and adequate assurance provisions. Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions. For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s). The following table provides information about our derivative instruments that have credit-risk-related contingent features (dollars in thousands): June 30, 2021 Aggregate fair value of derivative instruments in a net liability position $ 1,595 Cash collateral posted — Additional cash collateral in the event credit-risk-related contingent features were fully triggered — We also have energy-related non-derivative instrument contracts with investment grade credit-related contingent features, which could also require us to post additional collateral of approximately $87 million if our debt credit ratings were to fall below investment grade. |
Commitments and Contingencies
Commitments and Contingencies | 6 Months Ended |
Jun. 30, 2021 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Palo Verde Generating Station Spent Nuclear Fuel and Waste Disposal On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a second breach of contract lawsuit against the United States Department of Energy (“DOE”) in the United States Court of Federal Claims (“Court of Federal Claims”). The lawsuit sought to recover damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste (“Standard Contract”) for failing to accept Palo Verde’s spent nuclear fuel and high level waste from January 1, 2007 through June 30, 2011, as it was required to do pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act. On August 18, 2014, APS and DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment by DOE to the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. In addition, the settlement agreement, as amended, provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2022. APS has submitted six claims pursuant to the terms of the August 18, 2014 settlement agreement, for six separate time periods during July 1, 2011 through June 30, 2019. The DOE has approved and paid $99.7 million for these claims (APS’s share is $29.0 million). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. In accordance with the 2017 Rate Case Decision, this regulatory liability is being refunded to customers (see Note 4). On November 2, 2020, APS filed its seventh claim pursuant to the terms of the August 18, 2014 settlement agreement in the amount of $12.2 million (APS’s share is $3.6 million). On March 15, 2021, the DOE approved a payment of $12.1 million (APS’s share is $3.5 million) and on April 16, 2021, APS received this payment. Nuclear Insurance Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act (“Price-Anderson Act”), which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial sources and an industry-wide retrospective payment plan. In accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident of up to approximately $13.5 billion per occurrence. Palo Verde maintains the maximum available nuclear liability insurance in the amount of $450 million, which is provided by American Nuclear Insurers (“ANI”). The remaining balance of approximately $13.1 billion of liability coverage is provided through a mandatory industry-wide retrospective premium program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be responsible for retrospective premiums. The maximum retrospective premium per reactor under the program for each nuclear liability incident is approximately $137.6 million, subject to a maximum annual premium of approximately $20.5 million per incident. Based on APS’s ownership interest in the three Palo Verde units, APS’s maximum retrospective premium per incident for all three units is approximately $120.1 million, with a maximum annual retrospective premium of approximately $17.9 million. The Palo Verde participants maintain insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.8 billion. APS has also secured accidental outage insurance for a sudden and unforeseen accidental outage of any of the three units. The property damage, decontamination, and accidental outage insurance are provided by Nuclear Electric Insurance Limited (“NEIL”). APS is subject to retrospective premium adjustments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount APS could incur under the current NEIL policies totals approximately $22.4 million for each retrospective premium assessment declared by NEIL’s Board of Directors due to losses. In addition, NEIL policies contain rating triggers that would result in APS providing approximately $63.3 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions, sublimits and exclusions. Contractual Obligations As of June 30, 2021, our fuel and purchased power commitments have increased from the information provided in our 2020 Form 10-K. The increase is primarily due to new purchased power and energy storage commitments of approximately $624 million. The majority of the changes relate to 2026 and thereafter. Other than the item described above, there have been no material changes, as of June 30, 2021, outside the normal course of business in contractual obligations from the information provided in our 2020 Form 10-K. See Note 3 for discussion regarding changes in our short-term and long-term debt obligations. See Note 6 for discussion regarding changes to our contractual obligations related to the Palo Verde sale leaseback transactions. Superfund-Related Matters The Comprehensive Environmental Response Compensation and Liability Act (“Superfund” or “CERCLA”) establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who released, generated, transported to or disposed of hazardous substances at a contaminated site are among the parties who are potentially responsible (“PRPs”). PRPs may be strictly, and often are jointly and severally, liable for clean-up. On September 3, 2003, EPA advised APS that EPA considers APS to be a PRP in the Motorola 52 nd Street Superfund Site, Operable Unit 3 (“OU3”) in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3. In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study (“RI/FS”). Based upon discussions between the OU3 working group parties and EPA, along with the results of recent technical analyses prepared by the OU3 working group to supplement the RI/FS for OU3, APS anticipates finalizing the RI/FS during the fourth quarter of 2021. We estimate that our costs related to this investigation and study will be approximately $3 million. We anticipate incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time expenditures related to this matter cannot be reasonably estimated. On August 6, 2013, the Roosevelt Irrigation District (“RID”) filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants. The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID. The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3. As part of a state governmental investigation into groundwater contamination in this area, on January 25, 2015, the Arizona Department of Environmental Quality (“ADEQ”) sent a letter to APS seeking information concerning the degree to which, if any, APS’s current and former ownership of these facilities may have contributed to groundwater contamination in this area. APS responded to ADEQ on May 4, 2015. On December 16, 2016, two RID environmental and engineering contractors filed an ancillary lawsuit for recovery of costs against APS and the other defendants in the RID litigation. That same day, another RID service provider filed an additional ancillary CERCLA lawsuit against certain of the defendants in the main RID litigation, but excluded APS and certain other parties as named defendants. Because the ancillary lawsuits concern past costs allegedly incurred by these RID vendors, which were ruled unrecoverable directly by RID in November of 2016, the additional lawsuits do not increase APS’s exposure or risk related to these matters. On April 5, 2018, RID and the defendants in that particular litigation executed a settlement agreement, fully resolving RID’s CERCLA claims concerning both past and future cost recovery. APS’s share of this settlement was immaterial. In addition, the two environmental and engineering vendors voluntarily dismissed their lawsuit against APS and the other named defendants without prejudice. An order to this effect was entered on April 17, 2018. With this disposition of the case, the vendors may file their lawsuit again in the future. On August 16, 2019, Maricopa County, one of the three direct defendants in the service provider lawsuit, filed a third-party complaint seeking contribution for its liability, if any, from APS and 28 other third-party defendants. We are unable to predict the outcome of these matters; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows. Arizona Attorney General Matter APS received civil investigative demands from the Attorney General seeking information pertaining to the rate plan comparison tool offered to APS customers and other related issues including implementation of rates from the 2017 Settlement Agreement and its Customer Education and Outreach Plan associated with the 2017 Settlement Agreement. APS fully cooperated with the Attorney General’s Office in this matter. On February 22, 2021 APS entered into a consent agreement with the Attorney General as a way to settle the matter. The settlement resulted in APS paying $24.75 million, $24 million of which is being returned to customers as restitution. Four Corners SCR Cost Recovery As part of APS's rate case filing in 2019, APS included recovery of the deferral and rate base effects of the Four Corners SCR project. On August 2, 2021, the 2019 Rate Case ROO recommended a disallowance of approximately $399 million of SCR plant investments and $61 million of SCR cost deferrals. The ACC has not issued a decision on this matter, but if the recommendation regarding the Four Corners SCR project in the 2019 Rate Case ROO is adopted and ordered by the ACC, APS would be required to record a write-off related to the SCR cost deferrals. As of June 30, 2021, the SCR cost deferral balance is approximately $75 million net of accumulated deferred income taxes. In addition, if the recommendation regarding the SCR plant investment disallowance in the 2019 Rate Case ROO is adopted and ordered by the ACC, the amount of any loss will be determined based on the value of the SCR plant investment assets at the time the disallowance is probable and estimable and could also be affected by other regulatory and legal considerations. As of June 30, 2021, the value of the SCR plant investments is approximately $320 million, net of accumulated deferred income taxes. If a disallowance of all or a portion of the SCR plant investments is determined to be estimable and probable, or if regulatory recovery of all or a portion of the deferred costs is determined to no longer be probable, it is reasonably possible that APS will recognize a material loss on the SCR investments and cost deferrals. F or the period ended June 30, 2021, based on the fact that the 2019 Rate Case ROO is not a final decision and that APS intends to file exceptions to the 2019 Rate Case ROO related to the recommended disallowance of SCR plant investments and cost deferrals, among other factors, APS has not recorded any adjustments to write-off or write-down the SCR plant investments or cost deferrals. T he pollution control assets are used and useful and are required to operate Four Corners and APS believes that these SCR investments were prudently incurred. APS cannot predict the final outcome of the decision on this matter nor reasonably estimate the amount of any potential loss. Environmental Matters APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions of both conventional pollutants and greenhouse gases, water quality, wastewater discharges, solid waste, hazardous waste, and coal combustion residuals (“CCRs”). These laws and regulations can change from time to time, imposing new obligations on APS resulting in increased capital, operating, and other costs. Associated capital expenditures or operating costs could be material. APS intends to seek recovery of any such environmental compliance costs through our rates but cannot predict whether it will obtain such recovery. The following proposed and final rules involve material compliance costs to APS. Regional Haze Rules. APS has received the final rulemaking imposing pollution control requirements on Four Corners. EPA required the plant to install pollution control equipment that constitutes best available retrofit technology (“BART”) to lessen the impacts of emissions on visibility surrounding the plant. In addition, EPA issued a final rule for Regional Haze compliance at Cholla that does not involve the installation of new pollution controls and that will replace an earlier BART determination for this facility. See below for details of the Cholla BART approval. Four Corners. Based on EPA’s final standards, APS’s 63% share of the cost of required controls for Four Corners Units 4 and 5 was approximately $400 million, which has been incurred. In addition, APS and El Paso Electric Company (“El Paso”) entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso’s 7% interest in Four Corners Units 4 and 5. 4CA purchased the El Paso interest on July 6, 2016. Navajo Transitional Energy Company, LLC (“NTEC”) purchased the interest from 4CA on July 3, 2018. See “Four Corners — 4CA Matter” below for a discussion of the NTEC purchase. The cost of the pollution controls related to the 7% interest is approximately $45 million, which was assumed by NTEC through its purchase of the 7% interest. Cholla . In early 2017, EPA approved a final rule containing a revision to Arizona’s State Implementation Plan (“SIP”) for Cholla that implemented BART requirements for this facility, which did not require the installation of any new pollution control capital improvements. In conjunction with the closure of Cholla Unit 2 in 2015, APS has committed to ceasing coal combustion within Units 1 and 3 by April 2025. PacifiCorp retired Cholla Unit 4 at the end of 2020. (See “Cholla” in Note 4 for information regarding future plans for Cholla and details related to the resulting regulatory asset). Coal Combustion Waste . On December 19, 2014, EPA issued its final regulations governing the handling and disposal of CCR, such as fly ash and bottom ash. The rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act (“RCRA”) and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions. These criteria include standards governing location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and internet posting requirements. The rule generally requires any existing unlined CCR surface impoundment to stop receiving CCR and either retrofit or close, and further requires the closure of any CCR landfill or surface impoundment that cannot meet the applicable performance criteria for location restrictions or structural integrity. Such closure requirements are deemed “forced closure” or “closure for cause” of unlined surface impoundments and are the subject of recent regulatory and judicial activities described below. Since these regulations were finalized, EPA has taken steps to substantially modify the federal rules governing CCR disposal. While certain changes have been prompted by utility industry petitions, others have resulted from judicial review, court-approved settlements with environmental groups, and statutory changes to RCRA. The following lists the pending regulatory changes that, if finalized, could have a material impact as to how APS manages CCR at its coal-fired power plants: • Following the passage of the Water Infrastructure Improvements for the Nation Act in 2016, EPA possesses authority to either authorize states to develop their own permit programs for CCR management or issue federal permits governing CCR disposal both in states without their own permit programs and on tribal lands. Although ADEQ has taken steps to develop a CCR permitting program, it is not clear when that program will be put into effect. On December 19, 2019, EPA proposed its own set of regulations governing the issuance of CCR management permits. • On March 1, 2018, as a result of a settlement with certain environmental groups, EPA proposed adding boron to the list of constituents that trigger corrective action requirements to remediate groundwater impacted by CCR disposal activities. Apart from a subsequent proposal issued on August 14, 2019 to add a specific, health-based groundwater protection standard for boron, EPA has yet to take action on this proposal. • Based on an August 21, 2018 D.C. Circuit decision, which vacated and remanded those provisions of the EPA CCR regulations that allow for the operation of unlined CCR surface impoundments, EPA recently proposed corresponding changes to federal CCR regulations. On July 29, 2020, EPA took final action on new regulations establishing revised deadlines for initiating the closure of unlined CCR surface impoundments, April 11, 2021 at the latest. All APS disposal units subject to these closure requirements were closed as of April 11, 2021. • On November 4, 2019, EPA also proposed to change the manner by which facilities that have committed to cease burning coal in the near-term may qualify for alternative closure. Such qualification would allow CCR disposal units at these plants to continue operating, even though they would otherwise be subject to forced closure under the federal CCR regulations. EPA’s July 29, 2020 final regulation adopted this proposal and now requires explicit EPA approval for facilities to utilize an alternative closure deadline. With respect to the Cholla facility, APS’s application for alternative closure (which would allow the continued disposal of CCR within the facility’s existing unlined CCR surface impoundments until the required date for ceasing coal-fired boiler operations in April 2025) was submitted to EPA on November 30, 2020 and is currently pending. This application will be subject to public comment and, potentially, judicial review. We cannot at this time predict the outcome of these regulatory proceedings or when the EPA will take final action on those matters that are still pending. Depending on the eventual outcome, the costs associated with APS’s management of CCR could materially increase, which could affect APS’s financial position, results of operations, or cash flows. APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners. APS estimates that its share of incremental costs to comply with the CCR rule for Four Corners is approximately $27 million and its share of incremental costs to comply with the CCR rule for Cholla is approximately $16 million. The Navajo Plant disposed of CCR only in a dry landfill storage area. To comply with the CCR rule for the Navajo Plant, APS’s share of incremental costs was approximately $1 million, which has been incurred. Additionally, the CCR rule requires ongoing, phased groundwater monitoring. As of October 2018, APS has completed the statistical analyses for its CCR disposal units that triggered assessment monitoring. APS determined that several of its CCR disposal units at Cholla and Four Corners will need to undergo corrective action. In addition, under the current regulations, all such disposal units must have ceased operating and initiated closure by April 11, 2021 at the latest (except for those disposal units subject to alternative closure). APS initiated an assessment of corrective measures on January 14, 2019 and expects such assessment will continue through late-2021. As part of this assessment, APS continues to gather additional groundwater data and perform remedial evaluations as to the CCR disposal units at Cholla and Four Corners undergoing corrective action. In addition, APS will solicit input from the public, host public hearings, and select remedies as part of this process. Based on the work performed to date, APS currently estimates that its share of corrective action and monitoring costs at Four Corners will likely range from $10 million to $15 million, which would be incurred over 30 years. The analysis needed to perform a similar cost estimate for Cholla remains ongoing at this time. As APS continues to implement the CCR rule’s corrective action assessment process, the current cost estimates may change. Given uncertainties that may exist until we have fully completed the corrective action assessment process, we cannot predict any ultimate impacts to the Company; however, at this time we do not believe the cost estimates for Cholla and any potential change to the cost estimate for Four Corners would have a material impact on our financial position, results of operations or cash flows. Clean Power Plan/Affordable Clean Energy Regulations . On June 19, 2019, EPA took final action on its proposals to repeal EPA’s 2015 Clean Power Plan (“CPP”) and replace those regulations with a new rule, the Affordable Clean Energy (“ACE”) regulations. EPA originally finalized the CPP on August 3, 2015, and such rules would have had far broader impact on the electric power sector than the ACE regulations. On January 19, 2021, the U.S. Court of Appeals for the D.C. Circuit vacated the ACE regulations and remanded them back to EPA to develop new existing power plant carbon regulations consistent with the court’s ruling. That ruling endorsed an expansive view of the federal Clean Air Act consistent with EPA’s 2015 CPP. While the Biden administration has expressed an intent to regulate carbon emissions in this sector more aggressively under the Clean Air Act, we cannot at this time predict the outcome of pending EPA rulemaking proceedings in response to the court’s recent ACE decision. Other environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standard and other rules or matters involving the Clean Air Act, Clean Water Act, Endangered Species Act, RCRA, Superfund, the Navajo Nation, and water supplies for our power plants. The financial impact of complying with current and future environmental rules could jeopardize the economic viability of our coal plants or the willingness or ability of power plant participants to fund any required equipment upgrades or continue their participation in these plants. The economics of continuing to own certain resources, particularly our coal plants, may deteriorate, warranting early retirement of those plants, which may result in asset impairments. APS would seek recovery in rates for the book value of any remaining investments in the plants as well as other costs related to early retirement, but cannot predict whether it would obtain such recovery. Four Corners National Pollutant Discharge Elimination System (“NPDES”) Permit The latest NPDES permit for Four Corners was issued on September 30, 2019. Based upon a November 1, 2019 filing by several environmental groups, the Environmental Appeals Board (“EAB”) took up review of the Four Corners NPDES Permit. Oral argument on this appeal was held on September 3, 2020 and the EAB denied the environmental group petition on September 30, 2020. On January 22, 2021, the environmental groups filed a petition for review of the EAB’s decision with the U.S. Court of Appeals for the Ninth Circuit. The September 2019 permit remains in effect pending this appeal. The parties are presently engaged in mediation to settle this dispute. We cannot predict the outcome of this appeal proceeding, the ongoing mediation, and, if such appeal is successful, whether that outcome will have a material impact on our financial position, results of operations, or cash flows. Four Corners — 4CA Matter On July 6, 2016, 4CA purchased El Paso’s 7% interest in Four Corners. NTEC purchased this 7% interest on July 3, 2018 from 4CA. NTEC purchased the 7% interest at 4CA’s book value, approximately $70 million, and is paying 4CA the purchase price over a period of four years pursuant to a secured interest-bearing promissory note. The note is secured by a portion of APS’s payments to be owed to NTEC under the 2016 Coal Supply Agreement. As of June 30, 2021, the note has a remaining balance of $18 million. NTEC continues to make payments in accordance with the terms of the note. Due to its short-remaining term, among other factors, there are no expected credit losses associated with the note. In connection with the sale, Pinnacle West guaranteed certain obligations that NTEC will have to the other owners of Four Corners, such as NTEC’s 7% share of capital expenditures and operating and maintenance expenses. Pinnacle West’s guarantee is secured by a portion of APS’s payments to be owed to NTEC under the 2016 Coal Supply Agreement. The 2016 Coal Supply Agreement contained alternate pricing terms for the 7% interest in the event NTEC did not purchase the interest. Until the time that NTEC purchased the 7% interest, the alternate pricing provisions were applicable to 4CA as the holder of the 7% interest. These terms included a formula under which NTEC must make certain payments to 4CA for reimbursement of operations and maintenance costs and a specified rate of return, offset by revenue generated by 4CA’s power sales. The amount under this formula for calendar year 2018 (up to the date that NTEC purchased the 7% interest) was approximately $10 million, which was due to 4CA on December 31, 2019. Such payment was satisfied in January 2020 by NTEC directing to 4CA a prepayment from APS of future coal payment obligations of which the prepayment has been fully utilized as of June 2020. Financial Assurances In the normal course of business, we obtain standby letters of credit and surety bonds from financial institutions and other third parties. These instruments guarantee our own future performance and provide third parties with financial and performance assurance in the event we do not perform. These instruments support commodity contract collateral obligations and other transactions. As of June 30, 2021, standby letters of credit totaled $5.3 million and would have expired in 2021, subsequently in April of 2021 an extension was effective that reset the expiration dates to 2022. As of June 30, 2021, surety bonds expiring through 2022 totaled $16 million. The underlying liabilities insured by these instruments are reflected on our balance sheets, where applicable. Therefore, no additional liability is reflected for the letters of credit and surety bonds themselves. We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements. Most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely. Pinnacle West has issued parental guarantees and has provided indemnification under certain surety bonds for APS which were not material at June 30, 2021. In connection with the sale of 4CA’s 7% interest to NTEC, Pinnacle West is guaranteeing certain obligations that NTEC will have to the other owners of Four Corners. (See “Four Corners — 4CA Matter” above for information related to this guarantee). Pinnacle West has not needed to perform under this guarantee. A maximum obligation is not explicitly stated in the guarantee and, therefore, the overall maximum amount of the obligation under such guarantee cannot be reasonably estimated; however, we consider the fair value of this guarantee, including expected credit losses, to be immaterial. In connection with BCE’s acquisition of minority ownership positions in the Clear Creek and Nobles 2 wind farms, Pinnacle West has issued parental guarantees to guarantee the obligations of BCE subsidiaries to make required equity contributions to fund project construction (the “Equity Contribution Guarantees”) and to make production tax credit funding payments to borrowers of the projects (the “PTC Guarantees”). The amounts guaranteed by Pinnacle West are reduced as payments are made under the respective guarantee agreements. The Equity Contribution Guarantees remaining as of June 30, 2021 are immaterial in amount (approximately $2 million) and the PTC Guarantees (approximately $38 million as of June 30, 2021) are |
Other Income and Other Expense
Other Income and Other Expense | 6 Months Ended |
Jun. 30, 2021 | |
Other Income and Expenses [Abstract] | |
Other Income and Other Expense | Other Income and Other Expense The following table pro vides detail of Pinnacle West’s Consolidated other income and other expense (dollars in thousands): Three Months Ended Six Months Ended 2021 2020 2021 2020 Other income: Interest income $ 1,687 $ 2,755 $ 3,635 $ 6,032 Investment gains - net — 2,826 — 2,826 Debt return on Four Corners SCR deferrals (Note 4) 4,089 4,249 8,175 7,389 Debt return on Ocotillo modernization project (Note 4) 6,391 6,703 12,783 12,847 Miscellaneous 40 137 43 145 Total other income $ 12,207 $ 16,670 $ 24,636 $ 29,239 Other expense: Non-operating costs (4,102) (2,290) (6,039) (4,948) Investment gains (losses) — net (431) — (774) 60 Miscellaneous (651) (1,746) (2,224) (3,932) Total other expense $ (5,184) $ (4,036) $ (9,037) $ (8,820) Three Months Ended Six Months Ended 2021 2020 2021 2020 Other income: Interest income $ 1,047 $ 2,183 $ 2,528 $ 4,524 Debt return on Four Corners SCR deferrals (Note 4) 4,089 4,249 8,175 7,389 Debt return on Ocotillo modernization project (Note 4) 6,391 6,703 12,783 12,847 Miscellaneous 36 137 37 145 Total other income $ 11,563 $ 13,272 $ 23,523 $ 24,905 Other expense: Non-operating costs (3,615) (2,113) (5,392) (4,595) Miscellaneous (646) (1,746) (2,219) (3,932) Total other expense $ (4,261) $ (3,859) $ (7,611) $ (8,527) |
Earnings Per Share
Earnings Per Share | 6 Months Ended |
Jun. 30, 2021 | |
Earnings Per Share [Abstract] | |
Earnings Per Share | Earnings Per Share The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share (in thousands, except per share amounts): Three Months Ended June 30, Six Months Ended June 30, 2021 2020 2021 2020 Net income attributable to common shareholders $ 215,697 $ 193,585 $ 251,338 $ 223,578 Weighted average common shares outstanding — basic 112,882 112,638 112,855 112,616 Net effect of dilutive securities: Contingently issuable performance shares and restricted stock units 341 241 303 255 Weighted average common shares outstanding — diluted 113,223 112,879 113,158 112,871 Earnings per weighted-average common share outstanding Net income attributable to common shareholders — basic $ 1.91 $ 1.72 $ 2.23 $ 1.99 Net income attributable to common shareholders — diluted $ 1.91 $ 1.71 $ 2.22 $ 1.98 |
Fair Value Measurements
Fair Value Measurements | 6 Months Ended |
Jun. 30, 2021 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Fair Value Measurements We classify our assets and liabilities that are carried at fair value within the fair value hierarchy. This hierarchy ranks the quality and reliability of the inputs used to determine fair values, which are then classified and disclosed in one of three categories. The three levels of the fair value hierarchy are: Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. Level 2 — Other significant observable inputs, including quoted prices in active markets for similar assets or liabilities; quoted prices in markets that are not active, and model-derived valuations whose inputs are observable (such as yield curves). Level 3 — Valuation models with significant unobservable inputs that are supported by little or no market activity. Instruments in this category may include long-dated derivative transactions where valuations are unobservable due to the length of the transaction, options, and transactions in locations where observable market data does not exist. The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable. We maximize the use of observable inputs and minimize the use of unobservable inputs. We rely primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities. If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use. Our assessment of the inputs and the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities as well as their placement within the fair value hierarchy levels. We assess whether a market is active by obtaining observable broker quotes, reviewing actual market activity, and assessing the volume of transactions. We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote with market activity, or we can determine that the inputs the broker used to arrive at the quoted price are observable. Certain instruments have been valued using the concept of Net Asset Value (“NAV”) as a practical expedient. These instruments are typically structured as investment companies offering shares or units to multiple investors for the purpose of providing a return. These instruments are similar to mutual funds; however, their NAV is generally not published and publicly available, nor are these instruments traded on an exchange. Instruments valued using NAV as a practical expedient are included in our fair value disclosures; however, in accordance with GAAP are not classified within the fair value hierarchy levels. Recurring Fair Value Measurements We apply recurring fair value measurements to cash equivalents, derivative instruments, and investments held in the nuclear decommissioning trusts and other special use funds. On an annual basis, we apply fair value measurements to plan assets held in our retirement and other benefit plans. See Note 8 in the 2020 Form 10-K for fair value discussion of plan assets held in our retirement and other benefit plans. Cash Equivalents Cash equivalents represent certain investments in money market funds that are valued using quoted prices in active markets. Risk Management Activities — Derivative Instruments Exchange traded commodity contracts are valued using unadjusted quoted prices. For non-exchange traded commodity contracts, we calculate fair value based on the average of the bid and offer price, discounted to reflect net present value. We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments. These include valuation adjustments for liquidity and credit risks. The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed out or hedged. The credit valuation adjustment represents estimated credit losses on our net exposure to counterparties, taking into account netting agreements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio. We maintain credit policies that management believes minimize overall credit risk. Certain non-exchange traded commodity contracts are valued based on unobservable inputs due to the long-term nature of contracts, characteristics of the product, or the unique location of the transactions. Our long-dated energy transactions consist of observable valuations for the near-term portion and unobservable valuations for the long-term portions of the transaction. We rely primarily on broker quotes to value these instruments. When our valuations utilize broker quotes, we perform various control procedures to ensure the quote has been developed consistent with fair value accounting guidance. These controls include assessing the quote for reasonableness by comparison against other broker quotes, reviewing historical price relationships, and assessing market activity. When broker quotes are not available, the primary valuation technique used to calculate the fair value is the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at more illiquid delivery points. When the unobservable portion is significant to the overall valuation of the transaction, the entire transaction is classified as Level 3. Investments Held in Nuclear Decommissioning Trusts and Other Special Use Funds The nuclear decommissioning trusts and other special use funds invest in fixed income and equity securities. Other special use funds include the coal reclamation escrow account and the active union employee medical account. See Note 12 for additional discussion about our investment accounts. We value investments in fixed income and equity securities using information provided by our trustees and escrow agent. Our trustees and escrow agent use pricing services that utilize the valuation methodologies described below to determine fair market value. We have internal control procedures designed to ensure this information is consistent with fair value accounting guidance. These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustees’ and escrow agent’s internal operating controls and valuation processes. Fixed Income Securities Fixed income securities issued by the U.S. Treasury are valued using quoted active market prices and are typically classified as Level 1. Fixed income securities issued by corporations, municipalities, and other agencies, including mortgage-backed instruments, are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield curves and spreads relative to such yield curves. These fixed income instruments are classified as Level 2. Whenever possible, multiple market quotes are obtained which enables a cross-check validation. A primary price source is identified based on asset type, class, or issue of securities. Fixed income securities may also include short-term investments in certificates of deposit, variable rate notes, time deposit accounts, U.S. Treasury and Agency obligations, U.S. Treasury repurchase agreements, commercial paper, and other short-term instruments. These instruments are valued using active market prices or utilizing observable inputs described above. Equity Securities The nuclear decommissioning trusts's equity security investments are held indirectly through commingled funds. The commingled funds are valued using the funds’ NAV as a practical expedient. The funds’ NAV is primarily derived from the quoted active market prices of the underlying equity securities held by the funds. We may transact in these commingled funds on a semi-monthly basis at the NAV. The commingled funds are maintained by a bank and hold investments in accordance with the stated objective of tracking the performance of the S&P 500 Index. Because the commingled funds’ shares are offered to a limited group of investors, they are not considered to be traded in an active market. As these instruments are valued using NAV, as a practical expedient, they have not been classified within the fair value hierarchy. The nuclear decommissioning trusts and other special use funds may also hold equity securities that include exchange traded mutual funds and money market accounts for short-term liquidity purposes. These short-term, highly-liquid, investments are valued using active market prices. Fair Value Tables The following table presents the fair value at June 30, 2021 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands): Level 1 Level 2 Level 3 Other Total Assets Risk management activities — derivative instruments: Commodity contracts $ — $ 84,594 $ 26,388 $ (1,368) (a) $ 109,614 Nuclear decommissioning trust: Equity securities 22,749 — — (9,506) (b) 13,243 U.S. commingled equity funds — — — 702,836 (c) 702,836 U.S. Treasury debt 167,584 — — — 167,584 Corporate debt — 150,681 — — 150,681 Mortgage-backed securities — 119,481 — — 119,481 Municipal bonds — 59,876 — — 59,876 Other fixed income — 9,387 — — 9,387 Subtotal nuclear decommissioning trust 190,333 339,425 — 693,330 1,223,088 Other special use funds: Equity securities 19,904 — — 952 (b) 20,856 U.S. Treasury debt 324,418 — — — 324,418 Municipal bonds — 13,162 — — 13,162 Subtotal other special use funds 344,322 13,162 — 952 358,436 Total assets $ 534,655 $ 437,181 $ 26,388 $ 692,914 $ 1,691,138 Liabilities Risk management activities — derivative instruments: Commodity contracts $ — $ (1,586) $ (9) $ 83 (a) $ (1,512) (a) Represents counterparty netting, margin, and collateral. See Note 7. (b) Represents net pending securities sales and purchases. (c) Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy. The following table presents the fair value at December 31, 2020 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands): Level 1 Level 2 Level 3 Other Total Assets Risk management activities — derivative instruments: Commodity contracts $ — $ 9,016 $ 4 $ (4,271) (a) $ 4,749 Nuclear decommissioning trust: Equity securities 29,796 — — (17,828) (b) 11,968 U.S. commingled equity funds — — — 610,055 (c) 610,055 U.S. Treasury debt 164,514 — — — 164,514 Corporate debt — 149,509 — — 149,509 Mortgage-backed securities — 99,623 — — 99,623 Municipal bonds — 89,705 — — 89,705 Other fixed income — 13,061 — — 13,061 Subtotal nuclear decommissioning trust 194,310 351,898 — 592,227 1,138,435 Other special use funds: Equity securities 37,337 — — 504 (b) 37,841 U.S. Treasury debt 203,220 — — — 203,220 Municipal bonds — 13,448 — — 13,448 Subtotal other special use funds 240,557 13,448 — 504 254,509 Total assets $ 434,867 $ 374,362 $ 4 $ 588,460 $ 1,397,693 Liabilities Risk management activities — derivative instruments: Commodity contracts $ — $ (20,498) $ (1,107) $ 2,986 (a) $ (18,619) (a) Represents counterparty netting, margin, and collateral. See Note 7. (b) Represents net pending securities sales and purchases. (c) Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy. Fair Value Measurements Classified as Level 3 The significant unobservable inputs used in the fair value measurement of our energy derivative contracts include broker quotes that cannot be validated as an observable input primarily due to the long-term nature of the quote or other characteristics of the product. Significant changes in these inputs in isolation would result in significantly higher or lower fair value measurements. Changes in our derivative contract fair values, including changes relating to unobservable inputs, typically will not impact net income due to regulatory accounting treatment (see Note 4). Because our forward commodity contracts classified as Level 3 are currently in a net purchase position, we would expect price increases of the underlying commodity to result in increases in the net fair value of the related contracts. Conversely, if the price of the underlying commodity decreases, the net fair value of the related contracts would likely decrease. Other unobservable valuation inputs include credit and liquidity reserves which do not have a material impact on our valuations; however, significant changes in these inputs could also result in higher or lower fair value measurements. Financial Instruments Not Carried at Fair Value The carrying value of our short-term borrowings approximate fair value and are classified within Level 2 of the fair value hierarchy. See Note 3 for our long-term debt fair values. The NTEC note receivable related to the sale of 4CA’s interest in Four Corners bears interest at 3.9% per annum and has a book value of $18.2 million as of June 30, 2021 and $27.1 million as of December 31, 2020, as presented on the Condensed Consolidated Balance Sheets. The carrying amount is not materially different from the fair value of the note receivable and is classified within Level 3 of the fair value hierarchy. See Note 8 for more information on 4CA matters. |
Investments in Nuclear Decommis
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds | 6 Months Ended |
Jun. 30, 2021 | |
Investments, Debt and Equity Securities [Abstract] | |
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds | Investments in Nuclear Decommissioning Trusts and Other Special Use Funds We have investments in debt and equity securities held in Nuclear Decommissioning Trusts, Coal Reclamation Escrow Account, and an Active Union Employee Medical Account. Investments in debt securities are classified as available-for-sale securities. We record both debt and equity security investments at their fair value on our Condensed Consolidated Balance Sheets. See Note 11 for a discussion of how fair value is determined and the classification of the investments within the fair value hierarchy. The investments in each trust or account are restricted for use and are intended to fund specified costs and activities as further described for each fund below. Nuclear Decommissioning Trusts — APS established external decommissioning trusts in accordance with NRC regulations to fund the future costs APS expects to incur to decommission Palo Verde. Third-party investment managers are authorized to buy and sell securities per stated investment guidelines. The trust funds are invested in fixed income securities and equity securities. Earnings and proceeds from sales and maturities of securities are reinvested in the trusts. Because of the ability of APS to recover decommissioning costs in rates, and in accordance with the regulatory treatment, APS has deferred realized and unrealized gains and losses (including credit losses) in other regulatory liabilities. Coal Reclamation Escrow Account — APS has investments restricted for the future coal mine reclamation funding related to Four Corners. This escrow account is primarily invested in fixed income securities. Earnings and proceeds from sales of securities are reinvested in the escrow account. Because of the ability of APS to recover coal mine reclamation costs in rates, and in accordance with the regulatory treatment, APS has deferred realized and unrealized gains and losses (including credit losses) in other regulatory liabilities. Activities relating to APS coal mine reclamation escrow account investments are included within the other special use funds in the table below. Active Union Employee Medical Account — APS has investments restricted for paying active union employee medical costs. These investments may be used to pay active union employee medical costs incurred in the current and future periods. In 2020 and 2019, APS was reimbursed $14 million and $15 million, respectively, for prior year active union employee medical claims from the active union employee medical account. The account is invested primarily in fixed income securities. In accordance with the ratemaking treatment, APS has deferred the unrealized gains and losses (including credit losses) in other regulatory liabilities. Activities relating to active union employee medical account investments are included within the other special use funds in the table below. On January 4, 2021, an additional $106 million of investments were transferred from APS other postretirement benefit trust assets into the active union employee medical account (see Note 5). APS The following tables present the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trusts and other special use fund assets (dollars in thousands): June 30, 2021 Fair Value Total Total Investment Type: Nuclear Decommissioning Trusts Other Special Use Funds Total Equity securities $ 725,585 $ 19,904 $ 745,489 $ 510,432 $ — Available for sale-fixed income securities 507,009 337,580 844,589 (a) 31,269 (1,357) Other (9,506) 952 (8,554) (b) — — Total $ 1,223,088 $ 358,436 $ 1,581,524 $ 541,701 $ (1,357) (a) As of June 30, 2021, the amortized cost basis of these available-for-sale investments is $815 million. (b) Represents net pending securities sales and purchases. December 31, 2020 Fair Value Total Total Investment Type: Nuclear Decommissioning Trusts Other Special Use Funds Total Equity securities $ 639,851 $ 37,337 $ 677,188 $ 421,666 $ — Available for sale-fixed income securities 516,412 216,668 733,080 (a) 46,581 (398) Other (17,828) 504 (17,324) (b) — — Total $ 1,138,435 $ 254,509 $ 1,392,944 $ 468,247 $ (398) (a) As of December 31, 2020, the amortized cost basis of these available-for-sale investments is $687 million. (b) Represents net pending securities sales and purchases. The following table sets forth APS’s realized gains and losses relating to the sale and maturity of available-for-sale debt securities and equity securities, and the proceeds from the sale and maturity of these investment securities (dollars in thousands): Three Months Ended June 30, Nuclear Decommissioning Trusts Other Special Use Funds Total 2021 Realized gains $ 1,406 $ — $ 1,406 Realized losses (1,146) — (1,146) Proceeds from the sale of securities (a) 190,340 17,524 207,864 2020 Realized gains $ 4,500 $ — $ 4,500 Realized losses (1,621) — (1,621) Proceeds from the sale of securities (a) 176,942 19,830 196,772 (a) Proceeds are reinvested in the nuclear decommissioning trusts and other special use funds, excluding amounts reimbursed to the Company for active union employee medical claims from the active union employee medical account. Six Months Ended June 30, Nuclear Decommissioning Trusts Other Special Use Funds Total 2021 Realized gains $ 4,374 $ — $ 4,374 Realized losses (5,294) — (5,294) Proceeds from the sale of securities (a) 425,068 162,774 587,842 2020 Realized gains $ 7,813 $ — $ 7,813 Realized losses (3,848) — (3,848) Proceeds from the sale of securities (a) 355,138 36,721 391,859 (a) Proceeds are reinvested in the nuclear decommissioning trusts and other special use funds, excluding amounts reimbursed to the Company for active union employee medical claims from the active union employee medical account. Fixed Income Securities Contractual Maturities The fair value of APS’s fixed income securities, summarized by contractual maturities, at June 30, 2021, is as follows (dollars in thousands): Nuclear Decommissioning Trust Coal Reclamation Escrow Account Active Union Employee Medical Account Total Less than one year $ 28,151 $ 26,123 $ 40,263 $ 94,537 1 year – 5 years 133,054 35,880 162,728 331,662 5 years – 10 years 131,462 2,676 61,288 195,426 Greater than 10 years 214,342 8,622 — 222,964 Total $ 507,009 $ 73,301 $ 264,279 $ 844,589 |
Changes in Accumulated Other Co
Changes in Accumulated Other Comprehensive Loss | 6 Months Ended |
Jun. 30, 2021 | |
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract] | |
Changes in Accumulated Other Comprehensive Loss | Changes in Accumulated Other Comprehensive Loss The following table shows the changes in Pinnacle West’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component (dollars in thousands): Pension and Other Postretirement Benefits Derivative Instruments Total Three Months Ended June 30 Balance March 31, 2021 $ (59,703) $ (1,809) $ (61,512) OCI (loss) before reclassifications (1,125) 870 (255) Amounts reclassified from accumulated other comprehensive loss 1,189 (a) — 1,189 Balance June 30, 2021 $ (59,639) $ (939) $ (60,578) Balance March 31, 2020 $ (55,317) $ (262) $ (55,579) OCI (loss) before reclassifications (2,008) (1,549) (3,557) Amounts reclassified from accumulated other comprehensive loss 999 (a) 262 (b) 1,261 Balance June 30, 2020 $ (56,326) $ (1,549) $ (57,875) Pension and Other Postretirement Benefits Derivative Instruments Total Six Months Ended June 30 Balance December 31, 2020 $ (60,725) $ (2,071) $ (62,796) OCI (loss) before reclassifications (1,125) 1,132 7 Amounts reclassified from accumulated other comprehensive loss 2,211 (a) — 2,211 Balance June 30, 2021 $ (59,639) $ (939) $ (60,578) Balance December 31, 2019 $ (56,522) $ (574) $ (57,096) OCI (loss) before reclassifications (2,008) (1,257) (3,265) Amounts reclassified from accumulated other comprehensive loss 2,204 (a) 282 (b) 2,486 Balance June 30, 2020 $ (56,326) $ (1,549) $ (57,875) (a) These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 5. (b) These amounts primarily represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA. See Note 7. The following table shows the changes in APS’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component (dollars in thousands): Pension and Other Postretirement Benefits Derivative Instruments Total Three Months Ended June 30 Balance March 31, 2021 $ (39,991) $ — $ (39,991) OCI (loss) before reclassifications (914) — (914) Amounts reclassified from accumulated other comprehensive loss 1,073 (a) — 1,073 Balance June 30, 2021 $ (39,832) $ — $ (39,832) Balance March 31, 2020 $ (33,935) $ (262) $ (34,197) OCI (loss) before reclassifications (1,951) — (1,951) Amounts reclassified from accumulated other comprehensive loss 861 (a) 262 (b) 1,123 Balance June 30, 2020 $ (35,025) $ — $ (35,025) Pension and Other Postretirement Benefits Derivative Instruments Total Six Months Ended June 30 Balance December 31, 2020 $ (40,918) $ — $ (40,918) OCI (loss) before reclassifications (914) — (914) Amounts reclassified from accumulated other comprehensive loss 2,000 (a) — 2,000 Balance June 30, 2021 $ (39,832) $ — $ (39,832) Balance December 31, 2019 $ (34,948) $ (574) $ (35,522) OCI (loss) before reclassifications (1,951) 292 (1,659) Amounts reclassified from accumulated other comprehensive loss 1,874 (a) 282 (b) 2,156 Balance June 30, 2020 $ (35,025) $ — $ (35,025) (a) These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 5. (b) These amounts primarily represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA. See Note 7. |
Income Taxes
Income Taxes | 6 Months Ended |
Jun. 30, 2021 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes The Tax Act reduced the corporate tax rate to 21% effective January 1, 2018. As a result of this rate reduction, the Company recognized a $1.14 billion reduction in its net deferred income tax liabilities as of December 31, 2017. In accordance with accounting for regulated companies, the effect of this rate reduction was substantially offset by a net regulatory liability. Federal income tax laws require the amortization of a majority of the balance over the remaining regulatory life of the related property. As a result of the modifications made to the annual transmission formula rate during the second quarter of 2018, the Company began amortization of FERC jurisdictional net excess deferred tax liabilities in 2018. On March 13, 2019, the ACC approved the Company’s proposal to amortize non-depreciation related net excess deferred tax liabilities subject to its jurisdiction over a twelve-month period. As a result, the Company began amortization in March 2019. The Company recorded $14 million of income tax benefit related to the amortization of these non-depreciation related net excess deferred tax liabilities as of March 31, 2020, with these non-depreciation related net excess deferred tax liabilities being fully amortized as of March 31, 2020. On October 29, 2019, the ACC approved the Company’s proposal to amortize depreciation related net excess deferred tax liabilities subject to its jurisdiction over a 28.5-year period with amortization to retroactively begin as of January 1, 2018. The Company recorded $14 million of income tax benefit related to amortization of these depreciation related net excess deferred tax liabilities for the periods ending June 30, 2021 and June 30, 2020. See Note 4 for more details. Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax. As a result, there is no income tax expense associated with the VIEs recorded on the Pinnacle West Consolidated and APS Consolidated Statements of Income. See Note 6 for additional details related to the Palo Verde sale leaseback VIEs. As of the balance sheet date, the tax year ended December 31, 2017 and all subsequent tax years remain subject to examination by the IRS. With a few exceptions, the Company is no longer subject to state income tax examinations by tax authorities for years before 2016. |
Leases
Leases | 6 Months Ended |
Jun. 30, 2021 | |
Leases [Abstract] | |
Leases | Leases We lease certain land, buildings, vehicles, equipment and other property through operating rental agreements with varying terms, provisions, and expiration dates. APS also has certain purchased power agreements that qualify as lease arrangements. Our leases have remaining terms that expire in 2021 through 2050. Substantially all of our leasing activities relate to APS. In 1986, APS entered into agreements with three separate lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. These lessor trust entities have been deemed VIEs for which APS is the primary beneficiary. As the primary beneficiary, APS consolidated these lessor trust entities. The impacts of these sale leaseback transactions are excluded from our lease disclosures as lease accounting is eliminated upon consolidation. See Note 6 for a discussion of VIEs. On May 1, 2021, APS had a new purchased power lease contract that commenced. The lease term ends on October 31, 2027. This lease allows APS the right to the generation capacity from a natural-gas fueled generator during the months of May through October over the contract term. APS does not operate or maintain the leased asset. APS controls the dispatch of the leased asset during the months of May through October and is required to pay a fixed monthly capacity payment during these periods of use. For these types of leased assets APS has elected to combine both the lease and non-lease payment components and accounts for the entire fixed payment as a lease obligation. This purchased power lease contract is accounted for as an operating lease. The contract does not contain a purchase option or a term extension option. In addition to the fixed monthly capacity payment, APS must also pay variable charges based on the actual production volume of the asset. The variable consideration is not included in the measurement of our lease obligation. The following tables provide information related to our lease costs (dollars in thousands): Three Months Ended Three Months Ended Purchased Power Lease Contracts Land, Property & Equipment Leases Total Purchased Power Lease Contracts Land, Property & Equipment Leases Total Operating lease cost $ 29,514 $ 4,598 $ 34,112 $ 17,221 $ 4,651 $ 21,872 Variable lease cost 40,539 256 40,795 40,821 255 41,076 Short-term lease cost — 1,260 1,260 — 996 996 Total lease cost $ 70,053 $ 6,114 $ 76,167 $ 58,042 $ 5,902 $ 63,944 Six Months Ended Six Months Ended Purchased Power Lease Contracts Land, Property & Equipment Leases Total Purchased Power Lease Contracts Land, Property & Equipment Leases Total Operating lease cost $ 29,514 $ 9,239 $ 38,753 $ 17,221 $ 9,304 $ 26,525 Variable lease cost 62,027 510 62,537 61,394 498 61,892 Short-term lease cost — 2,249 2,249 — 1,786 1,786 Total lease cost $ 91,541 $ 11,998 $ 103,539 $ 78,615 $ 11,588 $ 90,203 Lease costs are primarily included as a component of operating expenses on our Condensed Consolidated Statements of Income. Lease costs relating to purchased power lease contracts are recorded in fuel and purchased power on the Condensed Consolidated Statements of Income, and are subject to recovery under the PSA or RES (see Note 4). The tables above reflect the lease cost amounts before the effect of regulatory deferral under the PSA and RES. Variable lease costs are recognized in the period the costs are incurred, and primarily relate to renewable purchased power lease contracts. Payments under most renewable purchased power lease contracts are dependent upon environmental factors, and due to the inherent uncertainty associated with the reliability of the fuel source, the payments are considered variable and are excluded from the measurement of lease liabilities and right-of-use lease assets. Certain of our lease agreements have lease terms with non-consecutive periods of use. For these agreements, we recognize lease costs during the periods of use. Leases with initial terms of 12 months or less are considered short-term leases and are not recorded on the balance sheet. The following table provides information related to the maturity of our operating lease liabilities (dollars in thousands): June 30, 2021 Year Purchased Power Lease Contracts Land, Property & Equipment Leases Total 2021 (remaining six months of 2021) $ 95,596 $ 7,762 $ 103,358 2022 103,744 11,872 115,616 2023 106,161 9,544 115,705 2024 108,634 6,955 115,589 2025 111,166 5,181 116,347 2026 75,099 3,989 79,088 Thereafter 39,106 34,444 73,550 Total lease commitments 639,506 79,747 719,253 Less imputed interest 25,803 17,613 43,416 Total lease liabilities $ 613,703 $ 62,134 $ 675,837 We recognize lease assets and liabilities upon lease commencement. At June 30, 2021, we have lease arrangements that have been executed, but have not yet commenced. These arrangements primarily relate to energy storage agreements, with lease commencement dates expected to begin in June 2022 with terms ending through December 2042. We expect the total fixed consideration paid for these arrangements, which includes both lease and nonlease payments, will approximate $392 million over the term of the arrangements. The following tables provide other additional information related to operating lease liabilities (dollars in thousands): Six Months Ended Six Months Ended June 30, 2020 Cash paid for amounts included in the measurement of lease liabilities — operating cash flows: $ 13,068 $ 7,624 Right-of-use operating lease assets obtained in exchange for operating lease liabilities 248,694 434,997 June 30, 2021 December 31, 2020 Weighted average remaining lease term 6 years 6 years Weighted average discount rate (a) 1.72 % 1.69 % |
Asset Retirement Obligations
Asset Retirement Obligations | 6 Months Ended |
Jun. 30, 2021 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | Asset Retirement Obligations During the six months ended June 30, 2021, the Company revised its cost estimates for existing Asset Retirement Obligations (ARO) at Cholla related to updated estimates for the closure of ponds and facilities, which resulted in an increase to the ARO of $11.1 million. (See additional details in Notes 4 and 8.) The following schedule shows the change in our asset retirement obligations for the six months ended June 30, 2021 (dollars in thousands): 2021 Asset retirement obligations at January 1, 2021 $ 705,083 Changes attributable to: Accretion expense 18,828 Settlements (2,853) Estimated cash flow revisions 10,932 Asset retirement obligations at June 30, 2021 $ 731,990 In accordance with regulatory accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal. See detail of regulatory liabilities in Note 4. |
New Accounting Standards
New Accounting Standards | 6 Months Ended |
Jun. 30, 2021 | |
Accounting Standards Update and Change in Accounting Principle [Abstract] | |
New Accounting Standards | New Accounting Standard ASU 2021-05, Leases: Certain Leases with Variable Lease PaymentsIn July 2021, a new accounting standard was issued that amends the lease accounting guidance. The amended guidance will require lessors to account for certain lease transactions, that contain variable lease payments, as operating leases. The amendments are intended to eliminate the recognition of any day-one loss associated with certain sales-type and direct-financing lease transactions. The changes do not impact lessee accounting. The new guidance is effective for us on January 1, 2022 and may be adopted using either a retrospective or prospective approach. As we typically are not the lessor in these type of lease transactions, we do not expect the adoption of this guidance will have a material impact on our financial statements. |
New Accounting Standards (Polic
New Accounting Standards (Policies) | 6 Months Ended |
Jun. 30, 2021 | |
Accounting Standards Update and Change in Accounting Principle [Abstract] | |
New Accounting Standards | ASU 2021-05, Leases: Certain Leases with Variable Lease PaymentsIn July 2021, a new accounting standard was issued that amends the lease accounting guidance. The amended guidance will require lessors to account for certain lease transactions, that contain variable lease payments, as operating leases. The amendments are intended to eliminate the recognition of any day-one loss associated with certain sales-type and direct-financing lease transactions. The changes do not impact lessee accounting. The new guidance is effective for us on January 1, 2022 and may be adopted using either a retrospective or prospective approach. As we typically are not the lessor in these type of lease transactions, we do not expect the adoption of this guidance will have a material impact on our financial statements. |
Consolidation and Nature of O_2
Consolidation and Nature of Operations (Tables) | 6 Months Ended |
Jun. 30, 2021 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Summary of supplemental cash flow information | The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands): Six Months Ended 2021 2020 Cash paid (received) during the period for: Income taxes, net of refunds $ (788) $ (3,028) Interest, net of amounts capitalized 112,010 107,417 Significant non-cash investing and financing activities: Accrued capital expenditures $ 105,515 $ 87,815 Dividends accrued but not yet paid 93,610 88,066 The following table summarizes supplemental APS cash flow information (dollars in thousands): Six Months Ended 2021 2020 Cash paid (received) during the period for: Income taxes, net of refunds $ 3,317 $ — Interest, net of amounts capitalized 107,044 100,991 Significant non-cash investing and financing activities: Accrued capital expenditures $ 105,515 $ 87,815 Dividends accrued but not yet paid 93,500 88,000 |
Revenue (Tables)
Revenue (Tables) | 6 Months Ended |
Jun. 30, 2021 | |
Revenue from Contract with Customer [Abstract] | |
Disaggregation of Revenue | The following table provides detail of Pinnacle West’s consolidated revenue disaggregated by revenue sources (dollars in thousands): Three Months Ended June 30, Six Months Ended June 30, 2021 2020 2021 2020 Retail Electric Revenue Residential $ 531,717 $ 515,128 $ 872,555 $ 840,201 Non-Residential 420,995 381,121 735,778 684,472 Wholesale Energy Sales 18,007 15,927 35,604 30,595 Transmission Services for Others 22,579 14,766 41,572 30,693 Other Sources 6,951 2,648 11,215 5,559 Total operating revenues $ 1,000,249 $ 929,590 $ 1,696,724 $ 1,591,520 |
Schedule of Accounts Receivable | The following table provides a rollforward of Pinnacle West’s allowance for doubtful accounts (dollars in thousands): June 30, 2021 December 31, 2020 Allowance for doubtful accounts, balance at beginning of period $ 19,782 $ 8,171 Bad debt expense 10,048 20,633 Actual write-offs (7,061) (9,022) Allowance for doubtful accounts, balance at end of period $ 22,769 $ 19,782 |
Long-Term Debt and Liquidity _2
Long-Term Debt and Liquidity Matters (Tables) | 6 Months Ended |
Jun. 30, 2021 | |
Debt Disclosure [Abstract] | |
Schedule of estimated fair value of long-term debt, including current maturities | The following table presents the estimated fair value of our long-term debt, including current maturities (dollars in thousands): As of June 30, 2021 As of December 31, 2020 Carrying Fair Value Carrying Fair Value Pinnacle West $ 646,729 $ 654,095 $ 496,321 $ 509,050 APS 5,819,198 6,746,984 5,817,945 7,103,791 Total $ 6,465,927 $ 7,401,079 $ 6,314,266 $ 7,612,841 |
Regulatory Matters (Tables)
Regulatory Matters (Tables) | 6 Months Ended |
Jun. 30, 2021 | |
Regulated Operations [Abstract] | |
Schedule of capital structure and cost of capital | 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 % |
Schedule of changes in the deferred fuel and purchased power regulatory asset | The following table shows the changes in the deferred fuel and purchased power regulatory asset for 2021 and 2020 (dollars in thousands): Six Months Ended 2021 2020 Beginning balance $ 175,835 $ 70,137 Deferred fuel and purchased power costs — current period 135,905 26,473 Amounts (charged) refunded to customers (10,828) 4,815 Ending balance $ 300,912 $ 101,425 |
Schedule of regulatory assets | The detail of regulatory assets is as follows (dollars in thousands): Amortization Through June 30, 2021 December 31, 2020 Current Non-Current Current Non-Current Pension (a) $ — $ 496,372 $ — $ 469,953 Deferred fuel and purchased power (b) (c) 2022 300,912 — 175,835 — Income taxes — allowance for funds used during construction (“AFUDC”) equity 2051 7,169 161,279 7,169 158,776 Retired power plant costs 2033 28,182 100,123 28,181 114,214 Ocotillo deferral N/A — 124,919 — 95,723 SCR deferral N/A — 95,171 — 81,307 Deferred property taxes 2027 8,569 45,342 8,569 49,626 Lost fixed cost recovery (b) 2022 53,087 — 41,807 — Deferred compensation 2036 — 35,806 — 36,195 Four Corners cost deferral 2024 8,077 20,037 8,077 24,075 Income taxes — investment tax credit basis adjustment 2049 1,113 23,807 1,113 24,291 Palo Verde VIEs (Note 6) 2046 — 21,174 — 21,255 Coal reclamation 2026 1,068 16,465 1,068 16,999 Loss on reacquired debt 2038 1,648 10,128 1,689 10,877 Mead-Phoenix transmission line contributions in aid of construction (“CIAC”) 2050 332 9,214 332 9,380 Tax expense adjustor mechanism (b) 2021 7,956 — 6,226 — Demand side management (b) 2022 — 7,269 — 7,268 Tax expense of Medicare subsidy 2024 1,235 3,167 1,235 3,704 TCA balancing account (b) 2023 — 1,903 — — Deferred fuel and purchased power — mark-to-market (Note 7) 2024 — — 3,341 9,244 PSA interest 2022 133 — 4,355 — Other Various 1,321 1,801 2,716 1,100 Total regulatory assets (d) $ 420,802 $ 1,173,977 $ 291,713 $ 1,133,987 (a) This asset represents the future recovery of pension benefit obligations through retail rates. If these costs are disallowed by the ACC, this regulatory asset would be charged to other comprehensive income (“OCI”) and result in lower future revenues. See Note 5. (b) See “Cost Recovery Mechanisms” discussion above. (c) Subject to a carrying charge. (d) There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base. FERC rates are set using a formula rate as described in “Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.” |
Schedule of regulatory liabilities | The detail of regulatory liabilities is as follows (dollars in thousands): Amortization Through June 30, 2021 December 31, 2020 Current Non-Current Current Non-Current Excess deferred income taxes — ACC - Tax Act (a) 2046 $ 41,381 $ 993,982 $ 41,330 $ 1,012,583 Excess deferred income taxes — FERC - Tax Act (a) 2058 7,240 225,995 7,240 229,147 Asset retirement obligations 2057 — 567,900 — 506,049 Other postretirement benefits (d) 47,798 314,218 37,705 349,588 Removal costs (c) 69,348 61,601 52,844 103,008 Deferred fuel and purchased power — mark-to-market (Note 7) 2024 82,082 27,305 — — Income taxes — change in rates 2050 2,839 65,319 2,839 66,553 Four Corners coal reclamation 2038 5,461 49,904 5,460 49,435 Income taxes — deferred investment tax credit 2049 2,231 47,677 2,231 48,648 Spent nuclear fuel 2027 6,510 41,815 6,768 44,221 Renewable energy standard (b) 2022 30,665 — 39,442 103 Property tax deferral N/A — 16,188 — 13,856 Demand side management (b) 2022 3,149 12,457 10,819 — Sundance maintenance 2031 556 12,312 2,989 11,508 FERC transmission true up 2023 7,547 3,511 6,598 3,008 TCA balancing account (b) 2023 10,750 159 2,902 4,672 Tax expense adjustor mechanism (b) (e) 2021 7,148 — 7,089 — Deferred gains on utility property 2022 2,423 333 2,423 1,544 Active union medical trust N/A — 2,347 — 6,057 Other Various 484 289 409 189 Total regulatory liabilities $ 327,612 $ 2,443,312 $ 229,088 $ 2,450,169 (a) For purposes of presentation on the Statement of Cash Flows, amortization of the regulatory liabilities for excess deferred income taxes are reflected as “Deferred income taxes” under Cash Flows From Operating Activities. (b) See “Cost Recovery Mechanisms” discussion above. (c) In accordance with regulatory accounting guidance, APS accrues removal costs for its regulated assets, even if there is no legal obligation for removal. (d) See Note 5. (e) Pursuant to Decision 77852, the ACC has authorized APS to return to customers up to $7 million of liability recorded to the TEAM balancing account through December 31, 2021. Should new base rates become effective prior to December 31, 2021, any remaining unreturned balance is anticipated to be included in the new base rates. |
Retirement Plans and Other Po_2
Retirement Plans and Other Postretirement Benefits (Tables) | 6 Months Ended |
Jun. 30, 2021 | |
Retirement Benefits [Abstract] | |
Schedule of net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged or amortized to the regulatory asset) | 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 Six Months Ended Three Months Ended Six Months Ended 2021 2020 2021 2020 2021 2020 2021 2020 Service cost — benefits earned during the period $ 14,939 $ 13,859 $ 30,618 $ 28,116 $ 4,341 $ 5,401 $ 8,898 $ 11,118 Non-service costs (credits): Interest cost on benefit obligation 24,614 29,522 49,283 59,283 4,095 6,417 8,257 12,929 Expected return on plan assets (50,706) (46,915) (101,314) (93,721) (10,361) (10,019) (20,722) (20,038) Amortization of: Prior service credit — — — — (9,427) (9,394) (18,854) (18,788) Net actuarial loss (gain) 3,989 8,295 7,974 17,306 (2,641) — (5,046) — Net periodic benefit cost/(benefit) $ (7,164) $ 4,761 $ (13,439) $ 10,984 $ (13,993) $ (7,595) $ (27,467) $ (14,779) Portion of cost/(benefit) charged to expense $ (8,614) $ 271 $ (16,625) $ 1,613 $ (9,608) $ (5,056) $ (19,136) $ (10,512) |
Palo Verde Sale Leaseback Var_2
Palo Verde Sale Leaseback Variable Interest Entities (Tables) | 6 Months Ended |
Jun. 30, 2021 | |
Variable Interest Entities [Abstract] | |
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets | Our Condensed Consolidated Balance Sheets at June 30, 2021 and December 31, 2020 include the following amounts relating to the VIEs (dollars in thousands): June 30, 2021 December 31, 2020 Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation $ 96,101 $ 98,036 Equity — Noncontrolling interests 117,275 119,290 |
Derivative Accounting (Tables)
Derivative Accounting (Tables) | 6 Months Ended |
Jun. 30, 2021 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Outstanding gross notional amount of derivatives, which represents both purchases and sales (does not reflect net position) | The following table shows the outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): Quantity Commodity Unit of Measure June 30, 2021 December 31, 2020 Power GWh 368 368 Gas Billion cubic feet 189 205 |
Gains and losses from derivative instruments in designated cash flow accounting hedges relationships | The following table provides information about APS’s gains and losses from derivative instruments in designated cash flow accounting hedging relationships (dollars in thousands): Financial Statement Location Three Months Ended Six Months Ended Commodity Contracts 2021 2020 2021 2020 Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a) Fuel and purchased power (b) $ — $ (349) $ — $ (763) (a) During the three and six months ended June 30, 2021 and 2020, 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. |
Gains and losses from derivative instruments not designated as accounting hedges instruments | The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments (dollars in thousands): Financial Statement Location Three Months Ended Six Months Ended Commodity Contracts 2021 2020 2021 2020 Net Gain (Loss) Recognized in Income Fuel and purchased power (a) $ 95,116 $ (4,894) $ 121,975 $ (34,971) (a) Amounts are before the effect of PSA deferrals. |
Schedule of offsetting assets | The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting. These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities and other assets lines of our Condensed Consolidated Balance Sheets. As of June 30, 2021: Gross Recognized Derivatives (a) Amounts Net Recognized Derivatives Other (c) Amount Reported on Balance Sheets Current assets $ 83,677 $ (1,368) $ 82,309 $ — $ 82,309 Investments and other assets 27,305 — 27,305 — 27,305 Total assets 110,982 (1,368) 109,614 — 109,614 Current liabilities (1,595) 1,368 (227) (1,285) (1,512) Deferred credits and other — — — — — Total liabilities (1,595) 1,368 (227) (1,285) (1,512) Total $ 109,387 $ — $ 109,387 $ (1,285) $ 108,102 (a) All of our gross recognized derivative instruments were subject to master netting arrangements. (b) No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting. (c) Represents cash collateral that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions or collateral posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $1,285. As of December 31, 2020: Gross Recognized Derivatives (a) Amounts Net Recognized Derivatives Other (c) Amount Current assets $ 5,870 $ (2,939) $ 2,931 $ — $ 2,931 Investments and other assets 3,150 (1,332) 1,818 — 1,818 Total assets 9,020 (4,271) 4,749 — 4,749 Current liabilities (9,211) 2,939 (6,272) (1,285) (7,557) Deferred credits and other (12,394) 1,332 (11,062) — (11,062) Total liabilities (21,605) 4,271 (17,334) (1,285) (18,619) Total $ (12,585) $ — $ (12,585) $ (1,285) $ (13,870) (a) All of our gross recognized derivative instruments were subject to master netting arrangements. (b) No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting. (c) Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $1,285. |
Schedule of offsetting liabilities | The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting. These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities and other assets lines of our Condensed Consolidated Balance Sheets. As of June 30, 2021: Gross Recognized Derivatives (a) Amounts Net Recognized Derivatives Other (c) Amount Reported on Balance Sheets Current assets $ 83,677 $ (1,368) $ 82,309 $ — $ 82,309 Investments and other assets 27,305 — 27,305 — 27,305 Total assets 110,982 (1,368) 109,614 — 109,614 Current liabilities (1,595) 1,368 (227) (1,285) (1,512) Deferred credits and other — — — — — Total liabilities (1,595) 1,368 (227) (1,285) (1,512) Total $ 109,387 $ — $ 109,387 $ (1,285) $ 108,102 (a) All of our gross recognized derivative instruments were subject to master netting arrangements. (b) No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting. (c) Represents cash collateral that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions or collateral posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $1,285. As of December 31, 2020: Gross Recognized Derivatives (a) Amounts Net Recognized Derivatives Other (c) Amount Current assets $ 5,870 $ (2,939) $ 2,931 $ — $ 2,931 Investments and other assets 3,150 (1,332) 1,818 — 1,818 Total assets 9,020 (4,271) 4,749 — 4,749 Current liabilities (9,211) 2,939 (6,272) (1,285) (7,557) Deferred credits and other (12,394) 1,332 (11,062) — (11,062) Total liabilities (21,605) 4,271 (17,334) (1,285) (18,619) Total $ (12,585) $ — $ (12,585) $ (1,285) $ (13,870) (a) All of our gross recognized derivative instruments were subject to master netting arrangements. (b) No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting. (c) Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $1,285. |
Information about derivative instruments that have credit-risk-related contingent features | The following table provides information about our derivative instruments that have credit-risk-related contingent features (dollars in thousands): June 30, 2021 Aggregate fair value of derivative instruments in a net liability position $ 1,595 Cash collateral posted — Additional cash collateral in the event credit-risk-related contingent features were fully triggered — |
Other Income and Other Expense
Other Income and Other Expense (Tables) | 6 Months Ended |
Jun. 30, 2021 | |
Other Income and Expenses [Abstract] | |
Detail of other income and other expense | The following table pro vides detail of Pinnacle West’s Consolidated other income and other expense (dollars in thousands): Three Months Ended Six Months Ended 2021 2020 2021 2020 Other income: Interest income $ 1,687 $ 2,755 $ 3,635 $ 6,032 Investment gains - net — 2,826 — 2,826 Debt return on Four Corners SCR deferrals (Note 4) 4,089 4,249 8,175 7,389 Debt return on Ocotillo modernization project (Note 4) 6,391 6,703 12,783 12,847 Miscellaneous 40 137 43 145 Total other income $ 12,207 $ 16,670 $ 24,636 $ 29,239 Other expense: Non-operating costs (4,102) (2,290) (6,039) (4,948) Investment gains (losses) — net (431) — (774) 60 Miscellaneous (651) (1,746) (2,224) (3,932) Total other expense $ (5,184) $ (4,036) $ (9,037) $ (8,820) Three Months Ended Six Months Ended 2021 2020 2021 2020 Other income: Interest income $ 1,047 $ 2,183 $ 2,528 $ 4,524 Debt return on Four Corners SCR deferrals (Note 4) 4,089 4,249 8,175 7,389 Debt return on Ocotillo modernization project (Note 4) 6,391 6,703 12,783 12,847 Miscellaneous 36 137 37 145 Total other income $ 11,563 $ 13,272 $ 23,523 $ 24,905 Other expense: Non-operating costs (3,615) (2,113) (5,392) (4,595) Miscellaneous (646) (1,746) (2,219) (3,932) Total other expense $ (4,261) $ (3,859) $ (7,611) $ (8,527) |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 6 Months Ended |
Jun. 30, 2021 | |
Earnings Per Share [Abstract] | |
Schedule of earnings per weighted average common share outstanding | The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share (in thousands, except per share amounts): Three Months Ended June 30, Six Months Ended June 30, 2021 2020 2021 2020 Net income attributable to common shareholders $ 215,697 $ 193,585 $ 251,338 $ 223,578 Weighted average common shares outstanding — basic 112,882 112,638 112,855 112,616 Net effect of dilutive securities: Contingently issuable performance shares and restricted stock units 341 241 303 255 Weighted average common shares outstanding — diluted 113,223 112,879 113,158 112,871 Earnings per weighted-average common share outstanding Net income attributable to common shareholders — basic $ 1.91 $ 1.72 $ 2.23 $ 1.99 Net income attributable to common shareholders — diluted $ 1.91 $ 1.71 $ 2.22 $ 1.98 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 6 Months Ended |
Jun. 30, 2021 | |
Fair Value Disclosures [Abstract] | |
Fair value of assets and liabilities that are measured at fair value on a recurring basis | The following table presents the fair value at June 30, 2021 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands): Level 1 Level 2 Level 3 Other Total Assets Risk management activities — derivative instruments: Commodity contracts $ — $ 84,594 $ 26,388 $ (1,368) (a) $ 109,614 Nuclear decommissioning trust: Equity securities 22,749 — — (9,506) (b) 13,243 U.S. commingled equity funds — — — 702,836 (c) 702,836 U.S. Treasury debt 167,584 — — — 167,584 Corporate debt — 150,681 — — 150,681 Mortgage-backed securities — 119,481 — — 119,481 Municipal bonds — 59,876 — — 59,876 Other fixed income — 9,387 — — 9,387 Subtotal nuclear decommissioning trust 190,333 339,425 — 693,330 1,223,088 Other special use funds: Equity securities 19,904 — — 952 (b) 20,856 U.S. Treasury debt 324,418 — — — 324,418 Municipal bonds — 13,162 — — 13,162 Subtotal other special use funds 344,322 13,162 — 952 358,436 Total assets $ 534,655 $ 437,181 $ 26,388 $ 692,914 $ 1,691,138 Liabilities Risk management activities — derivative instruments: Commodity contracts $ — $ (1,586) $ (9) $ 83 (a) $ (1,512) (a) Represents counterparty netting, margin, and collateral. See Note 7. (b) Represents net pending securities sales and purchases. (c) Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy. The following table presents the fair value at December 31, 2020 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands): Level 1 Level 2 Level 3 Other Total Assets Risk management activities — derivative instruments: Commodity contracts $ — $ 9,016 $ 4 $ (4,271) (a) $ 4,749 Nuclear decommissioning trust: Equity securities 29,796 — — (17,828) (b) 11,968 U.S. commingled equity funds — — — 610,055 (c) 610,055 U.S. Treasury debt 164,514 — — — 164,514 Corporate debt — 149,509 — — 149,509 Mortgage-backed securities — 99,623 — — 99,623 Municipal bonds — 89,705 — — 89,705 Other fixed income — 13,061 — — 13,061 Subtotal nuclear decommissioning trust 194,310 351,898 — 592,227 1,138,435 Other special use funds: Equity securities 37,337 — — 504 (b) 37,841 U.S. Treasury debt 203,220 — — — 203,220 Municipal bonds — 13,448 — — 13,448 Subtotal other special use funds 240,557 13,448 — 504 254,509 Total assets $ 434,867 $ 374,362 $ 4 $ 588,460 $ 1,397,693 Liabilities Risk management activities — derivative instruments: Commodity contracts $ — $ (20,498) $ (1,107) $ 2,986 (a) $ (18,619) (a) Represents counterparty netting, margin, and collateral. See Note 7. (b) Represents net pending securities sales and purchases. (c) Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy. |
Investments in Nuclear Decomm_2
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Tables) | 6 Months Ended |
Jun. 30, 2021 | |
Investments, Debt and Equity Securities [Abstract] | |
Fair value of APS's nuclear decommissioning trust fund assets | The following tables present the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trusts and other special use fund assets (dollars in thousands): June 30, 2021 Fair Value Total Total Investment Type: Nuclear Decommissioning Trusts Other Special Use Funds Total Equity securities $ 725,585 $ 19,904 $ 745,489 $ 510,432 $ — Available for sale-fixed income securities 507,009 337,580 844,589 (a) 31,269 (1,357) Other (9,506) 952 (8,554) (b) — — Total $ 1,223,088 $ 358,436 $ 1,581,524 $ 541,701 $ (1,357) (a) As of June 30, 2021, the amortized cost basis of these available-for-sale investments is $815 million. (b) Represents net pending securities sales and purchases. December 31, 2020 Fair Value Total Total Investment Type: Nuclear Decommissioning Trusts Other Special Use Funds Total Equity securities $ 639,851 $ 37,337 $ 677,188 $ 421,666 $ — Available for sale-fixed income securities 516,412 216,668 733,080 (a) 46,581 (398) Other (17,828) 504 (17,324) (b) — — Total $ 1,138,435 $ 254,509 $ 1,392,944 $ 468,247 $ (398) (a) As of December 31, 2020, the amortized cost basis of these available-for-sale investments is $687 million. (b) Represents net pending securities sales and purchases. |
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds | The following table sets forth APS’s realized gains and losses relating to the sale and maturity of available-for-sale debt securities and equity securities, and the proceeds from the sale and maturity of these investment securities (dollars in thousands): Three Months Ended June 30, Nuclear Decommissioning Trusts Other Special Use Funds Total 2021 Realized gains $ 1,406 $ — $ 1,406 Realized losses (1,146) — (1,146) Proceeds from the sale of securities (a) 190,340 17,524 207,864 2020 Realized gains $ 4,500 $ — $ 4,500 Realized losses (1,621) — (1,621) Proceeds from the sale of securities (a) 176,942 19,830 196,772 (a) Proceeds are reinvested in the nuclear decommissioning trusts and other special use funds, excluding amounts reimbursed to the Company for active union employee medical claims from the active union employee medical account. Six Months Ended June 30, Nuclear Decommissioning Trusts Other Special Use Funds Total 2021 Realized gains $ 4,374 $ — $ 4,374 Realized losses (5,294) — (5,294) Proceeds from the sale of securities (a) 425,068 162,774 587,842 2020 Realized gains $ 7,813 $ — $ 7,813 Realized losses (3,848) — (3,848) Proceeds from the sale of securities (a) 355,138 36,721 391,859 |
Fair value of fixed income securities, summarized by contractual maturities | The fair value of APS’s fixed income securities, summarized by contractual maturities, at June 30, 2021, is as follows (dollars in thousands): Nuclear Decommissioning Trust Coal Reclamation Escrow Account Active Union Employee Medical Account Total Less than one year $ 28,151 $ 26,123 $ 40,263 $ 94,537 1 year – 5 years 133,054 35,880 162,728 331,662 5 years – 10 years 131,462 2,676 61,288 195,426 Greater than 10 years 214,342 8,622 — 222,964 Total $ 507,009 $ 73,301 $ 264,279 $ 844,589 |
Changes in Accumulated Other _2
Changes in Accumulated Other Comprehensive Loss (Tables) | 6 Months Ended |
Jun. 30, 2021 | |
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract] | |
Schedule of changes in accumulated other comprehensive loss including reclassification adjustments, net of tax, by component | The following table shows the changes in Pinnacle West’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component (dollars in thousands): Pension and Other Postretirement Benefits Derivative Instruments Total Three Months Ended June 30 Balance March 31, 2021 $ (59,703) $ (1,809) $ (61,512) OCI (loss) before reclassifications (1,125) 870 (255) Amounts reclassified from accumulated other comprehensive loss 1,189 (a) — 1,189 Balance June 30, 2021 $ (59,639) $ (939) $ (60,578) Balance March 31, 2020 $ (55,317) $ (262) $ (55,579) OCI (loss) before reclassifications (2,008) (1,549) (3,557) Amounts reclassified from accumulated other comprehensive loss 999 (a) 262 (b) 1,261 Balance June 30, 2020 $ (56,326) $ (1,549) $ (57,875) Pension and Other Postretirement Benefits Derivative Instruments Total Six Months Ended June 30 Balance December 31, 2020 $ (60,725) $ (2,071) $ (62,796) OCI (loss) before reclassifications (1,125) 1,132 7 Amounts reclassified from accumulated other comprehensive loss 2,211 (a) — 2,211 Balance June 30, 2021 $ (59,639) $ (939) $ (60,578) Balance December 31, 2019 $ (56,522) $ (574) $ (57,096) OCI (loss) before reclassifications (2,008) (1,257) (3,265) Amounts reclassified from accumulated other comprehensive loss 2,204 (a) 282 (b) 2,486 Balance June 30, 2020 $ (56,326) $ (1,549) $ (57,875) (a) These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 5. (b) These amounts primarily represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA. See Note 7. The following table shows the changes in APS’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component (dollars in thousands): Pension and Other Postretirement Benefits Derivative Instruments Total Three Months Ended June 30 Balance March 31, 2021 $ (39,991) $ — $ (39,991) OCI (loss) before reclassifications (914) — (914) Amounts reclassified from accumulated other comprehensive loss 1,073 (a) — 1,073 Balance June 30, 2021 $ (39,832) $ — $ (39,832) Balance March 31, 2020 $ (33,935) $ (262) $ (34,197) OCI (loss) before reclassifications (1,951) — (1,951) Amounts reclassified from accumulated other comprehensive loss 861 (a) 262 (b) 1,123 Balance June 30, 2020 $ (35,025) $ — $ (35,025) Pension and Other Postretirement Benefits Derivative Instruments Total Six Months Ended June 30 Balance December 31, 2020 $ (40,918) $ — $ (40,918) OCI (loss) before reclassifications (914) — (914) Amounts reclassified from accumulated other comprehensive loss 2,000 (a) — 2,000 Balance June 30, 2021 $ (39,832) $ — $ (39,832) Balance December 31, 2019 $ (34,948) $ (574) $ (35,522) OCI (loss) before reclassifications (1,951) 292 (1,659) Amounts reclassified from accumulated other comprehensive loss 1,874 (a) 282 (b) 2,156 Balance June 30, 2020 $ (35,025) $ — $ (35,025) (a) These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 5. (b) These amounts primarily represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA. See Note 7. |
Leases (Tables)
Leases (Tables) | 6 Months Ended |
Jun. 30, 2021 | |
Leases [Abstract] | |
Lease cost and additional information | The following tables provide information related to our lease costs (dollars in thousands): Three Months Ended Three Months Ended Purchased Power Lease Contracts Land, Property & Equipment Leases Total Purchased Power Lease Contracts Land, Property & Equipment Leases Total Operating lease cost $ 29,514 $ 4,598 $ 34,112 $ 17,221 $ 4,651 $ 21,872 Variable lease cost 40,539 256 40,795 40,821 255 41,076 Short-term lease cost — 1,260 1,260 — 996 996 Total lease cost $ 70,053 $ 6,114 $ 76,167 $ 58,042 $ 5,902 $ 63,944 Six Months Ended Six Months Ended Purchased Power Lease Contracts Land, Property & Equipment Leases Total Purchased Power Lease Contracts Land, Property & Equipment Leases Total Operating lease cost $ 29,514 $ 9,239 $ 38,753 $ 17,221 $ 9,304 $ 26,525 Variable lease cost 62,027 510 62,537 61,394 498 61,892 Short-term lease cost — 2,249 2,249 — 1,786 1,786 Total lease cost $ 91,541 $ 11,998 $ 103,539 $ 78,615 $ 11,588 $ 90,203 The following tables provide other additional information related to operating lease liabilities (dollars in thousands): Six Months Ended Six Months Ended June 30, 2020 Cash paid for amounts included in the measurement of lease liabilities — operating cash flows: $ 13,068 $ 7,624 Right-of-use operating lease assets obtained in exchange for operating lease liabilities 248,694 434,997 June 30, 2021 December 31, 2020 Weighted average remaining lease term 6 years 6 years Weighted average discount rate (a) 1.72 % 1.69 % |
Schedule of future minimum payments | The following table provides information related to the maturity of our operating lease liabilities (dollars in thousands): June 30, 2021 Year Purchased Power Lease Contracts Land, Property & Equipment Leases Total 2021 (remaining six months of 2021) $ 95,596 $ 7,762 $ 103,358 2022 103,744 11,872 115,616 2023 106,161 9,544 115,705 2024 108,634 6,955 115,589 2025 111,166 5,181 116,347 2026 75,099 3,989 79,088 Thereafter 39,106 34,444 73,550 Total lease commitments 639,506 79,747 719,253 Less imputed interest 25,803 17,613 43,416 Total lease liabilities $ 613,703 $ 62,134 $ 675,837 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 6 Months Ended |
Jun. 30, 2021 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Change in asset retirement obligations | The following schedule shows the change in our asset retirement obligations for the six months ended June 30, 2021 (dollars in thousands): 2021 Asset retirement obligations at January 1, 2021 $ 705,083 Changes attributable to: Accretion expense 18,828 Settlements (2,853) Estimated cash flow revisions 10,932 Asset retirement obligations at June 30, 2021 $ 731,990 |
Consolidation and Nature of O_3
Consolidation and Nature of Operations (Details) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2021 | Jun. 30, 2020 | |
Cash paid (received) during the period for: | ||
Income taxes, net of refunds | $ (788) | $ (3,028) |
Interest, net of amounts capitalized | 112,010 | 107,417 |
Significant non-cash investing and financing activities: | ||
Accrued capital expenditures | 105,515 | 87,815 |
Dividends accrued but not yet paid | 93,610 | 88,066 |
APS | ||
Cash paid (received) during the period for: | ||
Income taxes, net of refunds | 3,317 | 0 |
Interest, net of amounts capitalized | 107,044 | 100,991 |
Significant non-cash investing and financing activities: | ||
Accrued capital expenditures | 105,515 | 87,815 |
Dividends accrued but not yet paid | $ 93,500 | $ 88,000 |
Revenue (Details)
Revenue (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2021 | Jun. 30, 2020 | Jun. 30, 2021 | Jun. 30, 2020 | |
Disaggregation of Revenue [Line Items] | ||||
Operating revenues | $ 1,000,249 | $ 929,590 | $ 1,696,724 | $ 1,591,520 |
Regulatory cost recovery revenue | 20,000 | 15,000 | 34,000 | 29,000 |
Electric Service | Residential | ||||
Disaggregation of Revenue [Line Items] | ||||
Operating revenues | 531,717 | 515,128 | 872,555 | 840,201 |
Electric Service | Non-Residential | ||||
Disaggregation of Revenue [Line Items] | ||||
Operating revenues | 420,995 | 381,121 | 735,778 | 684,472 |
Electric Service | Wholesale Energy Sales | ||||
Disaggregation of Revenue [Line Items] | ||||
Operating revenues | 18,007 | 15,927 | 35,604 | 30,595 |
Transmission Services for Others | ||||
Disaggregation of Revenue [Line Items] | ||||
Operating revenues | 22,579 | 14,766 | 41,572 | 30,693 |
Other Sources | ||||
Disaggregation of Revenue [Line Items] | ||||
Operating revenues | 6,951 | 2,648 | 11,215 | 5,559 |
Electric and Transmission Service | ||||
Disaggregation of Revenue [Line Items] | ||||
Operating revenues | $ 980,000 | $ 915,000 | $ 1,663,000 | $ 1,563,000 |
Revenue - Allowance for Doubtfu
Revenue - Allowance for Doubtful Accounts (Details) - USD ($) $ in Thousands | 6 Months Ended | 12 Months Ended |
Jun. 30, 2021 | Dec. 31, 2020 | |
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | ||
Allowance for doubtful accounts, balance at beginning of period | $ 19,782 | $ 8,171 |
Bad debt expense | 10,048 | 20,633 |
Actual write-offs | (7,061) | (9,022) |
Allowance for doubtful accounts, balance at end of period | $ 22,769 | $ 19,782 |
Long-Term Debt and Liquidity _3
Long-Term Debt and Liquidity Matters - Narrative (Details) | 6 Months Ended | |||||
Jun. 30, 2021USD ($)Facility | May 27, 2021USD ($)Facility | Dec. 23, 2020USD ($) | Dec. 17, 2020USD ($) | May 05, 2020USD ($) | May 04, 2020USD ($) | |
Long-Term Debt and Liquidity Matters | ||||||
Percentage of capitalization | 7.00% | |||||
Capacity available for trade purchases | $ 500,000,000 | |||||
Term Loan | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Debt instrument, face amount | $ 150,000,000 | |||||
Pinnacle West | Revolving Credit Facility | Revolving Credit Facility Maturing July 2023 | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Current borrowing capacity on credit facility | $ 200,000,000 | |||||
Pinnacle West | Revolving Credit Facility | Revolving Credit Facility Maturing May 2026 | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Long-term line of credit | $ 0 | |||||
Current borrowing capacity on credit facility | 200,000,000 | |||||
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to) | 300,000,000 | |||||
Pinnacle West | Letter of Credit | Revolving Credit Facility Maturing May 2026 | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Outstanding letters of credit | 0 | |||||
Pinnacle West | Commercial paper | Revolving Credit Facility Maturing May 2026 | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Commercial paper | $ 9,700,000 | |||||
Pinnacle West | Term Loan | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Debt instrument, face amount | $ 31,000,000 | $ 50,000,000 | ||||
Variable rate | 1.40% | |||||
APS | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Long-term debt limit | $ 7,500,000,000 | |||||
APS | Revolving Credit Facility | Revolving Credit Facility Maturing July 2023 | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Current borrowing capacity on credit facility | $ 500,000,000 | |||||
APS | Revolving Credit Facility | Revolving Credit Facility Maturing May 2026 | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Current borrowing capacity on credit facility | $ 1,000,000,000 | |||||
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to) | $ 1,400,000,000 | |||||
Number of line of credit facilities | Facility | 2 | |||||
APS | Revolving Credit Facility | Revolving Credit Facility Maturing in 2022 and 2023 | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Long-term line of credit | $ 0 | |||||
Number of line of credit facilities | Facility | 2 | |||||
APS | Revolving Credit Facility | Revolving Credit Facility Maturing June 2022 | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Current borrowing capacity on credit facility | $ 500,000,000 | |||||
APS | Revolving Credit Facility | Revolving Credit Facility Maturing May 2026, Facility One | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Current borrowing capacity on credit facility | 500,000,000 | |||||
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to) | 700,000,000 | |||||
APS | Revolving Credit Facility | Revolving Credit Facility Maturing May 2026, Facility Two | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Current borrowing capacity on credit facility | 500,000,000 | |||||
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to) | 700,000,000 | |||||
APS | Letter of Credit | Revolving Credit Facility Maturing in 2022 and 2023 | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Outstanding letters of credit | 0 | |||||
APS | Commercial paper | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Maximum commercial paper support available under credit facility | 750,000,000 | |||||
APS | Commercial paper | Revolving Credit Facility Maturing in 2022 and 2023 | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Commercial paper | $ 495,000,000 |
Long-Term Debt and Liquidity _4
Long-Term Debt and Liquidity Matters - Estimated Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands | Jun. 30, 2021 | Dec. 31, 2020 |
Estimated fair value of long-term debt, including current maturities | ||
Carrying Amount | $ 6,465,927 | $ 6,314,266 |
Fair Value | 7,401,079 | 7,612,841 |
APS | ||
Estimated fair value of long-term debt, including current maturities | ||
Carrying Amount | 5,819,198 | 5,817,945 |
Fair Value | 6,746,984 | 7,103,791 |
Pinnacle West | ||
Estimated fair value of long-term debt, including current maturities | ||
Carrying Amount | 646,729 | 496,321 |
Fair Value | $ 654,095 | $ 509,050 |
Regulatory Matters - COVID-19 (
Regulatory Matters - COVID-19 (Details) - APS - USD ($) | Jan. 21, 2021 | Mar. 31, 2021 | Feb. 28, 2021 | Dec. 31, 2020 | Jun. 30, 2021 | May 05, 2020 |
Public Utilities, General Disclosures [Line Items] | ||||||
Percentage increase under PSA effective for first billing cycle beginning April 2021 | 50.00% | 50.00% | ||||
Remaining percentage increase under PSA effective for first billing cycle beginning November 2021 | 50.00% | 50.00% | ||||
Demand side management funds | $ 36,000,000 | |||||
Customer credits | $ 43,000,000 | |||||
Customer credits, additional funds | $ 7,000,000 | |||||
Voluntary funds | $ 15,000,000 | |||||
Customer COVID assistance | 12,400,000 | |||||
Non-customer funds | 8,800,000 | |||||
Bill credits for limited income customers | $ 3,600,000 | |||||
Threshold percentage for deferral of potential recovery | 50.00% | |||||
Threshold for deferral of potential recovery | $ 2,500,000 | |||||
Customer support fund, bill credit | 100 | |||||
Expanded credit for limited income customers | 300 | |||||
Customer assistance, small customers, bill credit | 1,000 | |||||
Additional bill credit for delinquent limited income customers | 250 | |||||
Customer support fund, non-profits and community organizations | $ 2,700,000 | |||||
Damage from Fire, Explosion or Other Hazard | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Customer support fund, payment period | 8 months | |||||
Past due balance threshold qualifying for payment extension | $ 75 |
Regulatory Matters - Retail Rat
Regulatory Matters - Retail Rate Case Filing (Details) | Aug. 02, 2021USD ($) | Nov. 06, 2020USD ($) | Oct. 02, 2020USD ($) | Oct. 31, 2019USD ($)$ / kWhGW | Jun. 30, 2019USD ($) | Aug. 13, 2018USD ($) | Jan. 08, 2018USD ($) | Mar. 27, 2017USD ($)$ / kWh | Dec. 31, 2020USD ($) | Dec. 04, 2020USD ($) |
ACC | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Revenue increase (decrease) | $ 169,000,000 | $ 89,700,000 | $ 59,800,000 | |||||||
Average annual customer bill increase (decrease), percent | 5.14% | 2.70% | 1.82% | |||||||
Recommended return on equity, percentage | 10.00% | 9.40% | ||||||||
Alternative, percentage | 0.30% | |||||||||
Increment of fair value rate, percentage | 0.80% | 0.00% | ||||||||
Residential Utility Consumer Office | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Revenue increase (decrease) | $ (20,800,000) | $ (50,100,000) | ||||||||
Average annual customer bill increase (decrease), percent | (0.63%) | (1.52%) | ||||||||
Recommended return on equity, percentage | 8.74% | |||||||||
Increment of fair value rate, percentage | 0.00% | |||||||||
ACC | APS | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Proposed annual revenue increase | $ 184,000,000 | $ (86,500,000) | $ (119,100,000) | |||||||
Retail Rate Case Filing with Arizona Corporation Commission | ACC | APS | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Base rate decrease, elimination of tax expense adjustment mechanism | $ 115,000,000 | |||||||||
Approximate percentage of increase in average customer bill | 5.60% | 3.28% | ||||||||
Approximate percentage of increase in average residential customer bill | 5.40% | 4.54% | ||||||||
Rate matter, cost base rate | $ 8,870,000,000 | |||||||||
Base fuel rate (in dollars per kWh) | $ / kWh | 0.030168 | |||||||||
Funding limited income crisis bill program | $ 1,250,000 | |||||||||
Commercial customers, market pricing, threshold | GW | 0.02 | |||||||||
Expenses from recovery of deferral and rate base effects | $ 110,000,000 | |||||||||
Net retail base rate, increase | $ 94,600,000 | |||||||||
Non-fuel and non-depreciation base rate, increase | 87,200,000 | |||||||||
Fuel-related base rate decrease | 53,600,000 | |||||||||
Base rate increase, changes in depreciation schedules | $ 61,000,000 | |||||||||
Authorized return on common equity (as a percent) | 10.00% | |||||||||
Percentage of debt in capital structure | 44.20% | |||||||||
Percentage of common equity in capital structure | 55.80% | |||||||||
Rate matter, resource comparison proxy for exported energy (in dollars per kWh) | $ / kWh | 0.129 | |||||||||
Retail Rate Case Filing with Arizona Corporation Commission | ACC | APS | Subsequent Event | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Revenue increase (decrease) | $ (111,000,000) | |||||||||
Recommended return on equity, percentage | 9.16% | |||||||||
Increment of fair value rate, percentage | 0.15% | |||||||||
Reduction on equity percentage | 0.10% | |||||||||
Effective fair value percentage | 0.05% | |||||||||
AZ Sun Program Phase 2 | Retail Rate Case Filing with Arizona Corporation Commission | ACC | APS | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public utilities, minimum annual renewable energy standard and tariff | $ 10,000,000 | |||||||||
Public utilities, maximum annual renewable energy standard and tariff | $ 15,000,000 | |||||||||
Coal Community Transition Plan | ACC | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Amount funded by customers | $ 100,000,000 | |||||||||
Amount funded by customers, term | 10 years | |||||||||
Amount funded by shareholders | $ 25,000,000 | $ 25,000,000 | ||||||||
Coal Community Transition Plan | ACC | Navajo Nation, Economic Development Organization | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Amount funded by shareholders | $ 1,250,000 | |||||||||
Amount funded by shareholders, term | 5 years | |||||||||
Coal Community Transition Plan | ACC | Navajo Nation, Electrification Projects | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Amount funded by customers | $ 10,000,000 | |||||||||
Amount funded by shareholders | 10,000,000 | |||||||||
Coal Community Transition Plan | ACC | Navajo Nation, Transmission Revenue Sharing | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Amount funded by shareholders | 2,500,000 | |||||||||
Coal Community Transition Plan | ACC | Navajo County Communities, Cholla Power Plant Closure | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Amount funded by customers | $ 12,000,000 | |||||||||
Amount funded by customers, term | 5 years | |||||||||
Coal Community Transition Plan | ACC | Navajo Nation, Generation Station | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Amount funded by customers | $ 3,700,000 | |||||||||
Coal Community Transition Plan | Retail Rate Case Filing with Arizona Corporation Commission | ACC | APS | Navajo Nation, Economic Development Organization | Subsequent Event | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Disallowance of annual amortization percentage | 15.00% | |||||||||
Amount funded by customers | $ 50,000,000 | |||||||||
Amount funded by customers, term | 10 years | |||||||||
Coal Community Transition Plan | Retail Rate Case Filing with Arizona Corporation Commission | ACC | APS | Navajo County Communities, Cholla Power Plant Closure | Subsequent Event | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Amount funded by shareholders | $ 5,000,000 | |||||||||
Amount funded by shareholders, term | 5 years | |||||||||
Coal Community Transition Plan | Retail Rate Case Filing with Arizona Corporation Commission | ACC | APS | Navajo Nation, Hopi Tribe | Subsequent Event | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Amount funded by shareholders | $ 1,675,000 | |||||||||
Minimum | ACC | APS | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Annual increase in retail base rates | $ 69,000,000 | |||||||||
Minimum | Retail Rate Case Filing with Arizona Corporation Commission | ACC | APS | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Rate matter, environmental surcharge cap rate (in dollars per kWh) | $ / kWh | 0.00016 | |||||||||
Maximum | Retail Rate Case Filing with Arizona Corporation Commission | ACC | APS | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Rate matter, environmental surcharge cap rate (in dollars per kWh) | $ / kWh | 0.00050 |
Regulatory Matters - Capital St
Regulatory Matters - Capital Structure and Costs of Capital (Details) - APS - $ / kWh | Oct. 01, 2021 | May 01, 2020 | Oct. 31, 2019 | May 01, 2019 |
Cost of Capital | ||||
Long-term debt | 4.10% | |||
Common stock equity | 10.15% | |||
Weighted-average cost of capital | 7.41% | |||
Retail Rate Case Filing with Arizona Corporation Commission | ||||
Capital Structure | ||||
Common stock equity | 54.70% | |||
Retail Rate Case Filing with Arizona Corporation Commission | ACC | ||||
Capital Structure | ||||
Long-term debt | 45.30% | |||
Net Metering | ACC | ||||
Cost of Capital | ||||
Second-year export energy price (in dollars per kWh) | 0.094 | 0.105 | ||
Net Metering | ACC | Forecast | ||||
Cost of Capital | ||||
Second-year export energy price (in dollars per kWh) | 0.105 |
Regulatory Matters - Cost Recov
Regulatory Matters - Cost Recovery Mechanisms (Details) | Nov. 01, 2021$ / kWh | Oct. 01, 2021$ / kWh | Jun. 07, 2021USD ($) | Jun. 01, 2021USD ($) | Apr. 01, 2021$ / kWh | Feb. 22, 2021USD ($) | Feb. 15, 2021USD ($) | Feb. 01, 2021USD ($)$ / kWh | Aug. 20, 2020USD ($)Customer | Jun. 01, 2020USD ($) | May 01, 2020$ / kWh | Feb. 14, 2020USD ($) | Feb. 01, 2020$ / kWh | Nov. 14, 2019USD ($)Customer | Oct. 31, 2019USD ($) | Oct. 29, 2019USD ($) | Jun. 01, 2019USD ($) | May 01, 2019$ / kWh | Apr. 10, 2019 | Feb. 15, 2019USD ($) | Feb. 01, 2019$ / kWh | Aug. 13, 2018USD ($) | Feb. 15, 2018USD ($) | Feb. 01, 2018$ / kWh | Jan. 08, 2018USD ($) | Nov. 20, 2017USD ($) | Sep. 01, 2017USD ($)$ / kWh | Mar. 31, 2021 | Feb. 28, 2021 | Jun. 30, 2021USD ($) | Jun. 30, 2020USD ($) | Dec. 31, 2020USD ($)programMW | Dec. 31, 2017$ / kWh | Jul. 01, 2021USD ($) | Jul. 01, 2020USD ($) | May 15, 2020USD ($) | May 05, 2020USD ($) | Dec. 31, 2019USD ($) | Jul. 01, 2019USD ($) | Mar. 15, 2019agreement | Dec. 31, 2018USD ($) | Nov. 14, 2017USD ($) |
Change in regulatory asset | ||||||||||||||||||||||||||||||||||||||||||
Deferred fuel and purchased power costs — current period | $ 135,905,000 | $ 26,473,000 | ||||||||||||||||||||||||||||||||||||||||
Amounts (charged) refunded to customers | (10,828,000) | 4,815,000 | ||||||||||||||||||||||||||||||||||||||||
Rate plan comparison tool, number of customers | Customer | 3,800 | 13,000 | ||||||||||||||||||||||||||||||||||||||||
Rate plan comparison tool, inconvenience payment | $ 25 | $ 25 | ||||||||||||||||||||||||||||||||||||||||
APS | ||||||||||||||||||||||||||||||||||||||||||
Change in regulatory asset | ||||||||||||||||||||||||||||||||||||||||||
Deferred fuel and purchased power costs — current period | 135,905,000 | 26,473,000 | ||||||||||||||||||||||||||||||||||||||||
Amounts (charged) refunded to customers | (10,828,000) | 4,815,000 | ||||||||||||||||||||||||||||||||||||||||
Percentage increase under PSA effective for first billing cycle beginning April 2021 | 50.00% | 50.00% | ||||||||||||||||||||||||||||||||||||||||
Remaining percentage increase under PSA effective for first billing cycle beginning November 2021 | 50.00% | 50.00% | ||||||||||||||||||||||||||||||||||||||||
Demand side management funds | $ 36,000,000 | |||||||||||||||||||||||||||||||||||||||||
Customer credits | 43,000,000 | |||||||||||||||||||||||||||||||||||||||||
Customer credits, additional funds | $ 7,000,000 | |||||||||||||||||||||||||||||||||||||||||
APS | 2017 Settlement Agreement and its Customer Education and Outreach Plan | ||||||||||||||||||||||||||||||||||||||||||
Change in regulatory asset | ||||||||||||||||||||||||||||||||||||||||||
Settlement amount | $ 24,750,000 | |||||||||||||||||||||||||||||||||||||||||
Settlement amount returned to customers | $ 24,000,000 | |||||||||||||||||||||||||||||||||||||||||
Lost Fixed Cost Recovery Mechanisms | APS | ||||||||||||||||||||||||||||||||||||||||||
Change in regulatory asset | ||||||||||||||||||||||||||||||||||||||||||
Fixed cost recoverable per power lost (in dollars per kWh) | $ / kWh | 0.025 | |||||||||||||||||||||||||||||||||||||||||
Percentage of retail revenues | 1.00% | |||||||||||||||||||||||||||||||||||||||||
Amount of adjustment representing prorated sales losses pending approval | $ 38,500,000 | $ 26,600,000 | $ 36,200,000 | $ 60,700,000 | ||||||||||||||||||||||||||||||||||||||
Increase (decrease) in amount of adjustment representing prorated sales losses | $ 11,800,000 | $ (9,600,000) | $ (24,500,000) | |||||||||||||||||||||||||||||||||||||||
ACC | APS | ||||||||||||||||||||||||||||||||||||||||||
Settlement Agreement | ||||||||||||||||||||||||||||||||||||||||||
Program term | 18 years | |||||||||||||||||||||||||||||||||||||||||
Change in regulatory asset | ||||||||||||||||||||||||||||||||||||||||||
Gross-up for revenue requirement of rate regulation | $ (184,000,000) | $ 86,500,000 | $ 119,100,000 | |||||||||||||||||||||||||||||||||||||||
Deferred taxes amortization, period | 28 years 6 months | |||||||||||||||||||||||||||||||||||||||||
Public Utilities, one-time bill credit | $ 64,000,000 | |||||||||||||||||||||||||||||||||||||||||
Public Utilities, one-time bill credit, additional benefit | $ 39,500,000 | |||||||||||||||||||||||||||||||||||||||||
Number of programs | program | 2 | |||||||||||||||||||||||||||||||||||||||||
Solar power capacity (in MW) | MW | 80 | |||||||||||||||||||||||||||||||||||||||||
ACC | RES | APS | ||||||||||||||||||||||||||||||||||||||||||
Settlement Agreement | ||||||||||||||||||||||||||||||||||||||||||
Plan term | 5 years | |||||||||||||||||||||||||||||||||||||||||
ACC | RES 2018 | APS | ||||||||||||||||||||||||||||||||||||||||||
Settlement Agreement | ||||||||||||||||||||||||||||||||||||||||||
Amount of proposed budget | $ 93,100,000 | $ 84,700,000 | $ 86,300,000 | |||||||||||||||||||||||||||||||||||||||
Revenue requirements | $ 4,500,000 | |||||||||||||||||||||||||||||||||||||||||
Authorized amount to be collected | $ 68,300,000 | |||||||||||||||||||||||||||||||||||||||||
ACC | RES 2018 | APS | Solar Communities | ||||||||||||||||||||||||||||||||||||||||||
Settlement Agreement | ||||||||||||||||||||||||||||||||||||||||||
Program term | 3 years | |||||||||||||||||||||||||||||||||||||||||
ACC | Demand Side Management Adjustor Charge 2018 | APS | ||||||||||||||||||||||||||||||||||||||||||
Settlement Agreement | ||||||||||||||||||||||||||||||||||||||||||
Amount of proposed budget | $ 52,600,000 | $ 52,600,000 | ||||||||||||||||||||||||||||||||||||||||
ACC | Demand Side Management Adjustor Charge 2019 | APS | ||||||||||||||||||||||||||||||||||||||||||
Settlement Agreement | ||||||||||||||||||||||||||||||||||||||||||
Amount of proposed budget | $ 34,100,000 | |||||||||||||||||||||||||||||||||||||||||
ACC | Demand Side Management Adjustor Charge 2020 | APS | ||||||||||||||||||||||||||||||||||||||||||
Settlement Agreement | ||||||||||||||||||||||||||||||||||||||||||
Amount of proposed budget | $ 51,900,000 | $ 51,900,000 | ||||||||||||||||||||||||||||||||||||||||
ACC | Power Supply Adjustor (PSA) | APS | ||||||||||||||||||||||||||||||||||||||||||
Change in regulatory asset | ||||||||||||||||||||||||||||||||||||||||||
Beginning balance | $ 175,835,000 | 70,137,000 | $ 70,137,000 | |||||||||||||||||||||||||||||||||||||||
Deferred fuel and purchased power costs — current period | 135,905,000 | 26,473,000 | ||||||||||||||||||||||||||||||||||||||||
Amounts (charged) refunded to customers | (10,828,000) | 4,815,000 | ||||||||||||||||||||||||||||||||||||||||
Ending balance | $ 300,912,000 | $ 101,425,000 | 175,835,000 | |||||||||||||||||||||||||||||||||||||||
PSA rate (in dollars per kWh) | $ / kWh | 0.001544 | 0.003544 | (0.000456) | 0.001658 | 0.004555 | |||||||||||||||||||||||||||||||||||||
PSA rate for prior year (in dollars per kWh) | $ / kWh | (0.004444) | 0.003434 | (0.002086) | 0.000536 | ||||||||||||||||||||||||||||||||||||||
Forward component of increase in PSA (in dollars per kWh) | $ / kWh | 0.005988 | 0.000110 | 0.001630 | 0.001122 | ||||||||||||||||||||||||||||||||||||||
Fuel and purchased power costs above annual cap | $ 215,900,000 | |||||||||||||||||||||||||||||||||||||||||
ACC | Net Metering | APS | ||||||||||||||||||||||||||||||||||||||||||
Change in regulatory asset | ||||||||||||||||||||||||||||||||||||||||||
Cost of service, resource comparison proxy method, maximum annual percentage decrease | 10.00% | |||||||||||||||||||||||||||||||||||||||||
Cost of service for interconnected DG system customers, grandfathered period | 20 years | |||||||||||||||||||||||||||||||||||||||||
Cost of service for new customers, guaranteed export price period | 10 years | |||||||||||||||||||||||||||||||||||||||||
First-year export energy price (in dollars per kWh) | $ / kWh | 0.129 | |||||||||||||||||||||||||||||||||||||||||
Second-year export energy price (in dollars per kWh) | $ / kWh | 0.094 | 0.105 | ||||||||||||||||||||||||||||||||||||||||
ACC | Demand Side Management Adjustor Charge 2021 | APS | ||||||||||||||||||||||||||||||||||||||||||
Settlement Agreement | ||||||||||||||||||||||||||||||||||||||||||
Amount of proposed budget | $ 63,700,000 | |||||||||||||||||||||||||||||||||||||||||
FERC | Environmental Improvement Surcharge | APS | ||||||||||||||||||||||||||||||||||||||||||
Change in regulatory asset | ||||||||||||||||||||||||||||||||||||||||||
Increase (decrease) in annual wholesale transmission rates | 10,300,000 | |||||||||||||||||||||||||||||||||||||||||
Rate matters, increase (decrease) in cost recovery, excess of annual amount | $ 1,500,000 | |||||||||||||||||||||||||||||||||||||||||
FERC | Open Access Transmission Tariff | APS | ||||||||||||||||||||||||||||||||||||||||||
Change in regulatory asset | ||||||||||||||||||||||||||||||||||||||||||
Increase (decrease) in annual wholesale transmission rates | $ 4,000,000 | $ (6,100,000) | $ 25,800,000 | |||||||||||||||||||||||||||||||||||||||
Increase (decrease) in wholesale customer rates | (3,200,000) | 4,800,000 | 21,100,000 | |||||||||||||||||||||||||||||||||||||||
Increase (decrease) in retail customer rates | 7,200,000 | (10,900,000) | 4,700,000 | |||||||||||||||||||||||||||||||||||||||
Increase (decrease) in retail revenue requirements | $ (28,400,000) | $ (7,400,000) | $ 4,900,000 | |||||||||||||||||||||||||||||||||||||||
Cost Recovery Mechanisms | ACC | Power Supply Adjustor (PSA) | APS | ||||||||||||||||||||||||||||||||||||||||||
Change in regulatory asset | ||||||||||||||||||||||||||||||||||||||||||
Historical component of increase in PSA (in dollars per kWh) | $ / kWh | 0.004 | (0.002115) | (0.002897) | |||||||||||||||||||||||||||||||||||||||
Cost recovery, number of agreements | agreement | 2 | |||||||||||||||||||||||||||||||||||||||||
Forecast | ACC | Power Supply Adjustor (PSA) | APS | ||||||||||||||||||||||||||||||||||||||||||
Change in regulatory asset | ||||||||||||||||||||||||||||||||||||||||||
PSA rate (in dollars per kWh) | $ / kWh | 0.003544 | |||||||||||||||||||||||||||||||||||||||||
PSA rate for prior year (in dollars per kWh) | $ / kWh | (0.004444) | |||||||||||||||||||||||||||||||||||||||||
Forward component of increase in PSA (in dollars per kWh) | $ / kWh | 0.007988 | |||||||||||||||||||||||||||||||||||||||||
Forecast | ACC | Net Metering | APS | ||||||||||||||||||||||||||||||||||||||||||
Change in regulatory asset | ||||||||||||||||||||||||||||||||||||||||||
Second-year export energy price (in dollars per kWh) | $ / kWh | 0.105 | |||||||||||||||||||||||||||||||||||||||||
Minimum | ACC | APS | ||||||||||||||||||||||||||||||||||||||||||
Change in regulatory asset | ||||||||||||||||||||||||||||||||||||||||||
Operating results | $ (69,000,000) | |||||||||||||||||||||||||||||||||||||||||
Minimum | ACC | RES 2018 | APS | Solar Communities | ||||||||||||||||||||||||||||||||||||||||||
Settlement Agreement | ||||||||||||||||||||||||||||||||||||||||||
Required annual capital investment | $ 10,000,000 | |||||||||||||||||||||||||||||||||||||||||
Maximum | ACC | RES 2018 | APS | Solar Communities | ||||||||||||||||||||||||||||||||||||||||||
Settlement Agreement | ||||||||||||||||||||||||||||||||||||||||||
Required annual capital investment | $ 15,000,000 |
Regulatory Matters - Four Corne
Regulatory Matters - Four Corners, Cholla and Navajo Plant (Details) - APS - USD ($) $ in Millions | Aug. 02, 2021 | Jun. 30, 2021 | Sep. 30, 2018 | Apr. 30, 2018 |
Subsequent Event | Navajo Nation, Economic Development Organization | Coal Community Transition Plan | Retail Rate Case Filing with Arizona Corporation Commission | ACC | ||||
Business Acquisition [Line Items] | ||||
Disallowance of annual amortization percentage | 15.00% | |||
SCE | Four Corners Units 4 and 5 | ||||
Business Acquisition [Line Items] | ||||
Settlement agreement, ACC approved rate adjustment, annualized customer impact | $ 58.5 | $ 67.5 | ||
Estimated write-off of cost deferrals | $ 75 | |||
SCR plant investments | 320 | |||
SCE | Four Corners Units 4 and 5 | Subsequent Event | ||||
Business Acquisition [Line Items] | ||||
Disallowance of plant investments | $ 399 | |||
Cost deferrals | $ 61 | |||
Retired power plant costs | ||||
Business Acquisition [Line Items] | ||||
Net book value | 48.9 | |||
Navajo Plant | ||||
Business Acquisition [Line Items] | ||||
Net book value | 67 | |||
Navajo Plant, Coal Reclamation Regulatory Asset | ||||
Business Acquisition [Line Items] | ||||
Net book value | $ 17.5 |
Regulatory Matters - Schedule o
Regulatory Matters - Schedule of Regulatory Assets (Details) - USD ($) $ in Thousands | Jun. 30, 2021 | Dec. 31, 2020 |
Detail of regulatory assets | ||
Current | $ 420,802 | $ 291,713 |
Non-Current | 1,173,977 | 1,133,987 |
Pension | ||
Detail of regulatory assets | ||
Current | 0 | 0 |
Non-Current | 496,372 | 469,953 |
Deferred fuel and purchased power | ||
Detail of regulatory assets | ||
Current | 300,912 | 175,835 |
Non-Current | 0 | 0 |
Income taxes — allowance for funds used during construction (“AFUDC”) equity | ||
Detail of regulatory assets | ||
Current | 7,169 | 7,169 |
Non-Current | 161,279 | 158,776 |
Retired power plant costs | ||
Detail of regulatory assets | ||
Current | 28,182 | 28,181 |
Non-Current | 100,123 | 114,214 |
Ocotillo deferral | ||
Detail of regulatory assets | ||
Current | 0 | 0 |
Non-Current | 124,919 | 95,723 |
SCR deferral | ||
Detail of regulatory assets | ||
Current | 0 | 0 |
Non-Current | 95,171 | 81,307 |
Deferred property taxes | ||
Detail of regulatory assets | ||
Current | 8,569 | 8,569 |
Non-Current | 45,342 | 49,626 |
Lost fixed cost recovery | ||
Detail of regulatory assets | ||
Current | 53,087 | 41,807 |
Non-Current | 0 | 0 |
Deferred compensation | ||
Detail of regulatory assets | ||
Current | 0 | 0 |
Non-Current | 35,806 | 36,195 |
Four Corners cost deferral | ||
Detail of regulatory assets | ||
Current | 8,077 | 8,077 |
Non-Current | 20,037 | 24,075 |
Income taxes — investment tax credit basis adjustment | ||
Detail of regulatory assets | ||
Current | 1,113 | 1,113 |
Non-Current | 23,807 | 24,291 |
Palo Verde VIEs (Note 6) | ||
Detail of regulatory assets | ||
Current | 0 | 0 |
Non-Current | 21,174 | 21,255 |
Coal reclamation | ||
Detail of regulatory assets | ||
Current | 1,068 | 1,068 |
Non-Current | 16,465 | 16,999 |
Loss on reacquired debt | ||
Detail of regulatory assets | ||
Current | 1,648 | 1,689 |
Non-Current | 10,128 | 10,877 |
Mead-Phoenix transmission line contributions in aid of construction (“CIAC”) | ||
Detail of regulatory assets | ||
Current | 332 | 332 |
Non-Current | 9,214 | 9,380 |
Tax expense adjustor mechanism | ||
Detail of regulatory assets | ||
Current | 7,956 | 6,226 |
Non-Current | 0 | 0 |
Demand side management | ||
Detail of regulatory assets | ||
Current | 0 | 0 |
Non-Current | 7,269 | 7,268 |
Tax expense of Medicare subsidy | ||
Detail of regulatory assets | ||
Current | 1,235 | 1,235 |
Non-Current | 3,167 | 3,704 |
TCA balancing account | ||
Detail of regulatory assets | ||
Current | 0 | 0 |
Non-Current | 1,903 | 0 |
Deferred fuel and purchased power — mark-to-market (Note 7) | ||
Detail of regulatory assets | ||
Current | 0 | 3,341 |
Non-Current | 0 | 9,244 |
PSA Interest | ||
Detail of regulatory assets | ||
Current | 133 | 4,355 |
Non-Current | 0 | 0 |
Other | ||
Detail of regulatory assets | ||
Current | 1,321 | 2,716 |
Non-Current | $ 1,801 | $ 1,100 |
Regulatory Matters - Schedule_2
Regulatory Matters - Schedule of Regulatory Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Jun. 30, 2021 | Dec. 31, 2020 |
Detail of regulatory liabilities | |||
Current | $ 327,612 | $ 229,088 | |
Non-Current | 2,443,312 | 2,450,169 | |
Asset retirement obligations | |||
Detail of regulatory liabilities | |||
Current | 0 | 0 | |
Non-Current | 567,900 | 506,049 | |
Other postretirement benefits | |||
Detail of regulatory liabilities | |||
Current | 47,798 | 37,705 | |
Non-Current | 314,218 | 349,588 | |
Removal costs | |||
Detail of regulatory liabilities | |||
Current | 69,348 | 52,844 | |
Non-Current | 61,601 | 103,008 | |
Deferred fuel and purchased power — mark-to-market (Note 7) | |||
Detail of regulatory liabilities | |||
Current | 82,082 | 0 | |
Non-Current | 27,305 | 0 | |
Income taxes — change in rates | |||
Detail of regulatory liabilities | |||
Current | 2,839 | 2,839 | |
Non-Current | 65,319 | 66,553 | |
Four Corners coal reclamation | |||
Detail of regulatory liabilities | |||
Current | 5,461 | 5,460 | |
Non-Current | 49,904 | 49,435 | |
Income taxes — deferred investment tax credit | |||
Detail of regulatory liabilities | |||
Current | 2,231 | 2,231 | |
Non-Current | 47,677 | 48,648 | |
Spent nuclear fuel | |||
Detail of regulatory liabilities | |||
Current | 6,510 | 6,768 | |
Non-Current | 41,815 | 44,221 | |
Renewable energy standard | |||
Detail of regulatory liabilities | |||
Current | 30,665 | 39,442 | |
Non-Current | 0 | 103 | |
Property tax deferral | |||
Detail of regulatory liabilities | |||
Current | 0 | 0 | |
Non-Current | 16,188 | 13,856 | |
Demand side management | |||
Detail of regulatory liabilities | |||
Current | 3,149 | 10,819 | |
Non-Current | 12,457 | 0 | |
Sundance maintenance | |||
Detail of regulatory liabilities | |||
Current | 556 | 2,989 | |
Non-Current | 12,312 | 11,508 | |
FERC transmission true up | |||
Detail of regulatory liabilities | |||
Current | 7,547 | 6,598 | |
Non-Current | 3,511 | 3,008 | |
TCA balancing account | |||
Detail of regulatory liabilities | |||
Current | 10,750 | 2,902 | |
Non-Current | 159 | 4,672 | |
Tax expense adjustor mechanism | |||
Detail of regulatory liabilities | |||
Current | 7,148 | 7,089 | |
Non-Current | 0 | 0 | |
Tax expense adjustor mechanism | Forecast | |||
Detail of regulatory liabilities | |||
Current | $ 7,000 | ||
Deferred gains on utility property | |||
Detail of regulatory liabilities | |||
Current | 2,423 | 2,423 | |
Non-Current | 333 | 1,544 | |
Active union medical trust | |||
Detail of regulatory liabilities | |||
Current | 0 | 0 | |
Non-Current | 2,347 | 6,057 | |
Other | |||
Detail of regulatory liabilities | |||
Current | 484 | 409 | |
Non-Current | 289 | 189 | |
ACC | Excess deferred income taxes - Tax Act | |||
Detail of regulatory liabilities | |||
Current | 41,381 | 41,330 | |
Non-Current | 993,982 | 1,012,583 | |
FERC | Excess deferred income taxes - Tax Act | |||
Detail of regulatory liabilities | |||
Current | 7,240 | 7,240 | |
Non-Current | $ 225,995 | $ 229,147 |
Retirement Plans and Other Po_3
Retirement Plans and Other Postretirement Benefits - Narrative (Details) - USD ($) | Jan. 04, 2021 | Jun. 30, 2021 | Dec. 31, 2020 | Dec. 31, 2019 |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Initial pre-65 ultimate health care cost trend rate (as a percent) | 4.75% | |||
Initial post-65 healthcare cost trend rate (as a percent) | 2.00% | |||
Transfer to active union medical account | $ (106,000,000) | |||
Contributions | ||||
Expected voluntary employer contributions in the next fiscal year | $ 0 | |||
Expected voluntary employer contributions in the year after next fiscal year | 0 | |||
Other Benefits | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Transfer to active union medical account | 106,000,000 | |||
Contributions | ||||
Estimated future employer contributions in next three years | 0 | |||
Pension Benefits | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Transfer to active union medical account | $ (106,000,000) | |||
Contributions | ||||
Voluntary contributions | 0 | |||
Minimum employer contributions for the next three years | 0 | |||
Expected voluntary employer contributions in the remainder of the current fiscal year | $ 100,000,000 |
Retirement Plans and Other Po_4
Retirement Plans and Other Postretirement Benefits - Schedule of Net Benefit Cost (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2021 | Jun. 30, 2020 | Jun. 30, 2021 | Jun. 30, 2020 | |
Amortization of: | ||||
Portion of cost/(benefit) charged to expense | $ (28,175) | $ (14,142) | $ (55,966) | $ (28,053) |
Pension Benefits | ||||
Retirement Plans and Other Benefits | ||||
Service cost — benefits earned during the period | 14,939 | 13,859 | 30,618 | 28,116 |
Interest cost on benefit obligation | 24,614 | 29,522 | 49,283 | 59,283 |
Expected return on plan assets | (50,706) | (46,915) | (101,314) | (93,721) |
Amortization of: | ||||
Prior service credit | 0 | 0 | 0 | 0 |
Net actuarial loss (gain) | 3,989 | 8,295 | 7,974 | 17,306 |
Net periodic benefit cost/(benefit) | (7,164) | 4,761 | (13,439) | 10,984 |
Portion of cost/(benefit) charged to expense | (8,614) | 271 | (16,625) | 1,613 |
Other Benefits | ||||
Retirement Plans and Other Benefits | ||||
Service cost — benefits earned during the period | 4,341 | 5,401 | 8,898 | 11,118 |
Interest cost on benefit obligation | 4,095 | 6,417 | 8,257 | 12,929 |
Expected return on plan assets | (10,361) | (10,019) | (20,722) | (20,038) |
Amortization of: | ||||
Prior service credit | (9,427) | (9,394) | (18,854) | (18,788) |
Net actuarial loss (gain) | (2,641) | 0 | (5,046) | 0 |
Net periodic benefit cost/(benefit) | (13,993) | (7,595) | (27,467) | (14,779) |
Portion of cost/(benefit) charged to expense | $ (9,608) | $ (5,056) | $ (19,136) | $ (10,512) |
Palo Verde Sale Leaseback Var_3
Palo Verde Sale Leaseback Variable Interest Entities - Narrative (Details) | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2021USD ($)power_plant | Jun. 30, 2020USD ($) | Jun. 30, 2021USD ($)power_plantLease | Jun. 30, 2020USD ($) | Dec. 31, 1986Trust | |
Palo Verde Sale Leaseback Variable Interest Entities | |||||
Net income attributable to noncontrolling interests | $ 3,739,000 | $ 4,874,000 | $ 8,612,000 | $ 9,747,000 | |
APS | |||||
Palo Verde Sale Leaseback Variable Interest Entities | |||||
Number of VIE lessor trusts | 3 | 3 | 3 | ||
Net income attributable to noncontrolling interests | $ 3,739,000 | 4,874,000 | $ 8,612,000 | 9,747,000 | |
Palo Verde VIE | APS | |||||
Palo Verde Sale Leaseback Variable Interest Entities | |||||
Net income attributable to noncontrolling interests | $ 4,000,000 | $ 5,000,000 | 9,000,000 | $ 10,000,000 | |
Initial loss exposure to the VIE's noncontrolling equity participants during lease extension period | 307,000,000 | ||||
Maximum loss exposure to the VIE's noncontrolling equity participants during lease extension period | $ 501,000,000 | ||||
Palo Verde VIE | APS | Period through 2023 | |||||
Palo Verde Sale Leaseback Variable Interest Entities | |||||
Number of leases under which assets are retained | Lease | 1 | ||||
Palo Verde VIE | APS | Period through 2033 | |||||
Palo Verde Sale Leaseback Variable Interest Entities | |||||
Number of leases under which assets are retained | Lease | 2 | ||||
Palo Verde VIE | APS | Period 2021 through 2033 | |||||
Palo Verde Sale Leaseback Variable Interest Entities | |||||
Number of leases under which assets are retained | Lease | 3 | ||||
Annual lease payments | $ 21,000,000 | ||||
Palo Verde VIE | APS | Period 2021 through 2033 | Maximum | |||||
Palo Verde Sale Leaseback Variable Interest Entities | |||||
Lease period (up to) | 2 years |
Palo Verde Sale Leaseback Var_4
Palo Verde Sale Leaseback Variable Interest Entities - Schedule of VIEs (Details) - USD ($) $ in Thousands | Jun. 30, 2021 | Dec. 31, 2020 |
Palo Verde Sale Leaseback Variable Interest Entities | ||
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation | $ 15,505,961 | $ 15,159,210 |
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets | ||
Equity — Noncontrolling interests | 117,275 | 119,290 |
APS | ||
Palo Verde Sale Leaseback Variable Interest Entities | ||
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation | 15,505,604 | 15,158,846 |
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets | ||
Equity — Noncontrolling interests | 117,275 | 119,290 |
Palo Verde VIE | APS | ||
Palo Verde Sale Leaseback Variable Interest Entities | ||
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation | 96,101 | 98,036 |
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets | ||
Equity — Noncontrolling interests | $ 117,275 | $ 119,290 |
Derivative Accounting - Narrati
Derivative Accounting - Narrative (Details) - USD ($) | Jun. 30, 2021 | Jun. 30, 2021 | Jun. 30, 2020 | Jun. 30, 2021 | Jun. 30, 2020 |
Derivative Accounting | |||||
Amounts reclassified from accumulated other comprehensive income in next twelve months | $ 0 | ||||
Commodity Contracts | |||||
Derivative Accounting | |||||
Aggregate fair value of derivative instruments in a net liability position | $ 1,595,000 | $ 1,595,000 | 1,595,000 | ||
Additional collateral to counterparties for energy related non-derivative instrument contracts | $ 87,000,000 | 87,000,000 | 87,000,000 | ||
Commodity Contracts | Designated as Hedging Instruments | |||||
Derivative Accounting | |||||
Amount reclassified from accumulated other comprehensive income to earnings related to discontinued cash flow hedges | $ 0 | $ 0 | $ 0 | $ 0 | |
APS | |||||
Derivative Accounting | |||||
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment | 100.00% | 100.00% | 100.00% | ||
Risk Management Assets | Credit Concentration Risk | |||||
Derivative Accounting | |||||
Aggregate fair value of derivative instruments in a net liability position | $ 110,000,000 | $ 110,000,000 | $ 110,000,000 | ||
Risk Management Assets | Credit Concentration Risk | Two Counterparties | |||||
Derivative Accounting | |||||
Concentration risk | 35.00% |
Derivative Accounting - Schedul
Derivative Accounting - Schedule of Gross Notional Amounts Outstanding (Details) - Commodity Contracts GWh in Thousands, Bcf in Thousands | Mar. 31, 2021GWhBcf | Dec. 31, 2020GWhBcf |
Outstanding gross notional amount of derivatives | ||
Power | GWh | 368 | 368 |
Gas | Bcf | 189 | 205 |
Derivative Accounting - Gains a
Derivative Accounting - Gains and Losses from Derivative Instruments (Details) - Commodity Contracts - USD ($) | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2021 | Jun. 30, 2020 | Jun. 30, 2021 | Jun. 30, 2020 | |
Designated as Hedging Instruments | ||||
Gains and losses from derivative instruments | ||||
Amount reclassified from accumulated other comprehensive income to earnings related to discontinued cash flow hedges | $ 0 | $ 0 | $ 0 | $ 0 |
Designated as Hedging Instruments | Fuel and purchased power | ||||
Gains and losses from derivative instruments | ||||
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) | 0 | (349,000) | 0 | (763,000) |
Not Designated as Hedging Instruments | Fuel and purchased power | ||||
Gains and losses from derivative instruments | ||||
Net Gain (Loss) Recognized in Income | $ 95,116,000 | $ (4,894,000) | $ 121,975,000 | $ (34,971,000) |
Derivative Accounting - Derivat
Derivative Accounting - Derivative Instruments in the Balance Sheets (Details) - USD ($) | Jun. 30, 2021 | Dec. 31, 2020 |
Assets | ||
Gross Recognized Derivatives | $ 109,614,000 | $ 4,749,000 |
Liabilities | ||
Amount Reported on Balance Sheets | (1,512,000) | (18,619,000) |
Commodity Contracts | ||
Assets | ||
Gross Recognized Derivatives | 110,982,000 | 9,020,000 |
Amounts Offset | (1,368,000) | (4,271,000) |
Net Recognized Derivatives | 109,614,000 | 4,749,000 |
Other | 0 | 0 |
Amount Reported on Balance Sheets | 109,614,000 | 4,749,000 |
Liabilities | ||
Gross Recognized Derivatives | (1,595,000) | (21,605,000) |
Amounts Offset | 1,368,000 | 4,271,000 |
Net Recognized Derivatives | (227,000) | (17,334,000) |
Other | (1,285,000) | (1,285,000) |
Amount Reported on Balance Sheets | (1,512,000) | (18,619,000) |
Assets and Liabilities | ||
Gross Recognized Derivatives | 109,387,000 | (12,585,000) |
Amounts Offset | 0 | 0 |
Net Recognized Derivatives | 109,387,000 | (12,585,000) |
Other | (1,285,000) | (1,285,000) |
Amount Reported on Balance Sheets | 108,102,000 | (13,870,000) |
Cash collateral received from counterparties | 1,285,000 | 1,285,000 |
Commodity Contracts | Current assets | ||
Assets | ||
Gross Recognized Derivatives | 83,677,000 | 5,870,000 |
Amounts Offset | (1,368,000) | (2,939,000) |
Net Recognized Derivatives | 82,309,000 | 2,931,000 |
Other | 0 | 0 |
Amount Reported on Balance Sheets | 82,309,000 | 2,931,000 |
Commodity Contracts | Investments and other assets | ||
Assets | ||
Gross Recognized Derivatives | 27,305,000 | 3,150,000 |
Amounts Offset | 0 | (1,332,000) |
Net Recognized Derivatives | 27,305,000 | 1,818,000 |
Other | 0 | 0 |
Amount Reported on Balance Sheets | 27,305,000 | 1,818,000 |
Commodity Contracts | Current liabilities | ||
Liabilities | ||
Gross Recognized Derivatives | (1,595,000) | (9,211,000) |
Amounts Offset | 1,368,000 | 2,939,000 |
Net Recognized Derivatives | (227,000) | (6,272,000) |
Other | (1,285,000) | (1,285,000) |
Amount Reported on Balance Sheets | (1,512,000) | (7,557,000) |
Assets and Liabilities | ||
Cash collateral received from counterparties | 1,285,000 | 1,285,000 |
Commodity Contracts | Deferred credits and other | ||
Liabilities | ||
Gross Recognized Derivatives | 0 | (12,394,000) |
Amounts Offset | 0 | 1,332,000 |
Net Recognized Derivatives | 0 | (11,062,000) |
Other | 0 | 0 |
Amount Reported on Balance Sheets | 0 | (11,062,000) |
Assets and Liabilities | ||
Cash collateral received from counterparties | $ 0 | $ 0 |
Derivative Accounting - Credit
Derivative Accounting - Credit Risk and Credit Related Contingent Features (Details) - Commodity Contracts $ in Thousands | Jun. 30, 2021USD ($) |
Credit Risk and Credit-Related Contingent Features | |
Aggregate fair value of derivative instruments in a net liability position | $ 1,595 |
Cash collateral posted | 0 |
Additional cash collateral in the event credit-risk-related contingent features were fully triggered | $ 0 |
Commitments and Contingencies -
Commitments and Contingencies - Palo Verde Nuclear Generating Station and Contractual Obligations (Details) | Mar. 15, 2021USD ($) | Nov. 02, 2020claim | Oct. 31, 2019USD ($) | Jun. 30, 2021USD ($)power_plant | Jun. 30, 2018USD ($)claimtime_period | Dec. 31, 1986Trust |
Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste | ||||||
Commitments and Contingencies | ||||||
Litigation settlement amount | $ 12,100,000 | $ 12,200,000 | $ 99,700,000 | |||
APS | ||||||
Commitments and Contingencies | ||||||
Maximum insurance against public liability per occurrence for a nuclear incident (up to) | $ 13,500,000,000 | |||||
Maximum available nuclear liability insurance (up to) | 450,000,000 | |||||
Remaining nuclear liability insurance through mandatory industry wide retrospective assessment program | 13,100,000,000 | |||||
Maximum retrospective premium assessment per reactor for each nuclear liability incident | 137,600,000 | |||||
Annual limit per incident with respect to maximum retrospective premium assessment | $ 20,500,000 | |||||
Number of VIE lessor trusts | 3 | 3 | ||||
Maximum potential retrospective assessment per incident of APS | $ 120,100,000 | |||||
Annual payment limitation with respect to maximum potential retrospective premium assessment | 17,900,000 | |||||
Amount of "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde | 2,800,000,000 | |||||
Maximum amount that APS could incur under the current NEIL policies for each retrospective assessment | 22,400,000 | |||||
Collateral assurance provided based on rating triggers | $ 63,300,000 | |||||
Period to provide collateral assurance based on rating triggers | 20 days | |||||
APS | Public Utilities, Inventory, Fuel | ||||||
Commitments and Contingencies | ||||||
Purchase obligation | $ 624,000,000 | |||||
APS | Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste | ||||||
Commitments and Contingencies | ||||||
Litigation settlement amount | $ 3,500,000 | $ 3,600,000 | $ 29,000,000 | |||
Number of claims submitted | claim | 7 | 6 | ||||
Number of settlement agreement time periods | time_period | 6 |
Commitments and Contingencies_2
Commitments and Contingencies - Superfund-Related Matters, Southwest Power Outage, Clean Air Act and Four Corners (Details) - APS $ in Millions | Aug. 02, 2021USD ($) | Jun. 30, 2021USD ($) | Apr. 05, 2018plaintiffDefendant | Dec. 16, 2016plaintiff | Aug. 06, 2013Defendant | Jun. 30, 2021USD ($) |
SCE | Four Corners Units 4 and 5 | ||||||
Loss Contingencies [Line Items] | ||||||
Estimated write-off of cost deferrals | $ 75 | |||||
SCR plant investments | $ 320 | $ 320 | ||||
SCE | Four Corners Units 4 and 5 | Subsequent Event | ||||||
Loss Contingencies [Line Items] | ||||||
Disallowance of plant investments | $ 399 | |||||
Cost deferrals | $ 61 | |||||
Contaminated groundwater wells | ||||||
Loss Contingencies [Line Items] | ||||||
Costs related to investigation and study under Superfund site | $ 3 | |||||
Number of defendants against whom Roosevelt Irrigation District (RID) filed lawsuit | Defendant | 28 | 24 | ||||
Number of plaintiffs | plaintiff | 2 | |||||
Settled Litigation | Contaminated groundwater wells | ||||||
Loss Contingencies [Line Items] | ||||||
Number of plaintiffs | plaintiff | 2 |
Commitments and Contingencies_3
Commitments and Contingencies - Environmental Matters and Financial Assurances (Details) - USD ($) $ in Thousands | Feb. 22, 2021 | Jul. 03, 2018 | Jul. 06, 2016 | Jun. 30, 2021 |
Financial Assurances | ||||
Production tax credit guarantees | $ 2,000 | |||
Equity contribution guarantees | 38,000 | |||
APS | 2017 Settlement Agreement and its Customer Education and Outreach Plan | ||||
Arizona Attorney General [Abstract] | ||||
Settlement amount | $ 24,750 | |||
Settlement amount returned to customers | $ 24,000 | |||
APS | Letters of Credit Expiring in 2020 | ||||
Financial Assurances | ||||
Outstanding letters of credit | 5,300 | |||
APS | Surety Bonds Expiring in 2020 | ||||
Financial Assurances | ||||
Surety bonds expiring, amount | 16,000 | |||
4C Acquisition, LLC | Four Corners | ||||
Environmental Matters [Abstract] | ||||
Percentage of share of cost of control | 7.00% | |||
Four Corners Coal Supply Agreement | ||||
Notes receivable, related parties | 18,000 | |||
4C Acquisition, LLC | Coal Supply Agreement Arbitration | Four Corners | ||||
Four Corners Coal Supply Agreement | ||||
Reimbursement payments due to 4CA | $ 10,000 | |||
NTEC | Four Corners | ||||
Four Corners Coal Supply Agreement | ||||
Option to purchase ownership interest (as a percent) | 7.00% | 7.00% | ||
Proceeds from operating and maintenance cost reimbursement | $ 70,000 | |||
NTEC | Coal Supply Agreement Arbitration | Four Corners | ||||
Four Corners Coal Supply Agreement | ||||
Option to purchase ownership interest (as a percent) | 7.00% | |||
Regional Haze Rules | APS | Four Corners Units 4 and 5 | ||||
Environmental Matters [Abstract] | ||||
Percentage of share of cost of control | 63.00% | |||
Expected environmental cost | $ 400,000 | |||
Regional Haze Rules | APS | Natural gas tolling contract obligations | Four Corners Units 4 and 5 | ||||
Environmental Matters [Abstract] | ||||
Additional percentage share of cost of control | 7.00% | |||
Regional Haze Rules | APS | Four Corners | Four Corners Units 4 and 5 | ||||
Environmental Matters [Abstract] | ||||
Site contingency increase in loss exposure not accrued, best estimate | $ 45,000 | |||
Coal combustion waste | APS | Four Corners | ||||
Environmental Matters [Abstract] | ||||
Site contingency increase in loss exposure not accrued, best estimate | 27,000 | |||
Coal combustion waste | APS | Navajo Plant | ||||
Environmental Matters [Abstract] | ||||
Site contingency increase in loss exposure not accrued, best estimate | 1,000 | |||
Minimum | Coal combustion waste | APS | Cholla | ||||
Environmental Matters [Abstract] | ||||
Site contingency increase in loss exposure not accrued, best estimate | 16,000 | |||
Minimum | Coal combustion waste | APS | Cholla and Four Corners | ||||
Environmental Matters [Abstract] | ||||
Site contingency increase in loss exposure not accrued, best estimate | 10,000 | |||
Maximum | Coal combustion waste | APS | Cholla and Four Corners | ||||
Environmental Matters [Abstract] | ||||
Site contingency increase in loss exposure not accrued, best estimate | $ 15,000 |
Other Income and Other Expens_2
Other Income and Other Expense (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2021 | Jun. 30, 2020 | Jun. 30, 2021 | Jun. 30, 2020 | |
Other income: | ||||
Interest income | $ 1,687 | $ 2,755 | $ 3,635 | $ 6,032 |
Investment gains - net | 0 | 2,826 | 0 | 2,826 |
Miscellaneous | 40 | 137 | 43 | 145 |
Total other income | 12,207 | 16,670 | 24,636 | 29,239 |
Other expense: | ||||
Non-operating costs | (4,102) | (2,290) | (6,039) | (4,948) |
Investment gains (losses) — net | (431) | 0 | (774) | 60 |
Miscellaneous | (651) | (1,746) | (2,224) | (3,932) |
Total other expense | (5,184) | (4,036) | (9,037) | (8,820) |
APS | ||||
Other income: | ||||
Interest income | 1,047 | 2,183 | 2,528 | 4,524 |
Miscellaneous | 36 | 137 | 37 | 145 |
Total other income | 11,563 | 13,272 | 23,523 | 24,905 |
Other expense: | ||||
Non-operating costs | (3,615) | (2,113) | (5,392) | (4,595) |
Miscellaneous | (646) | (1,746) | (2,219) | (3,932) |
Total other expense | (4,261) | (3,859) | (7,611) | (8,527) |
SCR deferral | ||||
Other income: | ||||
Debt return on Four Corners SCR deferrals (Note 4) | 4,089 | 4,249 | 8,175 | 7,389 |
SCR deferral | APS | ||||
Other income: | ||||
Debt return on Four Corners SCR deferrals (Note 4) | 4,089 | 4,249 | 8,175 | 7,389 |
Ocotillo deferral | ||||
Other income: | ||||
Debt return on Four Corners SCR deferrals (Note 4) | 6,391 | 6,703 | 12,783 | 12,847 |
Ocotillo deferral | APS | ||||
Other income: | ||||
Debt return on Four Corners SCR deferrals (Note 4) | $ 6,391 | $ 6,703 | $ 12,783 | $ 12,847 |
Earnings Per Share (Details)
Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2021 | Jun. 30, 2020 | Jun. 30, 2021 | Jun. 30, 2020 | |
Earnings Per Share [Abstract] | ||||
Net income attributable to common shareholders | $ 215,697 | $ 193,585 | $ 251,338 | $ 223,578 |
Weighted average common shares outstanding - basic (in shares) | 112,882 | 112,638 | 112,855 | 112,616 |
Net effect of dilutive securities: | ||||
Contingently issuable performance shares and restricted stock units (in shares) | 341 | 241 | 303 | 255 |
Weighted average common shares outstanding — diluted (in shares) | 113,223 | 112,879 | 113,158 | 112,871 |
Earnings per weighted-average common share outstanding | ||||
Net income attributable to common shareholders - basic (in dollars per share) | $ 1.91 | $ 1.72 | $ 2.23 | $ 1.99 |
Net income attributable to common shareholders - diluted (in dollars per share) | $ 1.91 | $ 1.71 | $ 2.22 | $ 1.98 |
Fair Value Measurements - Asset
Fair Value Measurements - Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($) $ in Thousands | Jun. 30, 2021 | Dec. 31, 2020 |
Assets | ||
Commodity contracts, assets | $ 109,614 | $ 4,749 |
Commodity contracts, liabilities | (1,368) | (4,271) |
Nuclear decommissioning trust | 1,223,088 | 1,138,435 |
Nuclear decommissioning trust, other | 693,330 | 592,227 |
Other special use funds | 358,436 | 254,509 |
Other special use funds, other | 952 | 504 |
Total assets | 1,691,138 | 1,397,693 |
Total assets, other | 692,914 | 588,460 |
Liabilities | ||
Gross derivative liability, other | 83 | 2,986 |
Amount reported on balance sheet | (1,512) | (18,619) |
Equity securities | ||
Assets | ||
Nuclear decommissioning trust | 13,243 | 11,968 |
Nuclear decommissioning trust, other | (9,506) | (17,828) |
Other special use funds | 20,856 | 37,841 |
Other special use funds, other | 952 | 504 |
U.S. commingled equity funds | ||
Assets | ||
Nuclear decommissioning trust | 702,836 | 610,055 |
U.S. Treasury debt | ||
Assets | ||
Nuclear decommissioning trust | 167,584 | 164,514 |
Other special use funds | 324,418 | 203,220 |
Corporate debt | ||
Assets | ||
Nuclear decommissioning trust | 150,681 | 149,509 |
Mortgage-backed securities | ||
Assets | ||
Nuclear decommissioning trust | 119,481 | 99,623 |
Municipal bonds | ||
Assets | ||
Nuclear decommissioning trust | 59,876 | 89,705 |
Other special use funds | 13,162 | 13,448 |
Other fixed income | ||
Assets | ||
Nuclear decommissioning trust | 9,387 | 13,061 |
Level 1 | ||
Assets | ||
Commodity contracts, assets | 0 | 0 |
Nuclear decommissioning trust | 190,333 | 194,310 |
Other special use funds | 344,322 | 240,557 |
Total assets | 534,655 | 434,867 |
Liabilities | ||
Gross derivative liability | 0 | 0 |
Level 1 | Equity securities | ||
Assets | ||
Nuclear decommissioning trust | 22,749 | 29,796 |
Other special use funds | 19,904 | 37,337 |
Level 1 | U.S. commingled equity funds | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Level 1 | U.S. Treasury debt | ||
Assets | ||
Nuclear decommissioning trust | 167,584 | 164,514 |
Other special use funds | 324,418 | 203,220 |
Level 1 | Corporate debt | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Level 1 | Mortgage-backed securities | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Level 1 | Municipal bonds | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Other special use funds | 0 | 0 |
Level 1 | Other fixed income | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Level 2 | ||
Assets | ||
Commodity contracts, assets | 84,594 | 9,016 |
Nuclear decommissioning trust | 339,425 | 351,898 |
Other special use funds | 13,162 | 13,448 |
Total assets | 437,181 | 374,362 |
Liabilities | ||
Gross derivative liability | (1,586) | (20,498) |
Level 2 | Equity securities | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Other special use funds | 0 | 0 |
Level 2 | U.S. commingled equity funds | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Level 2 | U.S. Treasury debt | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Other special use funds | 0 | 0 |
Level 2 | Corporate debt | ||
Assets | ||
Nuclear decommissioning trust | 150,681 | 149,509 |
Level 2 | Mortgage-backed securities | ||
Assets | ||
Nuclear decommissioning trust | 119,481 | 99,623 |
Level 2 | Municipal bonds | ||
Assets | ||
Nuclear decommissioning trust | 59,876 | 89,705 |
Other special use funds | 13,162 | 13,448 |
Level 2 | Other fixed income | ||
Assets | ||
Nuclear decommissioning trust | 9,387 | 13,061 |
Level 3 | ||
Assets | ||
Commodity contracts, assets | 26,388 | 4 |
Nuclear decommissioning trust | 0 | 0 |
Other special use funds | 0 | 0 |
Total assets | 26,388 | 4 |
Liabilities | ||
Gross derivative liability | (9) | (1,107) |
Level 3 | Equity securities | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Other special use funds | 0 | 0 |
Level 3 | U.S. commingled equity funds | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Level 3 | U.S. Treasury debt | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Other special use funds | 0 | 0 |
Level 3 | Corporate debt | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Level 3 | Mortgage-backed securities | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Level 3 | Municipal bonds | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Other special use funds | 0 | 0 |
Level 3 | Other fixed income | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Fair Value Measured at Net Asset Value Per Share | U.S. commingled equity funds | ||
Assets | ||
Nuclear decommissioning trust | $ 702,836 | $ 610,055 |
Fair Value Measurements - Finan
Fair Value Measurements - Financial Instruments Not Carried at Fair Value (Details) - USD ($) $ in Millions | Jun. 30, 2021 | Dec. 31, 2020 |
Fair Value Disclosures [Abstract] | ||
Stated interest rate for notes receivable | 3.90% | |
Note receivable, net book value | $ 18.2 | $ 27.1 |
Investments in Nuclear Decomm_3
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Details) - USD ($) $ in Thousands | Jan. 04, 2021 | Jun. 30, 2021 | Jun. 30, 2020 | Jun. 30, 2021 | Jun. 30, 2020 | Dec. 31, 2020 | Dec. 31, 2019 |
Fair value of fixed income securities, summarized by contractual maturities | |||||||
Transfer to active union medical account | $ 106,000 | ||||||
APS | |||||||
Nuclear decommissioning trust fund assets | |||||||
Fair Value | $ 1,581,524 | $ 1,581,524 | $ 1,392,944 | ||||
Total Unrealized Gains | 541,701 | 468,247 | |||||
Total Unrealized Losses | (1,357) | (398) | |||||
Amortized cost | 815,000 | 815,000 | 687,000 | ||||
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds | |||||||
Realized gains | 1,406 | $ 4,500 | 4,374 | $ 7,813 | |||
Realized losses | (1,146) | (1,621) | (5,294) | (3,848) | |||
Proceeds from the sale of securities | 207,864 | 196,772 | 587,842 | 391,859 | |||
Fair value of fixed income securities, summarized by contractual maturities | |||||||
Employee medical claims amount | 14,000 | $ 15,000 | |||||
APS | Equity securities | |||||||
Nuclear decommissioning trust fund assets | |||||||
Equity securities | 745,489 | 745,489 | 677,188 | ||||
Total Unrealized Gains | 510,432 | 421,666 | |||||
Total Unrealized Losses | 0 | 0 | |||||
APS | Available for sale-fixed income securities | |||||||
Nuclear decommissioning trust fund assets | |||||||
Fair Value | 844,589 | 844,589 | 733,080 | ||||
Total Unrealized Gains | 31,269 | 46,581 | |||||
Total Unrealized Losses | (1,357) | (398) | |||||
Fair value of fixed income securities, summarized by contractual maturities | |||||||
Less than one year | 94,537 | 94,537 | |||||
1 year – 5 years | 331,662 | 331,662 | |||||
5 years – 10 years | 195,426 | 195,426 | |||||
Greater than 10 years | 222,964 | 222,964 | |||||
Total | 844,589 | 844,589 | |||||
APS | Other | |||||||
Nuclear decommissioning trust fund assets | |||||||
Fair Value | (8,554) | (8,554) | (17,324) | ||||
Total Unrealized Gains | 0 | 0 | |||||
Total Unrealized Losses | 0 | 0 | |||||
Nuclear Decommissioning Trust | APS | |||||||
Nuclear decommissioning trust fund assets | |||||||
Fair Value | 1,223,088 | 1,223,088 | 1,138,435 | ||||
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds | |||||||
Realized gains | 1,406 | 4,500 | 4,374 | 7,813 | |||
Realized losses | (1,146) | (1,621) | (5,294) | (3,848) | |||
Proceeds from the sale of securities | 190,340 | 176,942 | 425,068 | 355,138 | |||
Nuclear Decommissioning Trust | APS | Equity securities | |||||||
Nuclear decommissioning trust fund assets | |||||||
Equity securities | 725,585 | 725,585 | 639,851 | ||||
Nuclear Decommissioning Trust | APS | Available for sale-fixed income securities | |||||||
Nuclear decommissioning trust fund assets | |||||||
Fair Value | 507,009 | 507,009 | 516,412 | ||||
Fair value of fixed income securities, summarized by contractual maturities | |||||||
Less than one year | 28,151 | 28,151 | |||||
1 year – 5 years | 133,054 | 133,054 | |||||
5 years – 10 years | 131,462 | 131,462 | |||||
Greater than 10 years | 214,342 | 214,342 | |||||
Total | 507,009 | 507,009 | |||||
Nuclear Decommissioning Trust | APS | Other | |||||||
Nuclear decommissioning trust fund assets | |||||||
Fair Value | (9,506) | (9,506) | (17,828) | ||||
Other Special Use Funds | APS | |||||||
Nuclear decommissioning trust fund assets | |||||||
Fair Value | 358,436 | 358,436 | 254,509 | ||||
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds | |||||||
Realized gains | 0 | 0 | 0 | 0 | |||
Realized losses | 0 | 0 | 0 | 0 | |||
Proceeds from the sale of securities | 17,524 | $ 19,830 | 162,774 | $ 36,721 | |||
Other Special Use Funds | APS | Equity securities | |||||||
Nuclear decommissioning trust fund assets | |||||||
Equity securities | 19,904 | 19,904 | 37,337 | ||||
Other Special Use Funds | APS | Available for sale-fixed income securities | |||||||
Nuclear decommissioning trust fund assets | |||||||
Fair Value | 337,580 | 337,580 | 216,668 | ||||
Other Special Use Funds | APS | Other | |||||||
Nuclear decommissioning trust fund assets | |||||||
Fair Value | 952 | 952 | $ 504 | ||||
Coal Reclamation Escrow Account | APS | Available for sale-fixed income securities | |||||||
Fair value of fixed income securities, summarized by contractual maturities | |||||||
Less than one year | 26,123 | 26,123 | |||||
1 year – 5 years | 35,880 | 35,880 | |||||
5 years – 10 years | 2,676 | 2,676 | |||||
Greater than 10 years | 8,622 | 8,622 | |||||
Total | 73,301 | 73,301 | |||||
Active union medical trust | APS | Available for sale-fixed income securities | |||||||
Fair value of fixed income securities, summarized by contractual maturities | |||||||
Less than one year | 40,263 | 40,263 | |||||
1 year – 5 years | 162,728 | 162,728 | |||||
5 years – 10 years | 61,288 | 61,288 | |||||
Greater than 10 years | 0 | 0 | |||||
Total | $ 264,279 | $ 264,279 |
Changes in Accumulated Other _3
Changes in Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2021 | Jun. 30, 2020 | Jun. 30, 2021 | Jun. 30, 2020 | |
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||||
Balance at beginning of period | $ 5,806,680 | $ 5,596,832 | $ 5,752,793 | $ 5,553,188 |
OCI (loss) before reclassifications | (255) | (3,557) | 7 | (3,265) |
Amounts reclassified from accumulated other comprehensive loss | 1,189 | 1,261 | 2,211 | 2,486 |
Balance at end of period | 5,834,899 | 5,610,477 | 5,834,899 | 5,610,477 |
Pension and Other Postretirement Benefits | ||||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||||
Balance at beginning of period | (59,703) | (55,317) | (60,725) | (56,522) |
OCI (loss) before reclassifications | (1,125) | (2,008) | (1,125) | (2,008) |
Amounts reclassified from accumulated other comprehensive loss | 1,189 | 999 | 2,211 | 2,204 |
Balance at end of period | (59,639) | (56,326) | (59,639) | (56,326) |
Derivative Instruments | ||||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||||
Balance at beginning of period | (1,809) | (262) | (2,071) | (574) |
OCI (loss) before reclassifications | 870 | (1,549) | 1,132 | (1,257) |
Amounts reclassified from accumulated other comprehensive loss | 0 | 262 | 0 | 282 |
Balance at end of period | (939) | (1,549) | (939) | (1,549) |
Accumulated Other Comprehensive Income (Loss) | ||||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||||
Balance at beginning of period | (61,512) | (55,579) | (62,796) | (57,096) |
Balance at end of period | (60,578) | (57,875) | (60,578) | (57,875) |
APS | ||||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||||
Balance at beginning of period | 6,386,275 | 6,040,344 | 6,345,185 | 5,998,803 |
OCI (loss) before reclassifications | (914) | (1,951) | (914) | (1,659) |
Amounts reclassified from accumulated other comprehensive loss | 1,073 | 1,123 | 2,000 | 2,156 |
Balance at end of period | 6,412,290 | 6,054,137 | 6,412,290 | 6,054,137 |
APS | Pension and Other Postretirement Benefits | ||||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||||
Balance at beginning of period | (39,991) | (33,935) | (40,918) | (34,948) |
OCI (loss) before reclassifications | (914) | (1,951) | (914) | (1,951) |
Amounts reclassified from accumulated other comprehensive loss | 1,073 | 861 | 2,000 | 1,874 |
Balance at end of period | (39,832) | (35,025) | (39,832) | (35,025) |
APS | Derivative Instruments | ||||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||||
Balance at beginning of period | 0 | (262) | 0 | (574) |
OCI (loss) before reclassifications | 0 | 0 | 0 | 292 |
Amounts reclassified from accumulated other comprehensive loss | 0 | 262 | 0 | 282 |
Balance at end of period | 0 | 0 | 0 | 0 |
APS | Accumulated Other Comprehensive Income (Loss) | ||||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||||
Balance at beginning of period | (39,991) | (34,197) | (40,918) | (35,522) |
Balance at end of period | $ (39,832) | $ (35,025) | $ (39,832) | $ (35,025) |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | 12 Months Ended | |
Mar. 31, 2020 | Jun. 30, 2021 | Jun. 30, 2020 | Dec. 31, 2017 | |
Income Tax Contingency [Line Items] | ||||
Reduction in net deferred income tax liabilities | $ 1,140 | |||
Regulatory liability, amortization period | 28 years 6 months | |||
Income tax expense attributable to non controlling interests | $ 0 | |||
Domestic Tax Authority | ||||
Income Tax Contingency [Line Items] | ||||
Income tax benefit from amortization of an excess deferred tax liability | $ 14 | $ 14 | $ 14 |
Leases - Narrative (Details)
Leases - Narrative (Details) $ in Millions | Jun. 30, 2021USD ($)Lease |
Leases [Abstract] | |
Number of lease agreements, lease and sell back | Lease | 3 |
Lease not yet commenced | $ | $ 392 |
Leases - Lease Costs (Details)
Leases - Lease Costs (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2021 | Jun. 30, 2020 | Jun. 30, 2021 | Jun. 30, 2020 | |
Operating Leased Assets [Line Items] | ||||
Operating lease cost | $ 34,112 | $ 21,872 | $ 38,753 | $ 26,525 |
Variable lease cost | 40,795 | 41,076 | 62,537 | 61,892 |
Short-term lease cost | 1,260 | 996 | 2,249 | 1,786 |
Total lease cost | 76,167 | 63,944 | 103,539 | 90,203 |
Purchased Power Lease Contracts | ||||
Operating Leased Assets [Line Items] | ||||
Operating lease cost | 29,514 | 17,221 | 29,514 | 17,221 |
Variable lease cost | 40,539 | 40,821 | 62,027 | 61,394 |
Short-term lease cost | 0 | 0 | 0 | 0 |
Total lease cost | 70,053 | 58,042 | 91,541 | 78,615 |
Land, Property & Equipment Leases | ||||
Operating Leased Assets [Line Items] | ||||
Operating lease cost | 4,598 | 4,651 | 9,239 | 9,304 |
Variable lease cost | 256 | 255 | 510 | 498 |
Short-term lease cost | 1,260 | 996 | 2,249 | 1,786 |
Total lease cost | $ 6,114 | $ 5,902 | $ 11,998 | $ 11,588 |
Leases - Maturity of Operating
Leases - Maturity of Operating Lease Liabilities (Details) $ in Thousands | Jun. 30, 2021USD ($) |
Lessee, Lease, Description [Line Items] | |
2021 (remaining six months of 2021) | $ 103,358 |
2022 | 115,616 |
2023 | 115,705 |
2024 | 115,589 |
2025 | 116,347 |
2026 | 79,088 |
Thereafter | 73,550 |
Total lease commitments | 719,253 |
Less imputed interest | 43,416 |
Total lease liabilities | 675,837 |
Purchased Power Lease Contracts | |
Lessee, Lease, Description [Line Items] | |
2021 (remaining six months of 2021) | 95,596 |
2022 | 103,744 |
2023 | 106,161 |
2024 | 108,634 |
2025 | 111,166 |
2026 | 75,099 |
Thereafter | 39,106 |
Total lease commitments | 639,506 |
Less imputed interest | 25,803 |
Total lease liabilities | 613,703 |
Land, Property & Equipment Leases | |
Lessee, Lease, Description [Line Items] | |
2021 (remaining six months of 2021) | 7,762 |
2022 | 11,872 |
2023 | 9,544 |
2024 | 6,955 |
2025 | 5,181 |
2026 | 3,989 |
Thereafter | 34,444 |
Total lease commitments | 79,747 |
Less imputed interest | 17,613 |
Total lease liabilities | $ 62,134 |
Leases - Other Additional Infor
Leases - Other Additional Information Related to Operating Lease Liabilities (Details) - USD ($) $ in Thousands | 6 Months Ended | ||
Jun. 30, 2021 | Jun. 30, 2020 | Dec. 31, 2020 | |
Leases [Abstract] | |||
Cash paid for amounts included in the measurement of lease liabilities — operating cash flows: | $ 13,068 | $ 7,624 | |
Right-of-use operating lease assets obtained in exchange for operating lease liabilities | $ 248,694 | $ 434,997 | |
Weighted average remaining lease term | 6 years | 6 years | |
Weighted average discount rate | 1.72% | 1.69% |
Asset Retirement Obligations -
Asset Retirement Obligations - Narrative (Details) $ in Millions | 6 Months Ended |
Jun. 30, 2021USD ($) | |
Cholla | |
Asset Retirement Obligations | |
Asset retirement obligation, period increase | $ 11.1 |
Asset Retirement Obligations _2
Asset Retirement Obligations - Roll-Forward (Details) $ in Thousands | 6 Months Ended |
Jun. 30, 2021USD ($) | |
Change in asset retirement obligations | |
Asset retirement obligations at the beginning of year | $ 705,083 |
Changes attributable to: | |
Accretion expense | 18,828 |
Settlements | (2,853) |
Newly incurred liabilities | 10,932 |
Asset retirement obligations at the end of year | $ 731,990 |