Document and Entity Information
Document and Entity Information - shares | 3 Months Ended | |
Mar. 31, 2020 | May 01, 2020 | |
Entity Information [Line Items] | ||
Entity Shell Company | false | |
Entity Interactive Data Current | Yes | |
Security Exchange Name | NYSE | |
Trading Symbol | PNW | |
Title of 12(b) Security | Common Stock | |
Entity Tax Identification Number | 86-0512431 | |
Entity Address, Address Line One | 400 North Fifth Street, P.O. Box 53999 | |
Entity Address, City or Town | Phoenix | |
Entity Address, State or Province | AZ | |
Entity Address, Postal Zip Code | 85072-3999 | |
City Area Code | (602) | |
Local Phone Number | 250-1000 | |
Entity File Number | 1-8962 | |
Document Transition Report | false | |
Document Quarterly Report | true | |
Entity Registrant Name | PINNACLE WEST CAPITAL CORPORATION | |
Entity Central Index Key | 0000764622 | |
Document Type | 10-Q | |
Document Period End Date | Mar. 31, 2020 | |
Amendment Flag | false | |
Current Fiscal Year End Date | --12-31 | |
Entity Current Reporting Status | Yes | |
Entity Filer Category | Large Accelerated Filer | |
Entity Emerging Growth Company | false | |
Entity Small Business | false | |
Entity Common Stock, Shares Outstanding (in shares) | 112,493,458 | |
Document Fiscal Year Focus | 2020 | |
Document Fiscal Period Focus | Q1 | |
Entity Incorporation, State or Country Code | AZ | |
APS | ||
Entity Information [Line Items] | ||
Entity Shell Company | false | |
Entity Interactive Data Current | Yes | |
Entity Tax Identification Number | 86-0011170 | |
Entity Address, Address Line One | 400 North Fifth Street, P.O. Box 53999 | |
Entity Address, City or Town | Phoenix | |
Entity Address, State or Province | AZ | |
Entity Address, Postal Zip Code | 85072-3999 | |
City Area Code | (602) | |
Local Phone Number | 250-1000 | |
Entity File Number | 1-4473 | |
Entity Registrant Name | ARIZONA PUBLIC SERVICE COMPANY | |
Entity Central Index Key | 0000007286 | |
Document Type | 10-Q | |
Document Period End Date | Mar. 31, 2020 | |
Amendment Flag | false | |
Current Fiscal Year End Date | --12-31 | |
Entity Current Reporting Status | Yes | |
Entity Filer Category | Non-accelerated Filer | |
Entity Emerging Growth Company | false | |
Entity Small Business | false | |
Entity Common Stock, Shares Outstanding (in shares) | 71,264,947 | |
Document Fiscal Year Focus | 2020 | |
Document Fiscal Period Focus | Q1 | |
Entity Incorporation, State or Country Code | AZ |
CONDENSED CONSOLIDATED STATEMEN
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | |
Mar. 31, 2020 | Mar. 31, 2019 | |
OPERATING REVENUES (NOTE 2) | $ 661,930 | $ 740,530 |
OPERATING EXPENSES | ||
Fuel and purchased power | 188,521 | 230,588 |
Operations and maintenance | 221,318 | 245,634 |
Depreciation and amortization | 154,079 | 148,707 |
Taxes other than income taxes | 56,768 | 55,090 |
Other expenses | 822 | 427 |
Total | 621,508 | 680,446 |
OPERATING INCOME | 40,422 | 60,084 |
OTHER INCOME (DEDUCTIONS) | ||
Allowance for equity funds used during construction | 7,697 | 11,188 |
Pension and other postretirement non-service credits - net | 13,911 | 5,114 |
Other income (Note 9) | 12,569 | 7,169 |
Other expense (Note 9) | (4,784) | (4,358) |
Total | 29,393 | 19,113 |
INTEREST EXPENSE | ||
Interest charges | 59,234 | 60,653 |
Allowance for borrowed funds used during construction | (4,076) | (6,665) |
Total | 55,158 | 53,988 |
INCOME BEFORE INCOME TAXES | 14,657 | 25,209 |
INCOME TAXES | (20,209) | 2,418 |
NET INCOME | 34,866 | 22,791 |
Less: Net income attributable to noncontrolling interests (Note 6) | 4,873 | 4,873 |
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS | $ 29,993 | $ 17,918 |
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING | ||
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares) | 112,594 | 112,337 |
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares) | 112,862 | 112,735 |
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING | ||
Net income attributable to common shareholders - basic (in dollars per share) | $ 0.27 | $ 0.16 |
Net income attributable to common shareholders - diluted (in dollars per share) | $ 0.27 | $ 0.16 |
APS | ||
OPERATING REVENUES (NOTE 2) | $ 661,930 | $ 740,530 |
OPERATING EXPENSES | ||
Fuel and purchased power | 188,521 | 230,588 |
Operations and maintenance | 218,265 | 240,375 |
Depreciation and amortization | 154,058 | 148,685 |
Taxes other than income taxes | 56,758 | 55,078 |
Other expenses | 822 | 427 |
Total | 618,424 | 675,153 |
OPERATING INCOME | 43,506 | 65,377 |
OTHER INCOME (DEDUCTIONS) | ||
Allowance for equity funds used during construction | 7,697 | 11,188 |
Pension and other postretirement non-service credits - net | 14,262 | 5,499 |
Other income (Note 9) | 11,633 | 6,416 |
Other expense (Note 9) | (4,668) | (3,878) |
Total | 28,924 | 19,225 |
INTEREST EXPENSE | ||
Interest charges | 55,736 | 56,665 |
Allowance for borrowed funds used during construction | (4,076) | (6,665) |
Total | 51,660 | 50,000 |
INCOME BEFORE INCOME TAXES | 20,770 | 34,602 |
INCOME TAXES | (19,448) | 1,453 |
NET INCOME | 40,218 | 33,149 |
Less: Net income attributable to noncontrolling interests (Note 6) | 4,873 | 4,873 |
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS | $ 35,345 | $ 28,276 |
CONDENSED CONSOLIDATED STATEM_2
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2020 | Mar. 31, 2019 | |
NET INCOME | $ 34,866 | $ 22,791 |
Derivative instruments: | ||
Net unrealized gain, net of tax expense | 292 | 0 |
Reclassification of net realized loss, net of tax benefit | 20 | 328 |
Pension and other postretirement benefits activity, net of tax expense | 1,205 | 879 |
Total other comprehensive income | 1,517 | 1,207 |
COMPREHENSIVE INCOME | 36,383 | 23,998 |
Less: Comprehensive income attributable to noncontrolling interests | 4,873 | 4,873 |
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS | 31,510 | 19,125 |
APS | ||
NET INCOME | 40,218 | 33,149 |
Derivative instruments: | ||
Net unrealized gain, net of tax expense | 292 | 0 |
Reclassification of net realized loss, net of tax benefit | 20 | 328 |
Pension and other postretirement benefits activity, net of tax expense | 1,013 | 752 |
Total other comprehensive income | 1,325 | 1,080 |
COMPREHENSIVE INCOME | 41,543 | 34,229 |
Less: Comprehensive income attributable to noncontrolling interests | 4,873 | 4,873 |
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS | $ 36,670 | $ 29,356 |
CONDENSED CONSOLIDATED STATEM_3
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2020 | Mar. 31, 2019 | |
Net unrealized loss, net of tax expense | $ 292 | $ 0 |
Reclassification of net realized loss, net of tax benefit | 394 | 108 |
Pension and other postretirement benefits activity, net of tax expense (benefit) | 108 | 288 |
APS | ||
Net unrealized loss, net of tax expense | 292 | 0 |
Reclassification of net realized loss, net of tax benefit | 394 | 108 |
Pension and other postretirement benefits activity, net of tax expense (benefit) | $ 237 | $ 247 |
CONDENSED CONSOLIDATED BALANCE
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands | Mar. 31, 2020 | Dec. 31, 2019 |
CURRENT ASSETS | ||
Cash and cash equivalents | $ 63,139 | $ 10,283 |
Customer and other receivables | 258,874 | 266,426 |
Accrued unbilled revenues | 93,434 | 128,165 |
Allowance for doubtful accounts | (8,366) | (8,171) |
Materials and supplies (at average cost) | 323,545 | 331,091 |
Fossil fuel (at average cost) | 16,930 | 14,829 |
Income tax receivable | 20,599 | 21,727 |
Assets from risk management activities (Note 7) | 2,108 | 515 |
Deferred fuel and purchased power regulatory asset (Note 4) | 77,730 | 70,137 |
Other regulatory assets (Note 4) | 147,741 | 133,070 |
Other current assets | 82,573 | 61,958 |
Total current assets | 1,078,307 | 1,030,030 |
INVESTMENTS AND OTHER ASSETS | ||
Nuclear decommissioning trust (Notes 11 and 12) | 920,426 | 1,010,775 |
Other special use funds (Notes 11 and 12) | 252,723 | 245,095 |
Other assets | 97,822 | 96,953 |
Total investments and other assets | 1,270,971 | 1,352,823 |
PROPERTY, PLANT AND EQUIPMENT | ||
Plant in service and held for future use | 19,930,983 | 19,836,292 |
Accumulated depreciation and amortization | (6,784,467) | (6,637,857) |
Net | 13,146,516 | 13,198,435 |
Construction work in progress | 942,258 | 808,133 |
Intangible assets, net of accumulated amortization | 279,238 | 290,564 |
Nuclear fuel, net of accumulated amortization | 168,457 | 123,500 |
Total property, plant and equipment | 14,637,407 | 14,522,538 |
DEFERRED DEBITS | ||
Regulatory assets (Note 4) | 1,302,448 | 1,304,073 |
Operating lease right-of-use assets | 144,380 | 145,813 |
Assets for other postretirement benefits (Note 5) | 96,243 | 90,570 |
Other | 32,004 | 33,400 |
Total deferred debits | 1,575,075 | 1,573,856 |
TOTAL ASSETS | 18,561,760 | 18,479,247 |
CURRENT LIABILITIES | ||
Current maturities of long-term debt (Note 3) | 650,000 | 800,000 |
Accounts payable | 301,325 | 346,448 |
Accrued taxes | 194,732 | 144,899 |
Accrued interest | 53,608 | 53,534 |
Common dividends payable | 0 | 87,982 |
Short-term borrowings (Note 3) | 563,000 | 114,675 |
Customer deposits | 54,965 | 64,908 |
Liabilities from risk management activities (Note 7) | 54,784 | 38,946 |
Liabilities for asset retirements | 10,095 | 11,025 |
Operating lease liabilities | 12,360 | 12,713 |
Regulatory liabilities (Note 4) | 279,105 | 234,912 |
Other current liabilities | 121,514 | 168,323 |
Total current liabilities | 2,295,488 | 2,078,365 |
Long-term debt less current maturities (Note 3) | 4,833,324 | 4,832,558 |
DEFERRED CREDITS AND OTHER | ||
Deferred income taxes | 2,016,770 | 1,992,339 |
Regulatory liabilities (Note 4) | 2,067,801 | 2,267,835 |
Liabilities for asset retirements | 649,226 | 646,193 |
Liabilities for pension benefits (Note 5) | 273,284 | 280,185 |
Liabilities from risk management activities (Note 7) | 32,577 | 33,186 |
Customer advances | 212,545 | 215,330 |
Unrecorded Unconditional Purchase Obligation | 166,796 | 165,695 |
Deferred investment tax credit | 196,002 | 196,468 |
Unrecognized tax benefits | 6,400 | 6,189 |
Operating lease liabilities | 51,198 | 51,872 |
Other | 163,517 | 159,844 |
Total deferred credits and other | 5,836,116 | 6,015,136 |
COMMITMENTS AND CONTINGENCIES (SEE NOTE 8) | ||
EQUITY | ||
Common stock, no par value; authorized 150,000,000 shares, 112,563,610 and 112,540,126 issued at respective dates | 2,664,387 | 2,659,561 |
Treasury stock at cost; 72,302 and 103,546 shares at respective dates | (7,000) | (9,427) |
Total common stock | 2,657,387 | 2,650,134 |
Retained earnings | 2,867,610 | 2,837,610 |
Accumulated other comprehensive loss | (55,579) | (57,096) |
Total shareholders’ equity | 5,469,418 | 5,430,648 |
Noncontrolling interests (Note 6) | 127,414 | 122,540 |
Total equity | 5,596,832 | 5,553,188 |
TOTAL LIABILITIES AND EQUITY | 18,561,760 | 18,479,247 |
APS | ||
CURRENT ASSETS | ||
Cash and cash equivalents | 53,351 | 10,169 |
Customer and other receivables | 258,457 | 255,479 |
Accrued unbilled revenues | 93,434 | 128,165 |
Allowance for doubtful accounts | (8,366) | (8,171) |
Materials and supplies (at average cost) | 323,545 | 331,091 |
Fossil fuel (at average cost) | 16,930 | 14,829 |
Income tax receivable | 8,724 | 7,313 |
Assets from risk management activities (Note 7) | 2,108 | 515 |
Deferred fuel and purchased power regulatory asset (Note 4) | 77,730 | 70,137 |
Other regulatory assets (Note 4) | 147,741 | 133,070 |
Other current assets | 57,471 | 38,895 |
Total current assets | 1,031,125 | 981,492 |
INVESTMENTS AND OTHER ASSETS | ||
Nuclear decommissioning trust (Notes 11 and 12) | 920,426 | 1,010,775 |
Other special use funds (Notes 11 and 12) | 252,723 | 245,095 |
Other assets | 44,681 | 43,781 |
Total investments and other assets | 1,217,830 | 1,299,651 |
PROPERTY, PLANT AND EQUIPMENT | ||
Plant in service and held for future use | 19,927,522 | 19,832,805 |
Accumulated depreciation and amortization | (6,781,228) | (6,634,597) |
Net | 13,146,294 | 13,198,208 |
Construction work in progress | 942,258 | 808,133 |
Intangible assets, net of accumulated amortization | 279,082 | 290,409 |
Nuclear fuel, net of accumulated amortization | 168,457 | 123,500 |
Total property, plant and equipment | 14,637,029 | 14,522,156 |
DEFERRED DEBITS | ||
Regulatory assets (Note 4) | 1,302,448 | 1,304,073 |
Operating lease right-of-use assets | 142,647 | 144,024 |
Assets for other postretirement benefits (Note 5) | 92,391 | 86,736 |
Other | 31,282 | 32,591 |
Total deferred debits | 1,568,768 | 1,567,424 |
TOTAL ASSETS | 18,454,752 | 18,370,723 |
CURRENT LIABILITIES | ||
Current maturities of long-term debt (Note 3) | 200,000 | 350,000 |
Accounts payable | 294,037 | 338,006 |
Accrued taxes | 190,571 | 136,328 |
Accrued interest | 51,042 | 52,619 |
Common dividends payable | 0 | 88,000 |
Short-term borrowings (Note 3) | 430,000 | 0 |
Customer deposits | 54,965 | 64,908 |
Liabilities from risk management activities (Note 7) | 54,784 | 38,946 |
Liabilities for asset retirements | 10,095 | 11,025 |
Operating lease liabilities | 12,224 | 12,549 |
Regulatory liabilities (Note 4) | 279,105 | 234,912 |
Other current liabilities | 133,497 | 164,736 |
Total current liabilities | 1,710,320 | 1,492,029 |
Long-term debt less current maturities (Note 3) | 4,833,743 | 4,833,133 |
DEFERRED CREDITS AND OTHER | ||
Deferred income taxes | 2,057,824 | 2,033,096 |
Regulatory liabilities (Note 4) | 2,067,801 | 2,267,835 |
Liabilities for asset retirements | 649,226 | 646,193 |
Liabilities for pension benefits (Note 5) | 255,749 | 262,243 |
Liabilities from risk management activities (Note 7) | 32,577 | 33,186 |
Customer advances | 212,545 | 215,330 |
Unrecorded Unconditional Purchase Obligation | 166,796 | 165,695 |
Deferred investment tax credit | 196,002 | 196,468 |
Unrecognized tax benefits | 40,399 | 40,188 |
Operating lease liabilities | 49,442 | 50,092 |
Other | 141,984 | 136,432 |
Total deferred credits and other | 5,870,345 | 6,046,758 |
COMMITMENTS AND CONTINGENCIES (SEE NOTE 8) | ||
EQUITY | ||
Common stock | 178,162 | 178,162 |
Additional paid-in capital | 2,721,696 | 2,721,696 |
Retained earnings | 3,047,269 | 3,011,927 |
Accumulated other comprehensive loss | (34,197) | (35,522) |
Total shareholders’ equity | 5,912,930 | 5,876,263 |
Noncontrolling interests (Note 6) | 127,414 | 122,540 |
Total equity | 6,040,344 | 5,998,803 |
Total capitalization | 10,874,087 | 10,831,936 |
TOTAL LIABILITIES AND EQUITY | 18,454,752 | 18,370,723 |
Variable Interest Entity, Primary Beneficiary [Member] | ||
PROPERTY, PLANT AND EQUIPMENT | ||
Total property, plant and equipment | 100,938 | 101,906 |
Variable Interest Entity, Primary Beneficiary [Member] | APS | ||
PROPERTY, PLANT AND EQUIPMENT | ||
Total property, plant and equipment | 100,938 | 101,906 |
EQUITY | ||
Noncontrolling interests (Note 6) | $ 127,414 | $ 122,540 |
CONDENSED CONSOLIDATED BALANC_2
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - $ / shares | Mar. 31, 2020 | Dec. 31, 2019 |
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract] | ||
Common stock, par value (in dollars per share) | ||
Common stock, authorized shares (in shares) | 150,000,000 | 150,000,000 |
Common stock, issued shares (in shares) | 112,563,610 | 112,540,126 |
Treasury stock at cost, shares (in shares) | 72,302 | 103,546 |
CONDENSED CONSOLIDATED STATEM_4
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2020 | Mar. 31, 2019 | |
CASH FLOWS FROM OPERATING ACTIVITIES | ||
NET INCOME | $ 34,866 | $ 22,791 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation and amortization including nuclear fuel | 173,168 | 167,801 |
Deferred fuel and purchased power | (5,785) | 16,709 |
Deferred fuel and purchased power amortization | (1,808) | 12,872 |
Allowance for equity funds used during construction | (7,697) | (11,188) |
Deferred income taxes | (18,086) | 3,620 |
Deferred investment tax credit | (465) | (353) |
Stock compensation | 6,282 | 12,074 |
Increase (Decrease) in Accounts and Notes Receivable | (25,575) | (15,476) |
Changes in current assets and liabilities: | ||
Accrued unbilled revenues | 34,731 | 23,093 |
Materials, supplies and fossil fuel | 5,445 | (13,057) |
Income tax receivable | 1,128 | 0 |
Increase (Decrease) in Prepaid Expense | 20,202 | 10,115 |
Accounts payable | (5,192) | 26,593 |
Accrued taxes | 49,833 | 45,130 |
Other current liabilities | (63,096) | (86,250) |
Change in other long-term assets | 81,143 | (65,470) |
Change in other long-term liabilities | (106,212) | 13,706 |
Net cash flow provided by operating activities | 183,628 | 173,432 |
CASH FLOWS FROM INVESTING ACTIVITIES | ||
Capital expenditures | (340,014) | (259,792) |
Contributions in aid of construction | 3,152 | 7,938 |
Allowance for borrowed funds used during construction | (4,076) | (6,665) |
Proceeds from nuclear decommissioning trust sales and other special use funds | 195,087 | 179,048 |
Investment in nuclear decommissioning trust and other special use funds | (195,658) | (179,618) |
Other | 349 | 4,576 |
Net cash flow used for investing activities | (341,160) | (254,513) |
CASH FLOWS FROM FINANCING ACTIVITIES | ||
Issuance of long-term debt | 0 | 497,324 |
Short-term borrowing and payments — net | (76,675) | 172,650 |
Short-term debt borrowings | 751,690 | 0 |
Short-term debt repayments | (226,690) | (5,000) |
Repayment of long-term debt | (150,000) | (500,000) |
Dividends paid on common stock | (86,257) | (80,897) |
Common stock equity issuance - net of purchases | (1,680) | (2,653) |
Net cash flow provided by financing activities | 210,388 | 81,424 |
NET INCREASE IN CASH AND CASH EQUIVALENTS | 52,856 | 343 |
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD | 10,283 | 5,766 |
CASH AND CASH EQUIVALENTS AT END OF PERIOD | 63,139 | 6,109 |
APS | ||
CASH FLOWS FROM OPERATING ACTIVITIES | ||
NET INCOME | 40,218 | 33,149 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation and amortization including nuclear fuel | 173,147 | 167,779 |
Deferred fuel and purchased power | (5,785) | 16,709 |
Deferred fuel and purchased power amortization | (1,808) | 12,872 |
Allowance for equity funds used during construction | (7,697) | (11,188) |
Deferred income taxes | (17,782) | (1,205) |
Deferred investment tax credit | (465) | (353) |
Increase (Decrease) in Accounts and Notes Receivable | (15,045) | (16,541) |
Changes in current assets and liabilities: | ||
Accrued unbilled revenues | 34,731 | 23,093 |
Materials, supplies and fossil fuel | 5,445 | (13,057) |
Income tax receivable | (1,411) | 0 |
Increase (Decrease) in Prepaid Expense | 18,164 | 9,598 |
Accounts payable | (4,038) | 30,774 |
Accrued taxes | 54,243 | 54,234 |
Other current liabilities | (49,149) | (81,627) |
Change in other long-term assets | 82,178 | (64,516) |
Change in other long-term liabilities | (105,117) | 14,525 |
Net cash flow provided by operating activities | 193,591 | 188,132 |
CASH FLOWS FROM INVESTING ACTIVITIES | ||
Capital expenditures | (340,014) | (259,446) |
Contributions in aid of construction | 3,152 | 7,938 |
Allowance for borrowed funds used during construction | (4,076) | (6,665) |
Proceeds from nuclear decommissioning trust sales and other special use funds | 195,087 | 179,048 |
Investment in nuclear decommissioning trust and other special use funds | (195,658) | (179,618) |
Other | (900) | (1,140) |
Net cash flow used for investing activities | (342,409) | (259,883) |
CASH FLOWS FROM FINANCING ACTIVITIES | ||
Issuance of long-term debt | 0 | 497,324 |
Short-term borrowing and payments — net | 0 | 157,500 |
Short-term debt borrowings | 540,000 | 0 |
Short-term debt repayments | (110,000) | 0 |
Repayment of long-term debt | (150,000) | (500,000) |
Dividends paid on common stock | (88,000) | (82,700) |
Net cash flow provided by financing activities | 192,000 | 72,124 |
NET INCREASE IN CASH AND CASH EQUIVALENTS | 43,182 | 373 |
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD | 10,169 | 5,707 |
CASH AND CASH EQUIVALENTS AT END OF PERIOD | $ 53,351 | $ 6,080 |
CONDENSED CONSOLIDATED STATEM_5
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited) - USD ($) $ in Thousands | Total | Common Stock | Treasury Stock | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Noncontrolling Interests | APS | APSCommon Stock | APSAdditional Paid-In Capital | APSRetained Earnings | APSAccumulated Other Comprehensive Income (Loss) | APSNoncontrolling Interests | |
Beginning balance (in shares) at Dec. 31, 2018 | 112,159,896 | 58,135 | 71,264,947 | ||||||||||
Balance at beginning of period at Dec. 31, 2018 | $ 5,348,705 | $ 2,634,265 | $ (4,825) | $ 2,641,183 | $ (47,708) | $ 125,790 | $ 5,786,797 | $ 178,162 | $ 2,721,696 | $ 2,788,256 | $ (27,107) | $ 125,790 | |
Increase (Decrease) in Shareholders' Equity | |||||||||||||
Net Income | 22,791 | 17,918 | 4,873 | 33,149 | 28,276 | 4,873 | |||||||
Other comprehensive income (loss) | 1,207 | 1,207 | 1,080 | 1,080 | |||||||||
Dividends on common stock | (15) | (15) | |||||||||||
Issuance of common stock (in shares) | 180,426 | ||||||||||||
Issuance of common stock | 9,798 | $ 9,798 | |||||||||||
Purchase of treasury stock (in shares) | [1] | (75,791) | |||||||||||
Purchase of treasury stock | [1] | (6,882) | $ (6,882) | ||||||||||
Reissuance of treasury stock for stock-based compensation and other (in shares) | 70,655 | ||||||||||||
Reissuance of treasury stock for stock-based compensation and other | 6,121 | $ 6,121 | 0 | ||||||||||
Ending balance (in shares) at Mar. 31, 2019 | 112,340,322 | 63,271 | 71,264,947 | ||||||||||
Balance at end of period at Mar. 31, 2019 | $ 5,381,725 | $ 2,644,063 | $ (5,586) | 2,659,086 | (46,501) | 130,663 | 5,821,026 | $ 178,162 | 2,721,696 | 2,816,532 | (26,027) | 130,663 | |
Beginning balance (in shares) at Dec. 31, 2019 | 112,540,126 | 112,540,126 | 103,546 | 71,264,947 | |||||||||
Balance at beginning of period at Dec. 31, 2019 | $ 5,553,188 | $ 2,659,561 | $ (9,427) | 2,837,610 | (57,096) | 122,540 | 5,998,803 | $ 178,162 | 2,721,696 | 3,011,927 | (35,522) | 122,540 | |
Increase (Decrease) in Shareholders' Equity | |||||||||||||
Net Income | 34,866 | 29,993 | 4,873 | 40,218 | 35,345 | 4,873 | |||||||
Other comprehensive income (loss) | 1,517 | 1,517 | 1,325 | 1,325 | |||||||||
Dividends on common stock | 8 | 8 | |||||||||||
Issuance of common stock (in shares) | 23,484 | ||||||||||||
Issuance of common stock | 4,826 | $ 4,826 | |||||||||||
Purchase of treasury stock (in shares) | [1] | (20,724) | |||||||||||
Purchase of treasury stock | [1] | (2,086) | $ (2,086) | ||||||||||
Reissuance of treasury stock for stock-based compensation and other (in shares) | 51,968 | ||||||||||||
Reissuance of treasury stock for stock-based compensation and other | $ 4,513 | $ 4,513 | 0 | ||||||||||
Other | (1) | 1 | (2) | (3) | 1 | ||||||||
Ending balance (in shares) at Mar. 31, 2020 | 112,563,610 | 112,563,610 | 72,302 | 71,264,947 | |||||||||
Balance at end of period at Mar. 31, 2020 | $ 5,596,832 | $ 2,664,387 | $ (7,000) | $ 2,867,610 | $ (55,579) | $ 127,414 | $ 6,040,344 | $ 178,162 | $ 2,721,696 | $ 3,047,269 | $ (34,197) | $ 127,414 | |
[1] | Primarily represents shares of common stock withheld from certain stock awards for tax purposes. |
Consolidation and Nature of Ope
Consolidation and Nature of Operations | 3 Months Ended |
Mar. 31, 2020 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Consolidation and Nature of Operations | Consolidation and Nature of Operations The unaudited condensed consolidated financial statements include the accounts of Pinnacle West and our subsidiaries: APS, 4C Acquisition, LLC ("4CA"), Bright Canyon Energy Corporation ("BCE") and El Dorado Investment Company ("El Dorado"). See Note 8 for more information on 4CA matters. Intercompany accounts and transactions between the consolidated companies have been eliminated. The unaudited condensed consolidated financial statements for APS include the accounts of APS and the Palo Verde Generating Station ("Palo Verde") sale leaseback variable interest entities ("VIEs") (see Note 6 for further discussion). Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America ("GAAP"). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Amounts reported in our interim Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the respective annual periods, due to the effects of seasonal temperature variations on energy consumption, timing of maintenance on electric generating units ("EGU"), and other factors. Our condensed consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations, and cash flows for the periods presented. Certain information and footnote disclosures normally included in financial statements prepared in conformity with GAAP have been condensed or omitted pursuant to such regulations, although we believe that the disclosures provided are adequate to make the interim information presented not misleading. The accompanying condensed consolidated financial statements and these notes should be read in conjunction with the audited consolidated financial statements and notes included in our 2019 Form 10-K. Supplemental Cash Flow Information The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands): Three Months Ended 2020 2019 Cash paid during the period for: Income taxes, net of refunds $ (3,002 ) $ 1 Interest, net of amounts capitalized 53,723 63,764 Significant non-cash investing and financing activities: Accrued capital expenditures $ 100,868 $ 95,879 Right-of-use operating lease assets obtained in exchange for operating lease liabilities 2,311 2,293 The following table summarizes supplemental APS cash flow information (dollars in thousands): Three Months Ended 2020 2019 Cash paid during the period for: Income taxes, net of refunds $ — $ — Interest, net of amounts capitalized 52,034 61,387 Significant non-cash investing and financing activities: Accrued capital expenditures $ 100,868 $ 95,879 Right-of-use operating lease assets obtained in exchange for operating lease liabilities 2,311 2,293 |
Revenue
Revenue | 3 Months Ended |
Mar. 31, 2020 | |
Revenue from Contract with Customer [Abstract] | |
Revenue | Revenue Sources of Revenue The following table provides detail of Pinnacle West's consolidated revenue disaggregated by revenue sources (dollars in thousands): Three Months Ended March 31, 2020 2019 Retail Electric Revenue Residential $ 325,073 $ 351,566 Non-Residential 303,351 332,668 Wholesale energy sales 14,668 36,452 Transmission services for others 15,927 15,249 Other sources 2,911 4,595 Total operating revenues $ 661,930 $ 740,530 Retail Electric Revenue. Pinnacle West's retail electric revenue is generated by wholly owned regulated subsidiary APS's sale of electricity to our regulated customers within the authorized service territory at tariff rates approved by the ACC and based on customer usage. Revenues related to the sale of electricity are generally recognized when service is rendered or electricity is delivered to customers. The billing of electricity sales to individual customers is based on the reading of their meters. We obtain customers' meter data on a systematic basis throughout the month, and generally bill customers within a month from when service was provided. Customers are generally required to pay for services within 15 days of when the services are billed. Wholesale Energy Sales and Transmission Services for Others. Revenues from wholesale energy sales and transmission services for others represent energy and transmission sales to wholesale customers. These activities primarily consist of managing fuel and purchased power risks in connection with the cost of serving our retail customers' energy requirements. We may also sell into the wholesale markets generation that is not needed for APS’s retail load. Our wholesale activities and tariff rates are regulated by the United States Federal Energy Regulatory Commission ("FERC"). In the electricity business, some contracts to purchase energy are settled by netting against other contracts to sell electricity. This is referred to as a book-out, and usually occurs in contracts that have the same terms (product type, quantities, and delivery points) and for which power does not flow. We net these book-outs, which reduces both wholesale revenues and fuel and purchased power costs. Revenue Activities Our revenues primarily consist of activities that are classified as revenues from contracts with customers. We derive our revenues from contracts with customers primarily from sales of electricity to our regulated retail customers. Revenues from contracts with customers also include wholesale and transmission activities. Our revenues from contracts with customers for the three months ended March 31, 2020 and 2019 were $648 million and $721 million, respectively. We have certain revenues that do not meet the specific accounting criteria to be classified as revenues from contracts with customers. For the three months ended March 31, 2020 and 2019 , our revenues that do not qualify as revenue from contracts with customers were $14 million and $20 million , respectively. This relates primarily to certain regulatory cost recovery mechanisms that are considered alternative revenue programs. We recognize revenue associated with alternative revenue programs when specific events permitting recognition are completed. Certain amounts associated with alternative revenue programs will subsequently be billed to customers; however, we do not reclassify billed amounts into revenue from contracts with customers. See Note 4 for a discussion of our regulatory cost recovery mechanisms. Contract Assets and Liabilities from Contracts with Customers There were no material contract assets, contract liabilities, or deferred contract costs recorded on the Condensed Consolidated Balance Sheets as of March 31, 2020 or December 31, 2019 . Allowance for Doubtful Accounts The allowance for doubtful accounts represents our best estimate of accounts receivable and accrued unbilled revenues that will ultimately be uncollectible. The allowance is calculated by applying an estimated write-off factor to retail electric revenues. The write-off factor used to estimate uncollectible accounts is based upon consideration of historical collections experience, the current and forecasted economic environment, changes to our collection policies, and management’s best estimate of future collections success. During March 2020, due to the Coronavirus ("COVID-19") pandemic, and to assist customers who may be experiencing economic difficulties, we suspended all service shut-offs due to nonpayment. We are expecting an increase in the number of customers needing to utilize longer-term payment plans to avoid service disruption. These changes, among others including the Summer Disconnection Moratorium (defined in Note 4), impacted our write-off factor during the period. We continue to monitor COVID-19 and its impact on our allowance for doubtful accounts, which may impact our write-off factor for upcoming 2020 financial statements. See Note 4 for additional details. The following table provides a rollforward of Pinnacle West’s allowance for doubtful accounts (dollars in thousands): March 31, 2020 December 31, 2019 Allowance for doubtful accounts, balance at beginning of period $ 8,171 $ 4,069 Bad debt expense 3,122 11,819 Actual write-offs (2,927 ) (7,717 ) Allowance for doubtful accounts, balance at end of period $ 8,366 $ 8,171 |
Long-Term Debt and Liquidity Ma
Long-Term Debt and Liquidity Matters | 3 Months Ended |
Mar. 31, 2020 | |
Debt Disclosure [Abstract] | |
Long-Term Debt and Liquidity Matters | Long-Term Debt and Liquidity Matters Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs, to refinance indebtedness, and for other general corporate purposes. Pinnacle West At March 31, 2020 , Pinnacle West had a $200 million revolving credit facility that matures in July 2023. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on Pinnacle West's senior unsecured debt credit ratings. The facility is available to support Pinnacle West's $200 million commercial paper program, for bank borrowings or for issuances of letters of credits. At March 31, 2020 , Pinnacle West had $100 million outstanding borrowings under its credit facility, no letters of credit outstanding and no commercial paper borrowings. On May 5, 2020, Pinnacle West refinanced its 364-day $50 million term loan agreement that would have matured on May 7, 2020 with a new 364-day $31 million term loan agreement that matures on May 4, 2021. Borrowings under the agreement bear interest at London Inter-bank Offered Rate ("LIBOR") plus 1.40% per annum. At March 31, 2020, Pinnacle West had $33 million in outstanding borrowings under the prior agreement. APS On January 15, 2020, APS repaid at maturity the remaining $150 million of the $250 million aggregate principal amount of its 2.2% Senior Notes. At March 31, 2020 , APS had two revolving credit facilities totaling $1 billion , including a $500 million credit facility that matures in June 2022 and a $500 million facility that matures in July 2023. APS may increase the amount of each facility up to a maximum of $700 million , for a total of $1.4 billion , upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on APS’s senior unsecured debt credit ratings. These facilities are available to support APS’s $500 million commercial paper program, for bank borrowings or for issuances of letters of credit. At March 31, 2020, APS had $430 million outstanding borrowings under its revolving credit facilities and no letters of credit outstanding or commercial paper borrowings. On November 27, 2018, the ACC issued a financing order in which, subject to specified parameters and procedures, it approved APS’s short-term debt authorization equal to a sum of (i) 7% of APS’s capitalization, and (ii) $500 million (which is required to be used for costs relating to purchases of natural gas and power) and a long-term debt authorization of $5.9 billion . On March 27, 2020, APS filed an application with the ACC to increase the long-term debt limit from $5.9 billion to $7.5 billion and to continue its authorization of short-term debt granted in the 2018 financing order. See "Financial Assurances" in Note 8 for a discussion of other outstanding letters of credit. Debt Fair Value Our long-term debt fair value estimates are classified within Level 2 of the fair value hierarchy. The following table presents the estimated fair value of our long-term debt, including current maturities (dollars in thousands): As of March 31, 2020 As of December 31, 2019 Carrying Amount Fair Value Carrying Amount Fair Value Pinnacle West $ 449,581 $ 448,449 $ 449,425 $ 450,822 APS 5,033,743 5,634,265 5,183,133 5,743,570 Total $ 5,483,324 $ 6,082,714 $ 5,632,558 $ 6,194,392 |
Regulatory Matters
Regulatory Matters | 3 Months Ended |
Mar. 31, 2020 | |
Regulated Operations [Abstract] | |
Regulatory Matters | Regulatory Matters COVID-19 Pandemic Due to the COVID-19 pandemic, APS has voluntarily suspended disconnections of customers for nonpayment beginning March 13, 2020. In addition, APS has waived all late payment fees during this current moratorium. APS currently estimates that the Summer Disconnection Moratorium (see below for discussion of the Summer Disconnection Moratorium), the suspension of disconnections during the COVID-19 pandemic and the increased bad debt expense associated with both events will result in a negative impact to its 2020 operating results of approximately $20 to $30 million pre-tax above the impact of disconnections on its operating results for years that did not have the Summer Disconnection Moratorium or COVID-19 pandemic. APS is anticipating an increase in bad debt expense associated with the COVID-19 pandemic, but it still believes that costs associated with the Summer Disconnection Moratorium and the COVID-19 disconnection suspensions and related bad debt expense with both events will fall within this estimated $20 to $30 million range. These estimated impact amounts depend on certain assumptions, including customer behaviors and the impacts of COVID-19 on the economy not extending into 2021. APS also established a customer support fund of $1.5 million to assist customers with a one-time credit of up to $100 on their bill with a priority given to customers on limited-income service plans. Additionally, due to COVID-19, APS delayed the reset of the Environmental Improvement Surcharge ("EIS") adjustor and suspended the discontinuation of TEAM Phase II to the first billing cycle in May 2020 rather than April 2020 (see below for discussion of EIS and TEAM Phase II). On April 17, 2020, APS filed an application with the ACC requesting a COVID-19 emergency relief package to provide additional assistance to its customers. On May 5, 2020, the ACC approved APS returning $36 million that has been collected through the Demand Side Management ("DSM") Adjustor Clause, but not allocated for current DSM programs, directly to customers through a bill credit in June 2020 (see below for discussion of the DSM Adjustor Clause). Also, on May 5, 2020, APS also voluntarily committed to the ACC to contribute $5.3 million of non-ratepayer funds to provide assistance to residential and business customers that have been impacted by the COVID-19 pandemic. 2019 Retail Rate Case Filing with the Arizona Corporation Commission On October 31, 2019, APS filed an application with the ACC for an annual increase in retail base rates of $69 million . This amount includes recovery of the deferral and rate base effects of the Four Corners selective catalytic reduction ("SCR") project that is currently the subject of a separate proceeding (see “SCR Cost Recovery” below). It also reflects a net credit to base rates of approximately $115 million primarily due to the prospective inclusion of rate refunds currently provided through the Tax Expense Adjustment Mechanism ("TEAM"). The proposed total revenue increase in APS's application is $184 million . The average annual customer bill impact of APS’s request is an increase of 5.6% (the average annual bill impact for a typical APS residential customer is 5.4% ). The principal provisions of APS's application are: • a test year comprised of twelve months ended June 30, 2019, adjusted as described below; • an original cost rate base of $8.87 billion , which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits; • the following proposed capital structure and costs of capital: Capital Structure Cost of Capital Long-term debt 45.3 % 4.10 % Common stock equity 54.7 % 10.15 % Weighted-average cost of capital 7.41 % • a 1% return on the increment of fair value rate base above APS’s original cost rate base, as provided for by Arizona law; • authorization to defer until APS's next general rate case the increase or decrease in its Arizona property taxes attributable to tax rate changes after the date the rate application is adjudicated; • a number of proposed rate and program changes for residential customers, including: ▪ a super off-peak period during the winter months for APS’s time-of-use with demand rates; ▪ additional $1.25 million in funding for APS's limited-income crisis bill program; and ▪ a flat bill/subscription rate pilot program; • proposed rate design changes for commercial customers, including an experimental program designed to provide access to market pricing for up to 200 MW of medium and large commercial customers; • recovery of the deferral and rate base effects of the construction and operating costs of the Ocotillo modernization project ( see discussion below of the 2017 Settlement Agreement ); and • continued recovery of the remaining investment and other costs related to the retirement and closure of the Navajo Generating Station (the "Navajo Plant") (see "Navajo Plant" below). APS requested that the increase become effective December 1, 2020. The hearing for this rate case was delayed by 75 days, at the request of ACC Staff, and is currently scheduled to begin September 30, 2020. APS cannot predict the outcome of its request. 2016 Retail Rate Case Filing with the Arizona Corporation Commission On June 1, 2016, APS filed an application with the ACC for an annual increase in retail base rates. On March 27, 2017, a majority of the stakeholders in the general retail rate case, including the ACC Staff, the Residential Utility Consumer Office, limited income advocates and private rooftop solar organizations signed a settlement agreement (the "2017 Settlement Agreement") and filed it with the ACC. The 2017 Settlement Agreement provides for a net retail base rate increase of $94.6 million , excluding the transfer of adjustor balances, consisting of: (1) a non-fuel, non-depreciation, base rate increase of $87.2 million per year; (2) a base rate decrease of $53.6 million attributable to reduced fuel and purchased power costs; and (3) a base rate increase of $61.0 million due to changes in depreciation schedules. The average annual customer bill impact under the 2017 Settlement Agreement was calculated as an increase of 3.28% (the average annual bill impact for a typical APS residential customer was calculated as an increase of 4.54% ). Other key provisions of the agreement include the following: • an agreement by APS not to file another general retail rate case application before June 1, 2019; • an authorized return on common equity of 10.0% ; • a capital structure comprised of 44.2% debt and 55.8% common equity; • a cost deferral order for potential future recovery in APS’s next general retail rate case for the construction and operating costs APS incurs for its Ocotillo modernization project; • a cost deferral and procedure to allow APS to request rate adjustments prior to its next general retail rate case related to its share of the construction costs associated with installing SCR equipment at the Four Corners Power Plant ("Four Corners"); • a deferral for future recovery (or credit to customers) of the Arizona property tax expense above or below a specified test year level caused by changes to the applicable Arizona property tax rate; • an expansion of the Power Supply Adjustor (“PSA”) to include certain environmental chemical costs and third-party energy storage costs; • a new AZ Sun II program (now known as "APS Solar Communities") for utility-owned solar distributed generation with the purpose of expanding access to rooftop solar for low and moderate income Arizonans, recoverable through the Arizona Renewable Energy Standard and Tariff ("RES"), to be no less than $10 million per year in capital costs, and not more than $15 million per year in capital costs; • an increase to the per kWh cap for the environmental improvement surcharge from $0.00016 to $0.00050 and the addition of a balancing account; • rate design changes, including: ▪ a change in the on-peak time of use period from noon - 7 p.m. to 3 p.m. - 8 p.m. Monday through Friday, excluding holidays; ▪ non-grandfathered distributed generation ("DG") customers would be required to select a rate option that has time of use rates and either a new grid access charge or demand component; ▪ a Resource Comparison Proxy (“RCP”) for exported energy of 12.9 cents per kWh in year one; and • an agreement by APS not to pursue any new self-build generation (with certain exceptions) having an in-service date prior to January 1, 2022 (extended to December 31, 2027 for combined-cycle generating units), unless expressly authorized by the ACC. Through a separate agreement, APS, industry representatives, and solar advocates committed to stand by the 2017 Settlement Agreement and refrain from seeking to undermine it through ballot initiatives, legislation or advocacy at the ACC. On August 15, 2017, the ACC approved (by a vote of 4-1), the 2017 Settlement Agreement without material modifications. On August 18, 2017, the ACC issued a final written Opinion and Order reflecting its decision in APS’s general retail rate case (the "2017 Rate Case Decision"), which is subject to requests for rehearing and potential appeal. The new rates went into effect on August 19, 2017. On January 3, 2018, an APS customer filed a petition with the ACC that was determined by the ACC Staff to be a complaint filed pursuant to Arizona Revised Statute §40-246 (the “Complaint”). The Complaint was later amended alleging that the rates and charges in the 2017 Rate Case Decision are not just and reasonable. The ACC held a hearing on this matter and the hearing was concluded on October 1, 2018. On April 9, 2019, the Administrative Law Judge issued a Recommended Opinion and Order recommending that the Complaint be dismissed. On July 3, 2019, the Administrative Law Judge issued an amendment to the Recommended Opinion and Order that incorporated the requirements of the rate review of the 2017 Rate Case Decision (see below discussion regarding the rate review). On July 10, 2019, the ACC adopted the Administrative Law Judge's amended Recommended Opinion and Order along with several ACC Commissioner amendments and an amendment incorporating the results of the rate review and resolved the Complaint. On December 24, 2018, certain ACC Commissioners filed a letter stating that because the ACC had received a substantial number of complaints that the rate increase authorized by the 2017 Rate Case Decision was much more than anticipated, they believe there is a possibility that APS is earning more than was authorized by the 2017 Rate Case Decision. Accordingly, the ACC Commissioners requested the ACC Staff to perform a rate review of APS using calendar year 2018 as a test year. The ACC Commissioners also asked the ACC Staff to evaluate APS’s efforts to educate its customers regarding the new rates approved in the 2017 Rate Case Decision. On June 4, 2019, the ACC Staff filed a proposed order regarding the rate review of the 2017 Rate Case Decision. On June 11, 2019, the ACC Commissioners approved the proposed ACC Staff order with amendments. The key provisions of the amended order include the following: • APS must file a rate case no later than October 31, 2019, using a June 30, 2019 test-year; • until the conclusion of the rate case being filed no later than October 31, 2019, APS must provide information on customer bills that shows how much a customer would pay on their most economical rate given their actual usage during each month; • APS customers can switch rate plans during an open enrollment period of six months; • APS must identify customers whose bills have increased by more than 9% and that are not on the most economical rate and provide such customers with targeted education materials and an opportunity to switch rate plans; • APS must provide grandfathered net metering customers on legacy demand rates an opportunity to switch to another legacy rate to enable such customers to fully benefit from legacy net metering rates; • APS must fund and implement a supplemental customer education and outreach program to be developed with and administered by ACC Staff and a third-party consultant; and • APS must fund and organize, along with the third-party consultant, a stakeholder group to suggest better ways to communicate the impact of changes to adjustor cost recovery mechanisms (see below for discussion on cost recovery mechanisms), including more effective ways to educate customers on rate plans and to reduce energy usage. APS cannot predict the outcome or impact of the rate case filed on October 31, 2019. APS does not believe that the implementation of the other key provisions of the amended order regarding the rate review will have a material impact on its financial position, results of operations or cash flows. Cost Recovery Mechanisms APS has received regulatory decisions that allow for more timely recovery of certain costs outside of a general retail rate case through the following recovery mechanisms. Renewable Energy Standard . In 2006, the ACC approved the RES. Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies. In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects. Each year APS is required to file a five -year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget. In 2015, the ACC revised the R ES rules to allow the ACC to consider all available information, including the number of rooftop solar arrays in a utility’s service territory, to determine compliance with the RES. On November 20, 2017, APS filed an updated 2018 RES budget to include budget adjustments for APS Solar Communities (formerly known as AZ Sun II), which was approved as part of the 2017 Rate Case Decision. APS Solar Communities is a 3 -year program authorizing APS to spend $10 million to $15 million in capital costs each year to install utility-owned DG systems for low to moderate income residential homes, non-profit entities, Title I schools and rural government facilities. The 2017 Rate Case Decision provided that all operations and maintenance expenses, property taxes, marketing and advertising expenses, and the capital carrying costs for this program will be recovered through the RES. On June 29, 2018, APS filed its 2019 RES Implementation Plan and proposed a budget of approximately $89.9 million . APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the residential distributed energy requirement for 2019 contained in the RES rules. On October 29, 2019, the ACC approved the 2019 RES Implementation Plan including a waiver of the residential distributed energy requirements for the 2019 implementation year. On July 1, 2019, APS filed its 2020 RES Implementation Plan and proposed a budget of approximately $86.3 million . APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the residential distributed energy requirement for 2020 contained in the RES rules. The ACC has not yet ruled on the 2020 RES Implementation Plan. On July 2, 2019, ACC Staff issued draft rules, which propose a RES goal of 45% of retail energy served be renewables by 2035 and a goal of 20% of retail sales during peak demand to be from clean energy resources by 2035. The draft rules would also require a certain amount of the RES goal to be derived from distributed renewable storage, for which utilities would be required to offer performance-based incentives. Nuclear energy would be considered a clean resource under the draft rules. On February 18, 2020, ACC Staff issued revised draft rules which would change the RES and clean energy goals to standards and would provide additional reporting and compliance requirements. Certain ACC Commissioners have proposed different options with different implementation dates of these rules. APS cannot predict the outcome of this matter. See "Energy Modernization Plan" below for more information. Demand Side Management Adjustor Charge . The ACC Electric Energy Efficiency Standards require APS to submit a Demand Side Management Implementation Plan ("DSM Plan") annually for review by and approval of the ACC. Verified energy savings from APS's resource savings projects can be counted toward compliance with the Electric Energy Efficiency Standards; however, APS is not allowed to count savings from systems savings projects toward determination of the achievement of performance incentives, nor may APS include savings from these system savings projects in the calculation of its Lost Fixed Cost Recovery (“LFCR”) mechanism (see below for discussion of the LFCR). On September 1, 2017, APS filed its 2018 DSM Plan, which proposes modifications to the demand side management portfolio to better meet system and customer needs by focusing on peak demand reductions, storage, load shifting and demand response programs in addition to traditional energy savings measures. The 2018 DSM Plan seeks a requested budget of $52.6 million and requests a waiver of the Electric Energy Efficiency Standard for 2018. On November 14, 2017, APS filed an amended 2018 DSM Plan, which revised the allocations between budget items to address customer participation levels, but kept the overall budget at $52.6 million . The ACC has not yet ruled on the APS 2018 amended DSM Plan. On December 31, 2018, APS filed its 2019 DSM Plan, which requests a budget of $34.1 million and continues APS's focus on DSM strategies such as peak demand reduction, load shifting, storage and electrification strategies. The ACC has not yet ruled on the APS 2019 DSM Plan. On December 31, 2019, APS filed its 2020 DSM Plan, which requests a budget of $51.9 million and continues APS's focus on DSM strategies such as peak demand reduction, load shifting, storage and electrification strategies. The 2020 DSM Plan addresses all components of the 2018 and 2019 DSM plans, which enables the ACC to review the 2020 DSM Plan only. The ACC has not yet ruled on the APS 2020 DSM Plan. On April 17, 2020, APS filed an application with the ACC requesting a COVID-19 emergency relief package to provide additional assistance to its customers. On May 5, 2020, the ACC approved APS returning $36 million that has been collected through the DSM Adjustor Clause, but not allocated for current DSM programs, directly to customers through a bill credit in June 2020. See "COVID-19 Pandemic" above for more information. Power Supply Adjustor Mechanism and Balance. The PSA provides for the adjustment of retail rates to reflect variations primarily in retail fuel and purchased power costs. The following table shows the changes in the deferred fuel and purchased power regulatory asset for 2020 and 2019 (dollars in thousands): Three Months Ended 2020 2019 Beginning balance $ 70,137 $ 37,164 Deferred fuel and purchased power costs — current period 5,785 (16,709 ) Amounts charged to customers 1,808 (12,872 ) Ending balance $ 77,730 $ 7,583 The PSA rate for the PSA year beginning February 1, 2018 is $0.004555 per kWh, consisting of a forward component of $0.002009 per kWh and a historical component of $0.002546 per kWh. This represented a $0.004 per kWh increase over the August 19, 2017 PSA, the maximum permitted under the Plan of Administration for the PSA. This left $16.4 million of 2017 fuel and purchased power costs above this annual cap. These costs rolled over into the following year and were reflected in the 2019 reset of the PSA. The PSA rate for the PSA year beginning February 1, 2019 was $0.001658 per kWh , consisting of a Forward Component of $0.000536 per kWh and a Historical Component of $0.001122 per kWh. This represented a $0.002897 per kWh decrease compared to 2018. These rates went into effect as filed on February 1, 2019. On November 27, 2019, APS filed its PSA rate for the PSA year beginning February 1, 2020. That rate was $( 0.000456 ) per kWh and consisted of a Forward Component of $( 0.002086 ) per kWh and a Historical Component of $0.001630 per kWh. The 2020 PSA rate is a $0.002115 per kWh decrease compared to the 2019 PSA year. These rates went into effect as filed on February 1, 2020. On March 15, 2019, APS filed an application with the ACC requesting approval to recover the costs related to two energy storage power purchase tolling agreements through the PSA. This application is pending with the ACC. APS cannot predict the outcome of this matter. Environmental Improvement Surcharge. The EIS permits APS to recover the capital carrying costs (rate of return, depreciation and taxes) plus incremental operations and maintenance expenses associated with environmental improvements made outside of a test year to comply with environmental standards set by federal, state, tribal, or local laws and regulations. A filing is made on or before February 1st for qualified environmental improvements made during the prior calendar year, and the new charge becomes effective April 1 unless suspended by the ACC. There is an overall cap of $0.0005 per kWh (approximately $13 - 14 million per year). APS’s February 1, 2020 application requested an increase in the charge to $8.75 million , or $2.0 million over the charge in effect for the 2019-2020 rate effective year. On March 19, 2020, due to the COVID-19 pandemic, APS delayed the reset of the EIS adjustor to the first billing cycle in May 2020 rather than April 2020. Transmission Rates, Transmission Cost Adjustor ("TCA") and Other Transmission Matters . In July 2008, FERC approved a modification to APS’s Open Access Transmission Tariff to allow APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services. A large portion of the rate represents charges for transmission services to serve APS's retail customers ("Retail Transmission Charges"). In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA. Under the terms of the settlement agreement entered into in 2012 regarding APS's rate case ("2012 Settlement Agreement"), however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC. The formula rate is updated each year effective June 1 on the basis of APS's actual cost of service, as disclosed in APS's FERC Form 1 report for the previous fiscal year. Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items. The resolution of proposed adjustments can result in significant volatility in the revenues to be collected. APS reviews the proposed formula rate filing amounts with the ACC Staff. Any items or adjustments which are not agreed to by APS and the ACC Staff can remain in dispute until settled or litigated at FERC. Settlement or litigated resolution of disputed issues could require an extended period of time and could have a significant effect on the Retail Transmission Charges because any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts. On March 7, 2018, APS made a filing to make modifications to its annual transmission formula to provide transmission customers the benefit of the reduced federal corporate income tax rate resulting from the Tax Cuts and Jobs Act ("Tax Act") beginning in its 2018 annual transmission formula rate update filing. These modifications were approved by FERC on May 22, 2018 and reduced APS’s transmission rates compared to the rate that would have gone into effect absent these changes. On March 17, 2020, APS made a filing to make further modifications to its annual transmission formula to provide additional transparency for excess and deficient Accumulated Deferred Income Taxes resulting from the Tax Act, as well as for future local, state, and federal statutory tax rate changes. This filing is pending with FERC. Effective June 1, 2018, APS's annual wholesale transmission rates for all users of its transmission system decreased by approximately $22.7 million for the twelve-month period beginning June 1, 2018 in accordance with the FERC-approved formula. An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2018. Effective June 1, 2019, APS's annual wholesale transmission rates for all users of its transmission system increased by approximately $4.9 million for the twelve-month period beginning June 1, 2019 in accordance with the FERC-approved formula. An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2019. Lost Fixed Cost Recovery Mechanism . The LFCR mechanism permits APS to recover on an after-the-fact basis a portion of its fixed costs that would otherwise have been collected by APS in the kWh sales lost due to APS energy efficiency programs and to DG such as rooftop solar arrays. The fixed costs recoverable by the LFCR mechanism were first established in the 2012 Settlement Agreement and amount to approximately 3.1 cents per residential kWh lost and 2.3 cents per non-residential kWh lost. These amounts were revised in the 2017 Settlement Agreement to 2.5 cents for both lost residential and non-residential kWh. The LFCR adjustment has a year-over-year cap of 1% of retail revenues. Any amounts left unrecovered in a particular year because of this cap can be carried over for recovery in a future year. The kWhs lost from energy efficiency are based on a third-party evaluation of APS’s energy efficiency programs. DG sales losses are determined from the metered output from the DG units. On February 15, 2018, APS filed its 2018 annual LFCR adjustment, requesting that effective May 1, 2018, the LFCR be adjusted to $60.7 million . On February 6, 2019, the ACC approved the 2018 annual LFCR adjustment to become effective March 1, 2019. On February 15, 2019, APS filed its 2019 annual LFCR adjustment, requesting that effective May 1, 2019, the annual LFCR recovery amount be reduced to $36.2 million (a $24.5 million decrease from previous levels). On July 10, 2019, the ACC approved APS’s 2019 LFCR adjustment as filed, effective with the next billing cycle of July 2019. On February 14, 2020, APS filed its 2020 annual LFCR adjustment, requesting that effective May 1, 2020, the annual LFCR recovery amount be reduced to $26.6 million (a $9.6 million decrease from previous levels). On April 14, 2020, the ACC approved the 2020 LFCR adjustment as filed, effective with the first billing cycle in May 2020. Tax Expense Adjustor Mechanism . As part of the 2017 Settlement Agreement, the parties agreed to a rate adjustment mechanism to address potential federal income tax reform and enable the pass-through of certain income tax effects to customers. The TEAM expressly applies to APS's retail rates with the exception of a small subset of customers taking service under specially-approved tariffs. On December 22, 2017, the Tax Act was enacted. This legislation made significant changes to the federal income tax laws including a reduction in the corporate tax rate from 35% to 21% effective January 1, 2018. On January 8, 2018, APS filed an application with the ACC that addressed the change in the marginal federal tax rate from 35% to 21% resulting from the Tax Act and reduced rates by $119.1 million annually through an equal cents per kWh credit ("TEAM Phase I"). On February 22, 2018, the ACC approved the reduction of rates through an equal cents per kWh credit. The rate reduction was effective for the first billing cycle in March 2018. The impact of the TEAM Phase I, over time, is expected to be earnings neutral. However, on a quarterly basis, there is a difference between the timing and amount of the income tax benefit and the reduction in revenues refunded through the TEAM Phase I related to the lower federal income tax rate. The amount of the benefit of the lower federal income tax rate is based on quarterly pre-tax results, while the reduction in revenues refunded through the TEAM Phase I is based on a per kWh sales credit which follows our seasonal kWh sales pattern and is not impacted by earnings of the Company. On August 13, 2018, APS filed a second request with the ACC that addressed the return of an additional $86.5 million in tax savings to customers related to the amortization of non-depreciation related excess deferred taxes previously collected from customers ("TEAM Phase II"). The ACC approved this request on March 13, 2019, effective the first billing cycle in April 2019 through the last billing cycle in March 2020. On March 19, 2020, due to the COVID-19 pandemic, APS delayed the discontinuation of TEAM Phase II until the first billing cycle in May 2020. Amounts credited to customers after the last billing cycle in March 2020 will be recorded as a part of the balancing account and will be addressed for recovery as part of APS's 2019 ACC rate case. Both the timing of the reduction in revenues refunded through TEAM Phase II and the offsetting income tax benefit are recognized based upon our seasonal kWh sales pattern. On April 10, 2019, APS filed a third request with the ACC that addressed the amortization of depreciation related excess deferred taxes over a 28.5 year period consistent with IRS normalization rules (“TEAM Phase III”). On October 29, 2019, the ACC approved TEAM Phase III providing both (i) a one-time bill credit of $64 million which was credited to customers on their December 2019 bills, and (ii) a monthly bill credit effective the first billing cycle in December 2019 which will provide an additional benefit of $39.5 million to customers through December 31, 2020. It is currently anticipated that benefits related to the amortization of depreciation related excess deferred taxes for periods beginning after December 31, 2020 will be fully incorporated into the 2019 rate case. Net Metering In 2015, the ACC voted to conduct a generic evidentiary hearing on the value and cost of DG to gather information that will inform the ACC on net metering issues and cost of service studies in upcoming utility rate cases. A hearing was held in April 2016. On October 7, 2016, the Administrative Law Judge issued a recommendation in the docket concerning the value and cost of DG solar installations. On December 20, 2016, the ACC completed its open meeting to consider the recommended opinion and order by the Administrative Law Judge. After making several amendments, the ACC approved the recommended decision by a 4-1 vote. As a result of the ACC’s action, effective with APS’s 2017 Rate Case Decision, the net metering tariff that governs payments for energy exported to the grid from residential rooftop solar systems was replaced by a more formula-driven approach that utilizes inputs from historical wholesale solar power until an avoided cost methodology is developed by the ACC. As amended, the decision provides that payments by utilities for energy exported to the grid from DG solar facilities will be determined using a RCP methodology, a method that is based on the most recent five-year rolling average price that APS pays for utility-scale solar projects, while a forecasted avoided cost methodology is being developed. The price established by this RCP method will be updated annually (between general retail rate cases) but will not be decreased by more than 10% per year. Once the avoided cost methodology is developed, the ACC will determine in APS's subsequent rate cases which method (or a combination of methods) is appropriate to determine the actual price to be paid by APS for exported distributed energy. In addition, the ACC made the following determinations: • Customers who have interconnected a DG system or submitted an application for interconnection for DG systems prior to September 1, 2017, based on APS's 2017 Rate Case Decision, will be grandfathered for a period of 20 years from the date the customer’s interconnection application was accepted by the utility; • Customers with DG solar systems are to be considered a separate class of customers for ratemaking |
Retirement Plans and Other Post
Retirement Plans and Other Postretirement Benefits | 3 Months Ended |
Mar. 31, 2020 | |
Retirement Benefits [Abstract] | |
Retirement Plans and Other Postretirement Benefits | Retirement Plans and Other Postretirement Benefits Pinnacle West sponsors a qualified defined benefit and account balance pension plan, a non-qualified supplemental excess benefit retirement plan, and an other postretirement benefit plan for the employees of Pinnacle West and our subsidiaries. Pinnacle West uses a December 31 measurement date for its pension and other postretirement benefit plans. The market-related value of our plan assets is their fair value at the measurement dates. The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction or billed to electric plant participants) (dollars in thousands): Pension Benefits Other Benefits Three Months Ended Three Months Ended 2020 2019 2020 2019 Service cost — benefits earned during the period $ 14,257 $ 12,543 $ 5,717 $ 4,714 Non-service costs (credits): Interest cost on benefit obligation 29,761 34,352 6,512 7,526 Expected return on plan assets (46,806 ) (42,893 ) (10,019 ) (9,603 ) Amortization of: Prior service credit — — (9,394 ) (9,455 ) Net actuarial loss 9,011 11,239 — — Net periodic benefit cost (credit) $ 6,223 $ 15,241 $ (7,184 ) $ (6,818 ) Portion of cost (credit) charged to expense $ 1,342 $ 8,244 $ (5,456 ) $ (4,817 ) Contributions We have not made voluntary contributions to our pension plan year-to-date in 2020. The minimum required contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions up to $100 million per year during the 2020-2022 period. We do not expect to make any contributions over the next three years to our other postretirement benefit plans. |
Palo Verde Sale Leaseback Varia
Palo Verde Sale Leaseback Variable Interest Entities | 3 Months Ended |
Mar. 31, 2020 | |
Variable Interest Entities [Abstract] | |
Palo Verde Sale Leaseback Variable Interest Entities | Palo Verde Sale Leaseback Variable Interest Entities In 1986, APS entered into agreements with three separate VIE lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. APS will retain the assets through 2023 under one lease and 2033 under the other two leases. APS will be required to make payments relating to these leases of approximately $23 million annually for the period 2020 through 2023, and $16 million annually for the period 2024 through 2033. At the end of the lease period, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to two years , or return the assets to the lessors. The leases' terms give APS the ability to utilize the assets for a significant portion of the assets’ economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the VIEs’ economic performance. Predominantly due to the lease terms, APS has been deemed the primary beneficiary of these VIEs and therefore consolidates the VIEs. As a result of consolidation, we eliminate lease accounting and instead recognize depreciation expense, resulting in an increase in net income for the three months ended March 31, 2020 and 2019 of $ 5 million for each period, entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders is not impacted by the consolidation. Our Condensed Consolidated Balance Sheets at March 31, 2020 and December 31, 2019 include the following amounts relating to the VIEs (dollars in thousands): March 31, 2020 December 31, 2019 Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation $ 100,938 $ 101,906 Equity — Noncontrolling interests 127,414 122,540 Assets of the VIEs are restricted and may only be used for payment to the noncontrolling interest holders. These assets are reported on our condensed consolidated financial statements. APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the Nuclear Regulatory Commission ("NRC") issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event were to occur during the lease periods, APS may be required to pay the noncontrolling equity participants approximately $304 million beginning in 2020, and up to $456 million over the lease extension terms. For regulatory ratemaking purposes, the agreements continue to be treated as operating leases and, as a result, we have recorded a regulatory asset relating to the arrangements. |
Derivative Accounting
Derivative Accounting | 3 Months Ended |
Mar. 31, 2020 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Accounting | Derivative Accounting Derivative financial instruments are used to manage exposure to commodity price and transportation costs of electricity, natural gas, emissions allowances, and in interest rates. Risks associated with market volatility are managed by utilizing various physical and financial derivative instruments, including futures, forwards, options and swaps. As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and fuels. Derivative instruments that meet certain hedge accounting criteria may be designated as cash flow hedges and are used to limit our exposure to cash flow variability on forecasted transactions. The changes in market value of such instruments have a high correlation to price changes in the hedged transactions. Derivative instruments are also entered into for economic hedging purposes. While economic hedges may mitigate exposure to fluctuations in commodity prices, these instruments have not been designated as accounting hedges. Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our Condensed Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows. Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the balance sheets as an asset or liability and are measured at fair value. See Note 11 for a discussion of fair value measurements. Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery and the quantities represent those transacted in the normal course of business. Derivative instruments qualifying for the normal purchases and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below. For its regulated operations, APS defers for future rate treatment 100% of the unrealized gains and losses on derivatives pursuant to the PSA mechanism that would otherwise be recognized in income. Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate (see Note 4 ). Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals. As of March 31, 2020 and December 31, 2019 , we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): Quantity Commodity Unit of Measure March 31, 2020 December 31, 2019 Power GWh 477 193 Gas Billion cubic feet 263 257 Gains and Losses from Derivative Instruments The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the three months ended March 31, 2020 and 2019 (dollars in thousands): Financial Statement Location Three Months Ended Commodity Contracts 2020 2019 Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a) Fuel and purchased power (b) $ (414 ) $ (436 ) (a) During the three months ended March 31, 2020 and 2019 , we had no gains or losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges . (b) Amounts are before the effect of PSA deferrals. During the next twelve months, we estimate that a net loss of approximately $0.3 million before income taxes will be reclassified from accumulated OCI as an offset to the effect of market price changes for the related hedged transactions. In accordance with the PSA, most of these amounts will be recorded as either a regulatory asset or liability and have no immediate effect on earnings. The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the three months ended March 31, 2020 and 2019 (dollars in thousands): Financial Statement Location Three Months Ended Commodity Contracts 2020 2019 Net Gain (Loss) Recognized in Income Fuel and purchased power (a) $ (30,078 ) $ 8,170 (a) Amounts are before the effect of PSA deferrals. Derivative Instruments in the Condensed Consolidated Balance Sheets Our derivative transactions are typically executed under standardized or customized agreements, which include collateral requirements and, in the event of a default, would allow for the netting of positive and negative exposures associated with a single counterparty. Agreements that allow for the offsetting of positive and negative exposures associated with a single counterparty are considered master netting arrangements. Transactions with counterparties that have master netting arrangements are offset and reported net on the Condensed Consolidated Balance Sheets. Transactions that do not allow for offsetting of positive and negative positions are reported gross on the Condensed Consolidated Balance Sheets. We do not offset a counterparty’s current derivative contracts with the counterparty’s non-current derivative contracts, although our master netting arrangements would allow current and non-current positions to be offset in the event of a default. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, trade receivables and trade payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting tables presented below. The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of March 31, 2020 and December 31, 2019 . These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets. As of March 31, 2020: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheets Current assets $ 2,778 $ (1,482 ) $ 1,296 $ 812 $ 2,108 Investments and other assets 50 (50 ) — — — Total assets 2,828 (1,532 ) 1,296 812 2,108 Current liabilities (55,081 ) 1,482 (53,599 ) (1,185 ) (54,784 ) Deferred credits and other (32,627 ) 50 (32,577 ) — (32,577 ) Total liabilities (87,708 ) 1,532 (86,176 ) (1,185 ) (87,361 ) Total $ (84,880 ) $ — $ (84,880 ) $ (373 ) $ (85,253 ) (a) All of our gross recognized derivative instruments were subject to master netting arrangements. (b) 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 $1,185 and cash margin provided to counterparties of $812 . As of December 31, 2019: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheets Current assets $ 584 $ (474 ) $ 110 $ 405 $ 515 Total assets 584 (474 ) 110 405 515 Current liabilities (38,235 ) 474 (37,761 ) (1,185 ) (38,946 ) Deferred credits and other (33,186 ) — (33,186 ) — (33,186 ) Total liabilities (71,421 ) 474 (70,947 ) (1,185 ) (72,132 ) Total $ (70,837 ) $ — $ (70,837 ) $ (780 ) $ (71,617 ) (a) All of our gross recognized derivative instruments were subject to master netting arrangements. (b) 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 $1,185 and cash margin provided to counterparties of $405 . Credit Risk and Credit Related Contingent Features We are exposed to losses in the event of nonperformance or nonpayment by counterparties and have risk management contracts with many counterparties. As of March 31, 2020 we have one counterparty for which our exposure represents approximately 22% of Pinnacle West's risk management assets. This exposure relates to a master agreement with a counterparty that has a very high credit rating. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of our trading counterparties' debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these counterparties could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties. Certain of our derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross-default provisions, and adequate assurance provisions. Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions. For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s). The following table provides information about our derivative instruments that have credit-risk-related contingent features at March 31, 2020 (dollars in thousands): March 31, 2020 Aggregate fair value of derivative instruments in a net liability position $ 86,955 Cash collateral posted — Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a) 81,719 (a) This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above. We also have energy-related non-derivative instrument contracts with investment grade credit-related contingent features, which could also require us to post additional collateral of approximately $97 million if our debt credit ratings were to fall below investment grade. |
Commitments and Contingencies
Commitments and Contingencies | 3 Months Ended |
Mar. 31, 2020 | |
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, 2019. The DOE is reviewing a possible 3 year extension of the settlement agreement. APS cannot predict the timing of the DOE's decision on the extension. APS has submitted five claims pursuant to the terms of the August 18, 2014 settlement agreement, for five separate time periods during July 1, 2011 through June 30, 2018. The DOE has approved and paid $84.3 million for these claims (APS’s share is $24.5 million ). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. In accordance with the 2017 Rate Case Decision, this regulatory liability is being refunded to customers (see Note 4). On October 31, 2019, APS filed its next claim pursuant to the terms of the August 18, 2014 settlement agreement in the amount of $16 million (APS’s share is $4.7 million ). On February 11, 2020, the DOE approved a payment of $15.4 million (APS's share is $4.5 million ) and on April 20, 2020, 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 $13.8 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 $13.3 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 $25.5 million for each retrospective premium assessment declared by NEIL’s Board of Directors due to losses. In addition, NEIL policies contain rating triggers that would result in APS providing approximately $73.4 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions, sublimits and exclusions. Contractual Obligations As of March 31, 2020 , there have been no material changes outside the normal course of business in contractual obligations from the information provided in our 2019 Form 10-K. See Note 3 for discussion regarding changes in our short-term and long-term debt obligations. Superfund-Related Matters The Comprehensive Environmental Response Compensation and Liability Act ("Superfund" 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 in the fall of 2020. 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, 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. 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 new 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 . APS believed that EPA’s original 2012 final rule establishing controls constituting BART for Cholla, which would require installation of SCR controls, was unsupported and that EPA had no basis for disapproving Arizona’s State Implementation Plan ("SIP") and promulgating a FIP that was inconsistent with the state’s considered BART determinations under the regional haze program. In September 2014, APS met with EPA to propose a compromise BART strategy, whereby APS would permanently close Cholla Unit 2 and cease burning coal at Units 1 and 3 by the mid-2020s. (See "Cholla" in Note 4 for information regarding future plans for the Cholla plant and details related to the resulting regulatory asset.) APS made the proposal with the understanding that additional emission control equipment is unlikely to be required in the future because retiring and/or converting the units as contemplated in the proposal is more cost effective than, and will result in increased visibility improvement over, the BART requirements for oxides of nitrogen ("NOx") imposed through EPA's BART FIP. In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect for Cholla on April 26, 2017. 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 that is contaminating groundwater above a regulated constituent’s groundwater protection standard to stop receiving CCR and either retrofit or close, and further requires the closure of any CCR landfill or surface impoundment that cannot meet the applicable performance criteria for location restrictions or structural integrity. Such closure requirements are deemed "forced closure" 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 November 4, 2019, EPA proposed that all unlined CCR surface impoundments, regardless of their impact (or lack thereof) upon surrounding groundwater, must cease operation and initiate closure by August 31, 2020 (with an optional three-month extension as needed for the completion of alternative disposal capacity). • 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 proposal regarding alternative closure would require express EPA authorization for such facilities to continue operating their CCR disposal units under alternative closure. We cannot at this time predict the outcome of these regulatory proceedings or when the EPA will take final action. Depending on the eventual outcome, the costs associated with APS’s management of CCR could materially increase, which could affect APS’s financial position, results of operations, or cash flows. APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners. APS estimates that its share of incremental costs to comply with the CCR rule for Four Corners is approximately $22 million and its share of incremental costs to comply with the CCR rule for Cholla is approximately $15 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 cease operating and initiate closure by October 31, 2020. APS initiated an assessment of corrective measures on January 14, 2019 and expects such assessment will continue through mid- to late-2020. 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 those regulations had been stayed pending judicial review. The ACE regulations are based upon measures that can be implemented to improve the heat rate of steam-electric power plants, specifically coal-fired EGUs. In contrast with the CPP, EPA's ACE regulations would not involve utility-level generation dispatch shifting away from coal-fired generation and toward renewable energy resources and natural gas-fired combined cycle power plants. EPA’s ACE regulations provide states and EPA regions such as the Navajo Nation with three years to develop plans establishing source-specific standards of performance based upon application of the ACE rule’s heat-rate improvement emission guidelines. While corresponding New Source Review (“NSR”) reform regulations were proposed as part of EPA’s initial ACE proposal, the finalized ACE regulations did not include such reform measures. EPA announced that it will be taking final action on EPA's NSR reform proposal for EGUs in the near future. We cannot at this time predict the outcome of EPA's regulatory actions repealing and replacing the CPP. Various state governments, industry organizations, and environmental and public-health public interest groups have filed lawsuits in the D.C. Circuit challenging the legality of EPA’s action, both in repealing the CPP and issuing the ACE regulations. In addition, to the extent that the ACE regulations go into effect as finalized, it is not yet clear how the state of Arizona or EPA will implement these regulations as applied to APS’s coal-fired EGUs. In light of these uncertainties, APS is still evaluating the impact of the ACE regulations on its coal-fired generation fleet. Other environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standard and other rules or matters involving the Clean Air Act, Clean Water Act, Endangered Species Act, RCRA, Superfund, the Navajo Nation, and water supplies for our power plants. The financial impact of complying with current and future environmental rules could jeopardize the economic viability of our coal plants or the willingness or ability of power plant participants to fund any required equipment upgrades or continue their participation in these plants. The economics of continuing to own certain resources, particularly our coal plants, may deteriorate, warranting early retirement of those plants, which may result in asset impairments. APS would seek recovery in rates for the book value of any remaining investments in the plants as well as other costs related to early retirement, but cannot predict whether it would obtain such recovery. Federal Agency Environmental Lawsuit Related to Four Corners On April 20, 2016, several environmental groups filed a lawsuit against the Office of Surface Mining Reclamation and Enforcement ("OSM") and other federal agencies in the District of Arizona in connection with their issuance of the approvals that extended the life of Four Corners and the adjacent mine. The lawsuit alleges that these federal agencies violated both the Endangered Species Act ("ESA") and the National Environmental Policy Act ("NEPA") in providing the federal approvals necessary to extend operations at the Four Corners Power Plant and the adjacent Navajo Mine past July 6, 2016. APS filed a motion to intervene in the proceedings, which was granted on August 3, 2016. On September 15, 2016, NTEC, the company that owns the adjacent mine, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC's tribal sovereign immunity. On September 11, 2017, the Arizona District Court issued an order granting NTEC's motion, dismissing the litigation with prejudice, and terminating the proceedings. On November 9, 2017, the environmental group plaintiffs appealed the district court order dismissing their lawsuit. On July 29, 2019, the Ninth Circuit Court of Appeals affirmed the September 2017 dismissal of the lawsuit, after which the environmental group plaintiffs petitioned the Ninth Circuit for rehearing on September 12, 2019. The Ninth Circuit denied this petition for rehearing on December 11, 2019. On March 24 , 2020, the environmental group plaintiffs filed a Petition for a Writ of Certiorari with the U.S. Supreme Court seeking review of the Ninth Circuit decision. We cannot at this time predict the outcome of this request for further review. Four Corners National Pollutant Discharge Elimination System ("NPDES") Permit On July 16, 2018, several environmental groups filed a petition for review before the EPA Environmental Appeals Board ("EAB") concerning the NPDES wastewater discharge permit for Four Corners, which was reissued on June 12, 2018. The environmental groups allege that the permit was reissued in contravention of several requirements under the Clean Water Act and did not contain required provisions concerning EPA’s 2015 revised effluent limitation guidelines for steam-electric EGUs, 2014 existing-source regulations governing cooling-water intake structures, and effluent limits for surface seepage and subsurface discharges from coal-ash disposal facilities. To address certain of these issues through a reconsidered permit, EPA took action on December 19, 2018 to withdraw the NPDES permit reissued in June 2018. Withdrawal of the permit moots the EAB appeal, and EPA filed a motion to dismiss on that basis. The EAB thereafter dismissed the environmental group appeal on February 12, 2019. EPA then issued a revised final NPDES permit for Four Corners on September 30, 2019. This permit is now subject to a petition for review before the EAB, based upon a November 1, 2019 filing by several environmental groups. We cannot predict the outcome of this review and whether the review will have a material impact on our financial position, results of operations or cash flows. Four Corners - 4CA Matter On July 6, 2016, 4CA purchased El Paso’s 7% interest in Four Corners. NTEC had the option to purchase the 7% interest and ultimately purchased the interest on July 3, 2018. NTEC purchased the 7% interest at 4CA’s book value, approximately $70 million , and is paying 4CA the purchase price over a period of four years pursuant to a secured interest-bearing promissory note. The note is secured by a portion of APS’s payments to be owed to NTEC under the 2016 Coal Supply Agreement. As of March 31, 2020, the note has a remaining balance of $40 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. Financial Assurances In the normal course of business, we obtain standby letters of credit and surety bonds from financial institutions and other third parties. These instruments guarantee our own future performance and provide third parties with financial and performance assurance in the event we do not perform. These instruments support commodity contract collateral obligations and other transactions. As of March 31, 2020 , standby letters of credit totaled $1.7 million and will expire in 2020. As of March 31, 2020 , surety bonds expiring through 2020 totaled $14 million . The underlying liabilities insured by these instruments are reflected on our balance sheets, where applicable. Therefore, no additional liability is reflected for the letters of credit and surety bonds themselves. We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements. Most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely. Pinnacle West has issued parental guarantees and has provided indemnification under certain surety bonds for APS which were not material at March 31, 2020 . 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 reduce as payments are made under the respective guaranteed agreements. The Equity Contribution Guarantees are currently anticipated to be terminated upon completion of construction of the respective projects, which is anticipated to occur prior to December 31, 2020, and the PTC Guarantees (approximately $40 million as of March 31, 2020 |
Other Income and Other Expense
Other Income and Other Expense | 3 Months Ended |
Mar. 31, 2020 | |
Other Income and Expenses [Abstract] | |
Other Income and Other Expense | Other Income and Other Expense The following table provides detail of Pinnacle West's Consolidated other income and other expense for the three months ended March 31, 2020 and 2019 (dollars in thousands): Three Months Ended 2020 2019 Other income: Interest income $ 3,277 $ 2,302 Debt return on Four Corners SCR deferrals (Note 4) 3,140 4,844 Debt return on Ocotillo modernization project (Note 4) 6,144 — Miscellaneous 8 23 Total other income $ 12,569 $ 7,169 Other expense: Non-operating costs $ (2,658 ) $ (2,704 ) Investment gains — net 60 (238 ) Miscellaneous (2,186 ) (1,416 ) Total other expense $ (4,784 ) $ (4,358 ) The following table provides detail of APS’s other income and other expense for the three months ended March 31, 2020 and 2019 (dollars in thousands): Three Months Ended 2020 2019 Other income: Interest income $ 2,341 $ 1,550 Debt return on Four Corners SCR deferrals (Note 4) 3,140 4,844 Debt return on Ocotillo modernization project (Note 4) 6,144 — Miscellaneous 8 22 Total other income $ 11,633 $ 6,416 Other expense: Non-operating costs $ (2,482 ) $ (2,467 ) Miscellaneous (2,186 ) (1,411 ) Total other expense $ (4,668 ) $ (3,878 ) |
Earnings Per Share
Earnings Per Share | 3 Months Ended |
Mar. 31, 2020 | |
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 for the three months ended March 31, 2020 and 2019 (in thousands, except per share amounts): Three Months Ended March 31, 2020 2019 Net income attributable to common shareholders $ 29,993 $ 17,918 Weighted average common shares outstanding — basic 112,594 112,337 Net effect of dilutive securities: Contingently issuable performance shares and restricted stock units 268 398 Weighted average common shares outstanding — diluted 112,862 112,735 Earnings per weighted-average common share outstanding Net income attributable to common shareholders — basic $ 0.27 $ 0.16 Net income attributable to common shareholders — diluted $ 0.27 $ 0.16 |
Fair Value Measurements
Fair Value Measurements | 3 Months Ended |
Mar. 31, 2020 | |
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 — 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 trust 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 2019 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 Trust and Other Special Use Funds The nuclear decommissioning trust 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 trust'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 trust 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 March 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 Cash equivalents $ 26,130 $ — $ — $ — $ 26,130 Risk management activities — derivative instruments: Commodity contracts — 2,325 502 (719 ) (a) 2,108 Nuclear decommissioning trust: Equity securities 11,452 — — 2,090 (b) 13,542 U.S. commingled equity funds — — — 416,463 (c) 416,463 U.S. Treasury debt 152,951 — — — 152,951 Corporate debt — 112,667 — — 112,667 Mortgage-backed securities — 115,790 — — 115,790 Municipal bonds — 98,605 — — 98,605 Other fixed income — 10,408 — — 10,408 Subtotal nuclear decommissioning trust 164,403 337,470 — 418,553 920,426 Other special use funds: Equity securities 6,752 — — 1,331 (b) 8,083 U.S. Treasury debt 238,637 — — — 238,637 Municipal bonds — 6,003 — — 6,003 Subtotal other special use funds 245,389 6,003 — 1,331 252,723 Total assets $ 435,922 $ 345,798 $ 502 $ 419,165 $ 1,201,387 Liabilities Risk management activities — derivative instruments: Commodity contracts $ — $ (79,583 ) $ (8,124 ) $ 346 (a) $ (87,361 ) (a) Represents counterparty netting, margin, and collateral. See Note 7. (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, 2019 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 $ — $ 551 $ 33 $ (69 ) (a) $ 515 Nuclear decommissioning trust: Equity securities 10,872 — — 2,401 (b) 13,273 U.S. commingled equity funds — — — 518,844 (c) 518,844 U.S. Treasury debt 160,607 — — — 160,607 Corporate debt — 115,869 — — 115,869 Mortgage-backed securities — 118,795 — — 118,795 Municipal bonds — 73,040 — — 73,040 Other fixed income — 10,347 — — 10,347 Subtotal nuclear decommissioning trust 171,479 318,051 — 521,245 1,010,775 Other special use funds: Equity securities 7,142 — — 474 (b) 7,616 U.S. Treasury debt 232,848 — — — 232,848 Municipal bonds — 4,631 — — 4,631 Subtotal other special use funds 239,990 4,631 — 474 245,095 Total assets $ 411,469 $ 323,233 $ 33 $ 521,650 $ 1,256,385 Liabilities Risk management activities — derivative instruments: Commodity contracts $ — $ (67,992 ) $ (3,429 ) $ (711 ) (a) $ (72,132 ) (a) Represents counterparty netting, margin, and collateral. See Note 7. (b) Represents net pending securities sales and purchases. (c) Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy. Fair Value Measurements Classified as Level 3 The significant unobservable inputs used in the fair value measurement of our energy derivative contracts include broker quotes that cannot be validated as an observable input primarily due to the long-term nature of the quote or other characteristics of the product. Significant changes in these inputs in isolation would result in significantly higher or lower fair value measurements. Changes in our derivative contract fair values, including changes relating to unobservable inputs, typically will not impact net income due to regulatory accounting treatment (see Note 4). Because our forward commodity contracts classified as Level 3 are currently in a net purchase position, we would expect price increases of the underlying commodity to result in increases in the net fair value of the 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 $40 million as of March 31, 2020 and $44 million as of December 31, 2019, 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 | 3 Months Ended |
Mar. 31, 2020 | |
Investments, Debt and Equity Securities [Abstract] | |
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds | Investments in Nuclear Decommissioning Trust and Other Special Use Funds We have investments in debt and equity securities held in Nuclear Decommissioning Trusts, Coal Mine Reclamation Escrow Account, and an Active Union Employee Medical Account. Investments in debt securities are classified as available-for-sale securities. We record both debt and equity security investments at their fair value on our Condensed Consolidated Balance Sheets. See Note 11 for a discussion of how fair value is determined and the classification of the investments within the fair value hierarchy. The investments in each trust or account are restricted for use and are intended to fund specified costs and activities as further described for each fund below. Nuclear Decommissioning Trusts - To fund the future costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations. Third-party investment managers are authorized to buy and sell securities per stated investment guidelines. The trust funds are invested in fixed income securities and equity securities. Earnings and proceeds from sales and maturities of securities are reinvested in the trusts. Because of the ability of APS to recover decommissioning costs in rates, and in accordance with the regulatory treatment, APS has deferred realized and unrealized gains and losses (including credit losses) in other regulatory liabilities. Coal Mine Reclamation Escrow Account - APS has investments restricted for the future coal mine reclamation funding related to Four Corners. This escrow account is primarily invested in fixed income securities. Earnings and proceeds from sales of securities are reinvested in the escrow account. Because of the ability of APS to recover coal mine reclamation costs in rates, and in accordance with the regulatory treatment, APS has deferred realized and unrealized gains and losses (including credit losses) in other regulatory liabilities. Activities relating to APS coal mine reclamation escrow account investments are included within the other special use funds in the table below. Active Union Employee Medical Account - APS has investments restricted for paying active union employee medical costs. These investments may be used to pay active union employee medical costs incurred in the current and future periods. The account is invested primarily in fixed income securities. In accordance with the ratemaking treatment, APS has deferred the unrealized gains and losses (including credit losses) in other regulatory liabilities . Activities relating to active union employee medical account investments are included within the other special use funds in the table below. APS The following tables present the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS's Nuclear Decommissioning Trusts and other special use fund assets at March 31, 2020 and December 31, 2019 (dollars in thousands): March 31, 2020 Fair Value Total Unrealized Gains Total Unrealized Losses Investment Type: Nuclear Decommissioning Trusts Other Special Use Funds Total Equity securities $ 427,915 $ 6,752 $ 434,667 $ 234,695 $ (1,201 ) Available for sale-fixed income securities 490,421 244,640 735,061 (a) 41,455 (3,527 ) Other 2,090 1,331 3,421 (b) — — Total $ 920,426 $ 252,723 $ 1,173,149 $ 276,150 $ (4,728 ) (a) As of March 31, 2020 , the amortized cost basis of these available-for-sale investments is $697 million . (b) Represents net pending securities sales and purchases. December 31, 2019 Fair Value Total Unrealized Gains Total Unrealized Losses Investment Type: Nuclear Decommissioning Trusts Other Special Use Funds Total Equity securities $ 529,716 $ 7,142 $ 536,858 $ 337,681 $ — Available for sale-fixed income securities 478,658 237,479 716,137 (a) 25,795 (669 ) Other 2,401 474 2,875 (b) — — Total $ 1,010,775 $ 245,095 $ 1,255,870 $ 363,476 $ (669 ) (a) As of December 31, 2019 , the amortized cost basis of these available-for-sale investments is $691 million . (b) Represents net pending securities sales and purchases. 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 for the three months ended March 31, 2020 and 2019 (dollars in thousands): Three Months Ended March 31, Nuclear Decommissioning Trusts Other Special Use Funds Total 2020 Realized gains $ 3,313 $ — $ 3,313 Realized losses (2,227 ) — (2,227 ) Proceeds from the sale of securities (a) 178,196 16,891 195,087 2019 Realized gains $ 1,103 $ — $ 1,103 Realized losses (1,405 ) — (1,405 ) Proceeds from the sale of securities (a) 122,593 56,455 179,048 (a) Proceeds are reinvested in the Nuclear Decommissioning Trusts and other special use funds, excluding amounts reimbursed to the Company for active union employee medical claims from the active union employee medical account. The fair value of APS's fixed income securities, summarized by contractual maturities, at March 31, 2020 , is as follows (dollars in thousands): Nuclear Decommissioning Trust Coal Mine Reclamation Escrow Account Active Union Employee Medical Account Total Less than one year $ 11,911 $ 37,498 $ 40,872 $ 90,281 1 year – 5 years 137,509 18,487 143,565 299,561 5 years – 10 years 112,834 — — 112,834 Greater than 10 years 228,167 4,218 — 232,385 Total $ 490,421 $ 60,203 $ 184,437 $ 735,061 |
New Accounting Standards
New Accounting Standards | 3 Months Ended |
Mar. 31, 2020 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
New Accounting Standards | New Accounting Standards ASU 2016-13, Financial Instruments: Measurement of Credit Losses In June 2016, a new accounting standard was issued that amends the measurement of credit losses on certain financial instruments. The new standard requires entities to use a current expected credit loss model to measure impairment of certain investments in debt securities, trade accounts receivables, and other financial instruments. Since the issuance of the new standard, various guidance has been issued that amends the new standard, including clarifications of certain aspects of the standard and targeted transition relief, among other changes. The new standard and related amendments were effective for us on January 1, 2020, and must be adopted using a modified retrospective approach for certain aspects of the standard, and a prospective approach for other aspects of the standard. We adopted the standard on January 1, 2020 using primarily the modified retrospective approach. While the adoption of this guidance changed our process and methodology for determining credit losses and resulted in additional disclosures, these changes did not have a material impact on our financial statements. See Note 2 for related disclosures. |
Changes in Accumulated Other Co
Changes in Accumulated Other Comprehensive Loss | 3 Months Ended |
Mar. 31, 2020 | |
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 for the three months ended March 31, 2020 and 2019 (dollars in thousands): Pension and Other Postretirement Benefits Derivative Instruments Total Balance December 31, 2019 $ (56,522 ) $ (574 ) $ (57,096 ) OCI (loss) before reclassifications — 292 292 Amounts reclassified from accumulated other comprehensive loss 1,205 (a) 20 (b) 1,225 Balance March 31, 2020 $ (55,317 ) $ (262 ) $ (55,579 ) Balance December 31, 2018 $ (45,997 ) $ (1,711 ) $ (47,708 ) Amounts reclassified from accumulated other comprehensive loss 879 (a) 328 (b) 1,207 Balance March 31, 2019 $ (45,118 ) $ (1,383 ) $ (46,501 ) (a) These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 5. (b) These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA. See Note 7. The following table shows the changes in APS's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three months ended March 31, 2020 and 2019 (dollars in thousands): Pension and Other Postretirement Benefits Derivative Instruments Total Balance December 31, 2019 $ (34,948 ) $ (574 ) $ (35,522 ) OCI (loss) before reclassifications — 292 292 Amounts reclassified from accumulated other comprehensive loss 1,013 (a) 20 (b) 1,033 Balance March 31, 2020 $ (33,935 ) $ (262 ) $ (34,197 ) Balance December 31, 2018 $ (25,396 ) $ (1,711 ) $ (27,107 ) Amounts reclassified from accumulated other comprehensive loss 752 (a) 328 (b) 1,080 Balance March 31, 2019 $ (24,644 ) $ (1,383 ) $ (26,027 ) (a) These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 5. (b) These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA. See Note 7. |
Income Taxes
Income Taxes | 3 Months Ended |
Mar. 31, 2020 | |
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. For the quarter ended March 31, 2020 , the Company recorded $14 million of income tax benefit related to the amortization of these non-depreciation related net excess deferred tax liabilities. On October 29, 2019, the ACC approved the Company’s proposal to amortize depreciation related net excess deferred tax liabilities subject to its jurisdiction over a 28.5 -year period with amortization to retroactively begin as of January 1, 2018. For the quarter ended March 31, 2020 , the Company recorded $6 million of income tax benefit related to amortization of these depreciation related liabilities. See Note 4 for more details. In August 2018, U.S. Treasury proposed regulations that clarified bonus depreciation transition rules under the Tax Act for regulated public utility property placed in service after September 27, 2017 and before January 1, 2018. However, these proposed regulations were ambiguous with respect to regulated public utility property placed in service on or after January 1, 2018. In September 2019, U.S. Treasury issued final regulations, which replaced the August 2018 proposed regulations. These final regulations did not materially impact any tax position taken by the Company for property placed in service after September 27, 2017 and before January 1, 2018. Along with the September 2019 final regulations, U.S. Treasury also issued new proposed regulations which clarify bonus depreciation transition rules under the Tax Act for property placed in service by regulated public utilities after December 31, 2017. The proposed regulations provide that certain regulated public utility property which was under construction prior to September 28, 2017 and placed in service between January 1, 2018 and December 31, 2020 would continue to be eligible for bonus depreciation under the rules and bonus depreciation phase-downs in effect prior to enactment of the Tax Act. Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax. As a result, there is 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, 2016 and all subsequent tax years remain subject to examination by the IRS. With a few exceptions, the Company is no longer subject to state income tax examinations by tax authorities for years before 2015. |
Asset Retirement Obligations
Asset Retirement Obligations | 3 Months Ended |
Mar. 31, 2020 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | Asset Retirement Obligations In the first quarter of 2020, APS recognized an asset retirement obligation ("ARO") for its share of corrective action and water monitoring costs at Four Corners and the Navajo Plant (see additional details in Notes 4 and 8), which resulted in a decrease to the ARO of $11 million for Four Corners and an increase to the ARO of $5 million for the Navajo Plant. The following schedule shows the change in our asset retirement obligations for the three months ended March 31, 2020 (dollars in thousands): 2020 Asset retirement obligations at January 1, 2020 $ 657,218 Changes attributable to: Accretion expense 10,219 Settlements (2,295 ) Estimated cash flow revisions (5,821 ) Asset retirement obligations at March 31, 2020 $ 659,321 In accordance with regulatory accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal. See detail of regulatory liabilities in Note 4. |
New Accounting Standards (Polic
New Accounting Standards (Policies) | 3 Months Ended |
Mar. 31, 2020 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
New Accounting Standards | ASU 2016-13, Financial Instruments: Measurement of Credit Losses In June 2016, a new accounting standard was issued that amends the measurement of credit losses on certain financial instruments. The new standard requires entities to use a current expected credit loss model to measure impairment of certain investments in debt securities, trade accounts receivables, and other financial instruments. Since the issuance of the new standard, various guidance has been issued that amends the new standard, including clarifications of certain aspects of the standard and targeted transition relief, among other changes. The new standard and related amendments were effective for us on January 1, 2020, and must be adopted using a modified retrospective approach for certain aspects of the standard, and a prospective approach for other aspects of the standard. We adopted the standard on January 1, 2020 using primarily the modified retrospective approach. While the adoption of this guidance changed our process and methodology for determining credit losses and resulted in additional disclosures, these changes did not have a material impact on our financial statements. See Note 2 for related disclosures. |
Consolidation and Nature of O_2
Consolidation and Nature of Operations (Tables) | 3 Months Ended |
Mar. 31, 2020 | |
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): Three Months Ended 2020 2019 Cash paid during the period for: Income taxes, net of refunds $ (3,002 ) $ 1 Interest, net of amounts capitalized 53,723 63,764 Significant non-cash investing and financing activities: Accrued capital expenditures $ 100,868 $ 95,879 Right-of-use operating lease assets obtained in exchange for operating lease liabilities 2,311 2,293 The following table summarizes supplemental APS cash flow information (dollars in thousands): Three Months Ended 2020 2019 Cash paid during the period for: Income taxes, net of refunds $ — $ — Interest, net of amounts capitalized 52,034 61,387 Significant non-cash investing and financing activities: Accrued capital expenditures $ 100,868 $ 95,879 Right-of-use operating lease assets obtained in exchange for operating lease liabilities 2,311 2,293 |
Revenue (Tables)
Revenue (Tables) | 3 Months Ended |
Mar. 31, 2020 | |
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 March 31, 2020 2019 Retail Electric Revenue Residential $ 325,073 $ 351,566 Non-Residential 303,351 332,668 Wholesale energy sales 14,668 36,452 Transmission services for others 15,927 15,249 Other sources 2,911 4,595 Total operating revenues $ 661,930 $ 740,530 |
Schedule of Accounts Receivable | The following table provides a rollforward of Pinnacle West’s allowance for doubtful accounts (dollars in thousands): March 31, 2020 December 31, 2019 Allowance for doubtful accounts, balance at beginning of period $ 8,171 $ 4,069 Bad debt expense 3,122 11,819 Actual write-offs (2,927 ) (7,717 ) Allowance for doubtful accounts, balance at end of period $ 8,366 $ 8,171 |
Long-Term Debt and Liquidity _2
Long-Term Debt and Liquidity Matters (Tables) | 3 Months Ended |
Mar. 31, 2020 | |
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 March 31, 2020 As of December 31, 2019 Carrying Amount Fair Value Carrying Amount Fair Value Pinnacle West $ 449,581 $ 448,449 $ 449,425 $ 450,822 APS 5,033,743 5,634,265 5,183,133 5,743,570 Total $ 5,483,324 $ 6,082,714 $ 5,632,558 $ 6,194,392 |
Regulatory Matters (Tables)
Regulatory Matters (Tables) | 3 Months Ended |
Mar. 31, 2020 | |
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 2020 and 2019 (dollars in thousands): Three Months Ended 2020 2019 Beginning balance $ 70,137 $ 37,164 Deferred fuel and purchased power costs — current period 5,785 (16,709 ) Amounts charged to customers 1,808 (12,872 ) Ending balance $ 77,730 $ 7,583 |
Schedule of regulatory assets | The detail of regulatory assets is as follows (dollars in thousands): Amortization Through March 31, 2020 December 31, 2019 Current Non-Current Current Non-Current Pension (a) $ — $ 652,691 $ — $ 660,223 Retired power plant costs 2033 28,182 135,349 28,182 142,503 Income taxes — allowance for funds used during construction ("AFUDC") equity 2050 6,815 155,369 6,800 154,974 Deferred fuel and purchased power — mark-to-market (Note 7) 2024 51,954 32,576 36,887 33,185 Deferred fuel and purchased power (b) (c) 2021 77,730 — 70,137 — Deferred property taxes 2027 8,569 56,053 8,569 58,196 SCR deferral N/A — 58,258 — 52,644 Ocotillo deferral N/A — 51,767 — 38,144 Four Corners cost deferral 2024 8,077 30,133 8,077 32,152 Deferred compensation 2036 — 37,550 — 36,464 Lost fixed cost recovery (b) 2021 28,885 — 26,067 — Income taxes — investment tax credit basis adjustment 2048 1,098 24,920 1,098 24,981 Palo Verde VIEs (Note 6) 2046 — 20,790 — 20,635 Coal reclamation 2026 1,068 17,800 1,546 17,688 Loss on reacquired debt 2038 1,637 11,636 1,637 12,031 Mead-Phoenix transmission line contributions in aid of construction ("CIAC") 2050 332 9,629 332 9,712 TCA balancing account (b) 2021 6,048 1,027 6,324 2,885 Tax expense of Medicare subsidy 2024 1,238 4,881 1,235 4,940 AG-1 deferral 2022 2,787 2,019 2,787 2,716 Tax expense adjuster mechanism (b) 2020 942 — 1,612 — Other Various 109 — 1,917 — Total regulatory assets (d) $ 225,471 $ 1,302,448 $ 203,207 $ 1,304,073 (a) This asset represents the future recovery of pension benefit obligations through retail rates. If these costs are disallowed by the ACC, this regulatory asset would be charged to other comprehensive income ("OCI") and result in lower future revenues. (b) See "Cost Recovery Mechanisms" discussion above. (c) Subject to a carrying charge. (d) There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base. FERC rates are set using a formula rate as described in "Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters." |
Schedule of regulatory liabilities | The detail of regulatory liabilities is as follows (dollars in thousands): Amortization Through March 31, 2020 December 31, 2019 Current Non-Current Current Non-Current Excess deferred income taxes - ACC - Tax Cuts and Jobs Act (a) 2046 $ 113,142 $ 976,018 $ 59,918 $ 1,054,053 Excess deferred income taxes - FERC - Tax Cuts and Jobs Act (a) 2058 6,315 237,508 6,302 237,357 Asset retirement obligations 2057 — 311,517 — 418,423 Removal costs (c) 44,586 135,450 47,356 136,072 Other postretirement benefits (d) 37,575 130,270 37,575 139,634 Spent nuclear fuel 2027 6,638 49,234 6,676 51,019 Income taxes — change in rates 2050 2,802 51,152 2,797 68,265 Four Corners coal reclamation 2038 5,461 48,405 1,059 51,704 Income taxes — deferred investment tax credit 2048 2,202 49,910 2,202 50,034 Renewable energy standard (b) 2021 45,872 115 39,287 10,300 Demand side management (b) 2021 1,702 43,423 15,024 24,146 Sundance maintenance 2031 184 13,515 5,698 11,319 Active union medical trust N/A — 7,986 — 2,041 Property tax deferral N/A — 7,968 — 7,046 Tax expense adjustor mechanism (b) 2020 6,615 — 7,018 — Deferred gains on utility property 2022 2,423 3,577 2,423 4,163 FERC transmission true up 2022 3,304 1,621 1,045 2,004 Other Various 284 132 532 255 Total regulatory liabilities $ 279,105 $ 2,067,801 $ 234,912 $ 2,267,835 (a) For purposes of presentation on the Statement of Cash Flows, amortization of the regulatory liabilities for excess deferred income taxes are reflected as "Deferred income taxes" under Cash Flows From Operating Activities. (b) See “Cost Recovery Mechanisms” discussion above. (c) In accordance with regulatory accounting guidance, APS accrues removal costs for its regulated assets, even if there is no legal obligation for removal. (d) See Note 5. |
Retirement Plans and Other Po_2
Retirement Plans and Other Postretirement Benefits (Tables) | 3 Months Ended |
Mar. 31, 2020 | |
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 Three Months Ended 2020 2019 2020 2019 Service cost — benefits earned during the period $ 14,257 $ 12,543 $ 5,717 $ 4,714 Non-service costs (credits): Interest cost on benefit obligation 29,761 34,352 6,512 7,526 Expected return on plan assets (46,806 ) (42,893 ) (10,019 ) (9,603 ) Amortization of: Prior service credit — — (9,394 ) (9,455 ) Net actuarial loss 9,011 11,239 — — Net periodic benefit cost (credit) $ 6,223 $ 15,241 $ (7,184 ) $ (6,818 ) Portion of cost (credit) charged to expense $ 1,342 $ 8,244 $ (5,456 ) $ (4,817 ) |
Palo Verde Sale Leaseback Var_2
Palo Verde Sale Leaseback Variable Interest Entities (Tables) | 3 Months Ended |
Mar. 31, 2020 | |
Variable Interest Entities [Abstract] | |
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets | Our Condensed Consolidated Balance Sheets at March 31, 2020 and December 31, 2019 include the following amounts relating to the VIEs (dollars in thousands): March 31, 2020 December 31, 2019 Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation $ 100,938 $ 101,906 Equity — Noncontrolling interests 127,414 122,540 |
Derivative Accounting (Tables)
Derivative Accounting (Tables) | 3 Months Ended |
Mar. 31, 2020 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Outstanding gross notional amount of derivatives, which represents both purchases and sales (does not reflect net position) | As of March 31, 2020 and December 31, 2019 , we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): Quantity Commodity Unit of Measure March 31, 2020 December 31, 2019 Power GWh 477 193 Gas Billion cubic feet 263 257 |
Gains and losses from derivative instruments in designated cash flow accounting hedges relationships | The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the three months ended March 31, 2020 and 2019 (dollars in thousands): Financial Statement Location Three Months Ended Commodity Contracts 2020 2019 Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a) Fuel and purchased power (b) $ (414 ) $ (436 ) (a) During the three months ended March 31, 2020 and 2019 , we had no gains or losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges . (b) Amounts are before the effect of PSA deferrals. |
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 during the three months ended March 31, 2020 and 2019 (dollars in thousands): Financial Statement Location Three Months Ended Commodity Contracts 2020 2019 Net Gain (Loss) Recognized in Income Fuel and purchased power (a) $ (30,078 ) $ 8,170 (a) Amounts are before the effect of PSA deferrals. |
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 as of March 31, 2020 and December 31, 2019 . These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets. As of March 31, 2020: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheets Current assets $ 2,778 $ (1,482 ) $ 1,296 $ 812 $ 2,108 Investments and other assets 50 (50 ) — — — Total assets 2,828 (1,532 ) 1,296 812 2,108 Current liabilities (55,081 ) 1,482 (53,599 ) (1,185 ) (54,784 ) Deferred credits and other (32,627 ) 50 (32,577 ) — (32,577 ) Total liabilities (87,708 ) 1,532 (86,176 ) (1,185 ) (87,361 ) Total $ (84,880 ) $ — $ (84,880 ) $ (373 ) $ (85,253 ) (a) All of our gross recognized derivative instruments were subject to master netting arrangements. (b) 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 $1,185 and cash margin provided to counterparties of $812 . As of December 31, 2019: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheets Current assets $ 584 $ (474 ) $ 110 $ 405 $ 515 Total assets 584 (474 ) 110 405 515 Current liabilities (38,235 ) 474 (37,761 ) (1,185 ) (38,946 ) Deferred credits and other (33,186 ) — (33,186 ) — (33,186 ) Total liabilities (71,421 ) 474 (70,947 ) (1,185 ) (72,132 ) Total $ (70,837 ) $ — $ (70,837 ) $ (780 ) $ (71,617 ) (a) All of our gross recognized derivative instruments were subject to master netting arrangements. (b) 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 $1,185 and cash margin provided to counterparties of $405 . |
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 as of March 31, 2020 and December 31, 2019 . These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets. As of March 31, 2020: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheets Current assets $ 2,778 $ (1,482 ) $ 1,296 $ 812 $ 2,108 Investments and other assets 50 (50 ) — — — Total assets 2,828 (1,532 ) 1,296 812 2,108 Current liabilities (55,081 ) 1,482 (53,599 ) (1,185 ) (54,784 ) Deferred credits and other (32,627 ) 50 (32,577 ) — (32,577 ) Total liabilities (87,708 ) 1,532 (86,176 ) (1,185 ) (87,361 ) Total $ (84,880 ) $ — $ (84,880 ) $ (373 ) $ (85,253 ) (a) All of our gross recognized derivative instruments were subject to master netting arrangements. (b) 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 $1,185 and cash margin provided to counterparties of $812 . As of December 31, 2019: Gross Recognized Derivatives (a) Amounts Offset (b) Net Recognized Derivatives Other (c) Amount Reported on Balance Sheets Current assets $ 584 $ (474 ) $ 110 $ 405 $ 515 Total assets 584 (474 ) 110 405 515 Current liabilities (38,235 ) 474 (37,761 ) (1,185 ) (38,946 ) Deferred credits and other (33,186 ) — (33,186 ) — (33,186 ) Total liabilities (71,421 ) 474 (70,947 ) (1,185 ) (72,132 ) Total $ (70,837 ) $ — $ (70,837 ) $ (780 ) $ (71,617 ) (a) All of our gross recognized derivative instruments were subject to master netting arrangements. (b) 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 $1,185 and cash margin provided to counterparties of $405 . |
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 at March 31, 2020 (dollars in thousands): March 31, 2020 Aggregate fair value of derivative instruments in a net liability position $ 86,955 Cash collateral posted — Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a) 81,719 (a) This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above. |
Other Income and Other Expense
Other Income and Other Expense (Tables) | 3 Months Ended |
Mar. 31, 2020 | |
Other Income and Expenses [Abstract] | |
Detail of other income and other expense | The following table provides detail of Pinnacle West's Consolidated other income and other expense for the three months ended March 31, 2020 and 2019 (dollars in thousands): Three Months Ended 2020 2019 Other income: Interest income $ 3,277 $ 2,302 Debt return on Four Corners SCR deferrals (Note 4) 3,140 4,844 Debt return on Ocotillo modernization project (Note 4) 6,144 — Miscellaneous 8 23 Total other income $ 12,569 $ 7,169 Other expense: Non-operating costs $ (2,658 ) $ (2,704 ) Investment gains — net 60 (238 ) Miscellaneous (2,186 ) (1,416 ) Total other expense $ (4,784 ) $ (4,358 ) The following table provides detail of APS’s other income and other expense for the three months ended March 31, 2020 and 2019 (dollars in thousands): Three Months Ended 2020 2019 Other income: Interest income $ 2,341 $ 1,550 Debt return on Four Corners SCR deferrals (Note 4) 3,140 4,844 Debt return on Ocotillo modernization project (Note 4) 6,144 — Miscellaneous 8 22 Total other income $ 11,633 $ 6,416 Other expense: Non-operating costs $ (2,482 ) $ (2,467 ) Miscellaneous (2,186 ) (1,411 ) Total other expense $ (4,668 ) $ (3,878 ) |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 3 Months Ended |
Mar. 31, 2020 | |
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 for the three months ended March 31, 2020 and 2019 (in thousands, except per share amounts): Three Months Ended March 31, 2020 2019 Net income attributable to common shareholders $ 29,993 $ 17,918 Weighted average common shares outstanding — basic 112,594 112,337 Net effect of dilutive securities: Contingently issuable performance shares and restricted stock units 268 398 Weighted average common shares outstanding — diluted 112,862 112,735 Earnings per weighted-average common share outstanding Net income attributable to common shareholders — basic $ 0.27 $ 0.16 Net income attributable to common shareholders — diluted $ 0.27 $ 0.16 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 3 Months Ended |
Mar. 31, 2020 | |
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 March 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 Cash equivalents $ 26,130 $ — $ — $ — $ 26,130 Risk management activities — derivative instruments: Commodity contracts — 2,325 502 (719 ) (a) 2,108 Nuclear decommissioning trust: Equity securities 11,452 — — 2,090 (b) 13,542 U.S. commingled equity funds — — — 416,463 (c) 416,463 U.S. Treasury debt 152,951 — — — 152,951 Corporate debt — 112,667 — — 112,667 Mortgage-backed securities — 115,790 — — 115,790 Municipal bonds — 98,605 — — 98,605 Other fixed income — 10,408 — — 10,408 Subtotal nuclear decommissioning trust 164,403 337,470 — 418,553 920,426 Other special use funds: Equity securities 6,752 — — 1,331 (b) 8,083 U.S. Treasury debt 238,637 — — — 238,637 Municipal bonds — 6,003 — — 6,003 Subtotal other special use funds 245,389 6,003 — 1,331 252,723 Total assets $ 435,922 $ 345,798 $ 502 $ 419,165 $ 1,201,387 Liabilities Risk management activities — derivative instruments: Commodity contracts $ — $ (79,583 ) $ (8,124 ) $ 346 (a) $ (87,361 ) (a) Represents counterparty netting, margin, and collateral. See Note 7. (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, 2019 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 $ — $ 551 $ 33 $ (69 ) (a) $ 515 Nuclear decommissioning trust: Equity securities 10,872 — — 2,401 (b) 13,273 U.S. commingled equity funds — — — 518,844 (c) 518,844 U.S. Treasury debt 160,607 — — — 160,607 Corporate debt — 115,869 — — 115,869 Mortgage-backed securities — 118,795 — — 118,795 Municipal bonds — 73,040 — — 73,040 Other fixed income — 10,347 — — 10,347 Subtotal nuclear decommissioning trust 171,479 318,051 — 521,245 1,010,775 Other special use funds: Equity securities 7,142 — — 474 (b) 7,616 U.S. Treasury debt 232,848 — — — 232,848 Municipal bonds — 4,631 — — 4,631 Subtotal other special use funds 239,990 4,631 — 474 245,095 Total assets $ 411,469 $ 323,233 $ 33 $ 521,650 $ 1,256,385 Liabilities Risk management activities — derivative instruments: Commodity contracts $ — $ (67,992 ) $ (3,429 ) $ (711 ) (a) $ (72,132 ) (a) Represents counterparty netting, margin, and collateral. See Note 7. (b) Represents net pending securities sales and purchases. (c) Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy. |
Investments in Nuclear Decomm_2
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Tables) | 3 Months Ended |
Mar. 31, 2020 | |
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 at March 31, 2020 and December 31, 2019 (dollars in thousands): March 31, 2020 Fair Value Total Unrealized Gains Total Unrealized Losses Investment Type: Nuclear Decommissioning Trusts Other Special Use Funds Total Equity securities $ 427,915 $ 6,752 $ 434,667 $ 234,695 $ (1,201 ) Available for sale-fixed income securities 490,421 244,640 735,061 (a) 41,455 (3,527 ) Other 2,090 1,331 3,421 (b) — — Total $ 920,426 $ 252,723 $ 1,173,149 $ 276,150 $ (4,728 ) (a) As of March 31, 2020 , the amortized cost basis of these available-for-sale investments is $697 million . (b) Represents net pending securities sales and purchases. December 31, 2019 Fair Value Total Unrealized Gains Total Unrealized Losses Investment Type: Nuclear Decommissioning Trusts Other Special Use Funds Total Equity securities $ 529,716 $ 7,142 $ 536,858 $ 337,681 $ — Available for sale-fixed income securities 478,658 237,479 716,137 (a) 25,795 (669 ) Other 2,401 474 2,875 (b) — — Total $ 1,010,775 $ 245,095 $ 1,255,870 $ 363,476 $ (669 ) (a) As of December 31, 2019 , the amortized cost basis of these available-for-sale investments is $691 million . (b) Represents net pending securities sales and purchases. |
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 for the three months ended March 31, 2020 and 2019 (dollars in thousands): Three Months Ended March 31, Nuclear Decommissioning Trusts Other Special Use Funds Total 2020 Realized gains $ 3,313 $ — $ 3,313 Realized losses (2,227 ) — (2,227 ) Proceeds from the sale of securities (a) 178,196 16,891 195,087 2019 Realized gains $ 1,103 $ — $ 1,103 Realized losses (1,405 ) — (1,405 ) Proceeds from the sale of securities (a) 122,593 56,455 179,048 (a) Proceeds are reinvested in the Nuclear Decommissioning Trusts and other special use funds, excluding amounts reimbursed to the Company for active union employee medical claims from the active union employee medical account. |
Fair value of fixed income securities, summarized by contractual maturities | The fair value of APS's fixed income securities, summarized by contractual maturities, at March 31, 2020 , is as follows (dollars in thousands): Nuclear Decommissioning Trust Coal Mine Reclamation Escrow Account Active Union Employee Medical Account Total Less than one year $ 11,911 $ 37,498 $ 40,872 $ 90,281 1 year – 5 years 137,509 18,487 143,565 299,561 5 years – 10 years 112,834 — — 112,834 Greater than 10 years 228,167 4,218 — 232,385 Total $ 490,421 $ 60,203 $ 184,437 $ 735,061 |
Changes in Accumulated Other _2
Changes in Accumulated Other Comprehensive Loss (Tables) | 3 Months Ended |
Mar. 31, 2020 | |
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 for the three months ended March 31, 2020 and 2019 (dollars in thousands): Pension and Other Postretirement Benefits Derivative Instruments Total Balance December 31, 2019 $ (56,522 ) $ (574 ) $ (57,096 ) OCI (loss) before reclassifications — 292 292 Amounts reclassified from accumulated other comprehensive loss 1,205 (a) 20 (b) 1,225 Balance March 31, 2020 $ (55,317 ) $ (262 ) $ (55,579 ) Balance December 31, 2018 $ (45,997 ) $ (1,711 ) $ (47,708 ) Amounts reclassified from accumulated other comprehensive loss 879 (a) 328 (b) 1,207 Balance March 31, 2019 $ (45,118 ) $ (1,383 ) $ (46,501 ) (a) These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 5. (b) These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA. See Note 7. The following table shows the changes in APS's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three months ended March 31, 2020 and 2019 (dollars in thousands): Pension and Other Postretirement Benefits Derivative Instruments Total Balance December 31, 2019 $ (34,948 ) $ (574 ) $ (35,522 ) OCI (loss) before reclassifications — 292 292 Amounts reclassified from accumulated other comprehensive loss 1,013 (a) 20 (b) 1,033 Balance March 31, 2020 $ (33,935 ) $ (262 ) $ (34,197 ) Balance December 31, 2018 $ (25,396 ) $ (1,711 ) $ (27,107 ) Amounts reclassified from accumulated other comprehensive loss 752 (a) 328 (b) 1,080 Balance March 31, 2019 $ (24,644 ) $ (1,383 ) $ (26,027 ) (a) These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 5. (b) These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA. See Note 7. |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 3 Months Ended |
Mar. 31, 2020 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Change in asset retirement obligations | The following schedule shows the change in our asset retirement obligations for the three months ended March 31, 2020 (dollars in thousands): 2020 Asset retirement obligations at January 1, 2020 $ 657,218 Changes attributable to: Accretion expense 10,219 Settlements (2,295 ) Estimated cash flow revisions (5,821 ) Asset retirement obligations at March 31, 2020 $ 659,321 |
Consolidation and Nature of O_3
Consolidation and Nature of Operations (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2020 | Mar. 31, 2019 | |
Cash paid during the period for: | ||
Income taxes, net of refunds | $ (3,002) | $ 1 |
Interest, net of amounts capitalized | 53,723 | 63,764 |
Significant non-cash investing and financing activities: | ||
Accrued capital expenditures | 100,868 | 95,879 |
Right-of-use operating lease assets obtained in exchange for operating lease liabilities | 2,311 | 2,293 |
APS | ||
Cash paid during the period for: | ||
Income taxes, net of refunds | 0 | 0 |
Interest, net of amounts capitalized | 52,034 | 61,387 |
Significant non-cash investing and financing activities: | ||
Accrued capital expenditures | 100,868 | 95,879 |
Right-of-use operating lease assets obtained in exchange for operating lease liabilities | $ 2,311 | $ 2,293 |
Revenue (Details)
Revenue (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2020 | Mar. 31, 2019 | |
Disaggregation of Revenue [Line Items] | ||
Operating revenues | $ 661,930 | $ 740,530 |
Regulatory cost recovery revenue | 14,000 | 20,000 |
Electric Service | Residential | ||
Disaggregation of Revenue [Line Items] | ||
Operating revenues | 325,073 | 351,566 |
Electric Service | Non-Residential | ||
Disaggregation of Revenue [Line Items] | ||
Operating revenues | 303,351 | 332,668 |
Electric Service | Wholesale energy sales | ||
Disaggregation of Revenue [Line Items] | ||
Operating revenues | 14,668 | 36,452 |
Transmission services for others | ||
Disaggregation of Revenue [Line Items] | ||
Operating revenues | 15,927 | 15,249 |
Other sources | ||
Disaggregation of Revenue [Line Items] | ||
Operating revenues | 2,911 | 4,595 |
Electric and Transmission Service | ||
Disaggregation of Revenue [Line Items] | ||
Operating revenues | $ 648,000 | $ 721,000 |
Revenue Allowance for Doubtful
Revenue Allowance for Doubtful Accounts (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2020 | Dec. 31, 2019 | Mar. 31, 2020 | |
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | |||
Allowance for doubtful accounts, balance at beginning of period | $ 8,171 | $ 4,069 | |
Bad debt expense | 3,122 | 11,819 | |
Actual write-offs | (2,927) | (7,717) | |
Allowance for doubtful accounts, balance at end of period | $ 8,171 | $ 4,069 | $ 8,366 |
Long-Term Debt and Liquidity _3
Long-Term Debt and Liquidity Matters - Narrative (Details) | Jan. 15, 2020USD ($) | Mar. 31, 2020USD ($)Facility | May 05, 2020USD ($) | May 04, 2020USD ($) | Mar. 26, 2020USD ($) | Nov. 27, 2018USD ($) |
Long-Term Debt and Liquidity Matters | ||||||
Percentage of capitalization | 7.00% | |||||
Capacity available for trade purchases | $ 500,000,000 | |||||
Long-term debt limit | $ 7,500,000,000 | |||||
Pinnacle West | Revolving Credit Facility | Revolving credit Facility maturing July 2023 | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to) | 300,000,000 | |||||
Long-term line of credit | 100,000,000 | |||||
Current borrowing capacity on credit facility | 200,000,000 | |||||
Pinnacle West | Letter of Credit | Revolving credit Facility maturing July 2023 | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Outstanding letters of credit | 0 | |||||
Pinnacle West | Commercial paper | Revolving credit Facility maturing July 2023 | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Commercial paper | 0 | |||||
Pinnacle West | Term Loan [Member] | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Long-term line of credit | $ 33,000,000 | |||||
Variable rate | 1.40% | |||||
APS | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Long-term debt limit | $ 5,900,000,000 | |||||
APS | Senior Unsecured Notes [Member] | Senior notes | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Debt instrument, face amount | $ 250,000,000 | |||||
Extinguishment of debt | $ 150,000,000 | |||||
APS | Revolving Credit Facility | Revolving credit Facility maturing July 2023 | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to) | $ 700,000,000 | |||||
Current borrowing capacity on credit facility | 500,000,000 | |||||
APS | Revolving Credit Facility | Revolving Credit Facility Maturing in 2022 and 2023 | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to) | 1,400,000,000 | |||||
Long-term line of credit | 430,000,000 | |||||
Current borrowing capacity on credit facility | $ 1,000,000,000 | |||||
Number of line of credit facilities | Facility | 2 | |||||
APS | Revolving Credit Facility | Revolving credit facility maturing June 2022 | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders (up to) | $ 700,000,000 | |||||
Current borrowing capacity on credit facility | 500,000,000 | |||||
APS | Commercial paper | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Maximum commercial paper support available under credit facility | 500,000,000 | |||||
APS | Commercial paper | Revolving Credit Facility Maturing in 2022 and 2023 | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Commercial paper | $ 0 | |||||
Minimum | APS | Senior Unsecured Notes [Member] | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Debt instrument, interest rate | 2.20% | |||||
Subsequent Event | Pinnacle West | Term Loan [Member] | ||||||
Long-Term Debt and Liquidity Matters | ||||||
Debt instrument, face amount | $ 31,000,000 | $ 50,000,000 |
Long-Term Debt and Liquidity _4
Long-Term Debt and Liquidity Matters - Estimated Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands | Mar. 31, 2020 | Dec. 31, 2019 |
Estimated fair value of long-term debt, including current maturities | ||
Carrying Amount | $ 5,483,324 | $ 5,632,558 |
Fair Value | 6,082,714 | 6,194,392 |
Pinnacle West | ||
Estimated fair value of long-term debt, including current maturities | ||
Carrying Amount | 449,581 | 449,425 |
Fair Value | 448,449 | 450,822 |
APS | ||
Estimated fair value of long-term debt, including current maturities | ||
Carrying Amount | 5,033,743 | 5,183,133 |
Fair Value | $ 5,634,265 | $ 5,743,570 |
Regulatory Matters Regulatory M
Regulatory Matters Regulatory Matters - COVID-19 (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||
Mar. 31, 2020 | Mar. 31, 2019 | Dec. 31, 2020 | May 05, 2020 | Mar. 13, 2020 | |
Public Utilities, General Disclosures [Line Items] | |||||
Pre-tax income | $ 14,657,000 | $ 25,209,000 | |||
APS | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Pre-tax income | $ 20,770,000 | $ 34,602,000 | |||
Customer support fund | $ 1,500,000 | ||||
Customer support fund, bill credit | $ 100 | ||||
Subsequent Event | APS | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Demand side management funds | $ 36,000,000 | ||||
Voluntary funds | $ 5,300,000 | ||||
Minimum | Damage from Fire, Explosion or Other Hazard | Forecast | APS | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Pre-tax income | $ 20,000,000 | ||||
Maximum | Damage from Fire, Explosion or Other Hazard | Forecast | APS | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Pre-tax income | $ 30,000,000 |
Regulatory Matters - Retail Rat
Regulatory Matters - Retail Rate Case Filing (Details) - ACC - APS | Oct. 31, 2019USD ($)GW | Jun. 30, 2019USD ($) | Mar. 27, 2017USD ($)$ / kWh |
Retail Rate Case Filing with Arizona Corporation Commission | |||
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% | |
Rate matter, cost base rate | $ 8,870,000,000 | ||
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 | ||
Approximate percentage of increase in average residential customer bill | 5.40% | 4.54% | |
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 | ||
Funding limited income crisis bill program | $ 1,250,000 | ||
Commercial customers, market pricing, threshold | GW | 0.2 | ||
AZ Sun Program Phase 2 | Retail Rate Case Filing with Arizona Corporation Commission | |||
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 | ||
Minimum | |||
Public Utilities, General Disclosures [Line Items] | |||
Operating Results | $ 69,000,000 | ||
Minimum | Retail Rate Case Filing with Arizona Corporation Commission | |||
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 | |||
Public Utilities, General Disclosures [Line Items] | |||
Rate matter, environmental surcharge cap rate (in dollars per kWh) | $ / kWh | 0.00050 |
Regulatory Matters Regulatory_2
Regulatory Matters Regulatory Matters - Capital Structure and Costs of Capital (Details) | Oct. 31, 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 | APS | |
Capital Structure | |
Common stock equity | 54.70% |
Retail Rate Case Filing with Arizona Corporation Commission | ACC | APS | |
Capital Structure | |
Long-term debt | 45.30% |
Regulatory Matters - Cost Recov
Regulatory Matters - Cost Recovery Mechanism and Net Metering (Details) Customer in Thousands | Feb. 14, 2020USD ($) | Feb. 01, 2020USD ($)$ / kWh | Nov. 14, 2019USD ($)Customer | Oct. 31, 2019USD ($) | Oct. 29, 2019USD ($) | Jun. 01, 2019USD ($) | Apr. 10, 2019 | Feb. 15, 2019USD ($) | Feb. 01, 2019$ / kWh | Aug. 13, 2018USD ($) | Jun. 01, 2018USD ($) | May 01, 2018$ / kWh | Feb. 15, 2018USD ($) | Feb. 01, 2018$ / kWh | Jan. 08, 2018USD ($) | Nov. 20, 2017USD ($) | Dec. 20, 2016$ / kWh | Aug. 31, 2016 | Mar. 31, 2020USD ($) | Mar. 31, 2019USD ($) | Dec. 31, 2020USD ($) | Dec. 31, 2017$ / kWh | Dec. 31, 2012$ / kWh | May 05, 2020USD ($) | Dec. 31, 2019USD ($) | Jul. 01, 2019USD ($) | Mar. 15, 2019agreement | Dec. 31, 2018USD ($) | Jun. 29, 2018USD ($) | Nov. 14, 2017USD ($) | Sep. 01, 2017USD ($) |
Settlement Agreement | |||||||||||||||||||||||||||||||
Pre-tax income | $ 14,657,000 | $ 25,209,000 | |||||||||||||||||||||||||||||
Change in regulatory asset | |||||||||||||||||||||||||||||||
Deferred fuel and purchased power costs — current period | 5,785,000 | (16,709,000) | |||||||||||||||||||||||||||||
Amounts charged to customers | 1,808,000 | (12,872,000) | |||||||||||||||||||||||||||||
Rate plan comparison tool, number of customers | Customer | 13 | ||||||||||||||||||||||||||||||
Rate plan comparison tool, inconvenience payment | $ 25 | ||||||||||||||||||||||||||||||
APS | |||||||||||||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||||||||||||
Pre-tax income | 20,770,000 | 34,602,000 | |||||||||||||||||||||||||||||
Change in regulatory asset | |||||||||||||||||||||||||||||||
Deferred fuel and purchased power costs — current period | 5,785,000 | (16,709,000) | |||||||||||||||||||||||||||||
Amounts charged to customers | $ 1,808,000 | (12,872,000) | |||||||||||||||||||||||||||||
Lost Fixed Cost Recovery Mechanisms | APS | |||||||||||||||||||||||||||||||
Change in regulatory asset | |||||||||||||||||||||||||||||||
Fixed costs recoverable per residential power lost (in dollars per kWh) | $ / kWh | 0.031 | ||||||||||||||||||||||||||||||
Fixed costs recoverable per non-residential power lost (in dollars per kWh) | $ / kWh | 0.023 | ||||||||||||||||||||||||||||||
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 | $ 26,600,000 | $ 36,200,000 | $ 60,700,000 | ||||||||||||||||||||||||||||
Increase (decrease) in amount of adjustment representing prorated sales losses | $ (9,600,000) | $ (24,500,000) | |||||||||||||||||||||||||||||
ACC | APS | |||||||||||||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||||||||||||
Program term | 2 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 | ||||||||||||||||||||||||||||||
ACC | RES | APS | |||||||||||||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||||||||||||
Plan term | 5 years | ||||||||||||||||||||||||||||||
ACC | RES 2018 | APS | |||||||||||||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||||||||||||
Amount of proposed budget | $ 86,300,000 | $ 89,900,000 | |||||||||||||||||||||||||||||
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 | ||||||||||||||||||||||||||||||
ACC | Power Supply Adjustor (PSA) | APS | |||||||||||||||||||||||||||||||
Change in regulatory asset | |||||||||||||||||||||||||||||||
Beginning balance | $ 70,137,000 | 37,164,000 | $ 70,137,000 | ||||||||||||||||||||||||||||
Deferred fuel and purchased power costs — current period | 5,785,000 | (16,709,000) | |||||||||||||||||||||||||||||
Amounts charged to customers | 1,808,000 | (12,872,000) | |||||||||||||||||||||||||||||
Ending balance | 77,730,000 | $ 7,583,000 | |||||||||||||||||||||||||||||
PSA rate (in dollars per kWh) | $ / kWh | (0.000456) | 0.001658 | 0.004555 | ||||||||||||||||||||||||||||
PSA rate for prior year (in dollars per kWh) | $ / kWh | (0.002086) | 0.000536 | 0.002009 | ||||||||||||||||||||||||||||
Forward component of increase in PSA (in dollars per kWh) | $ / kWh | 0.001630 | 0.001122 | 0.002546 | ||||||||||||||||||||||||||||
Maximum increase (decrease) in PSA rate | $ / kWh | 0.004 | ||||||||||||||||||||||||||||||
Fuel and purchased power costs, excess annual limit | $ 16,400,000 | ||||||||||||||||||||||||||||||
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 | 0.116 | ||||||||||||||||||||||||||||||
United States Federal Energy Regulatory Commission | Environmental Improvement Surcharge [Member] | APS | |||||||||||||||||||||||||||||||
Change in regulatory asset | |||||||||||||||||||||||||||||||
Increase (decrease) in annual wholesale transmission rates | $ 8,750,000 | ||||||||||||||||||||||||||||||
United States Federal Energy Regulatory Commission | Open Access Transmission Tariff | APS | |||||||||||||||||||||||||||||||
Change in regulatory asset | |||||||||||||||||||||||||||||||
Increase (decrease) in annual wholesale transmission rates | $ 4,900,000 | $ (22,700,000) | |||||||||||||||||||||||||||||
Cost Recovery Mechanisms | ACC | Power Supply Adjustor (PSA) | APS | |||||||||||||||||||||||||||||||
Change in regulatory asset | |||||||||||||||||||||||||||||||
Historical component of increase in PSA (in dollars per kWh) | $ / kWh | (0.002115) | (0.002897) | |||||||||||||||||||||||||||||
Cost Recovery, Number Of Agreements | agreement | 2 | ||||||||||||||||||||||||||||||
Forecast | United States Federal Energy Regulatory Commission | Environmental Improvement Surcharge [Member] | APS | |||||||||||||||||||||||||||||||
Change in regulatory asset | |||||||||||||||||||||||||||||||
Rate Matters, Increase (Decrease) in Cost Recovery, Excess Of Annual Amount | (2,000,000) | ||||||||||||||||||||||||||||||
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 | ||||||||||||||||||||||||||||||
Subsequent Event | APS | |||||||||||||||||||||||||||||||
Change in regulatory asset | |||||||||||||||||||||||||||||||
Demand side management funds | $ 36,000,000 | ||||||||||||||||||||||||||||||
Damage from Fire, Explosion or Other Hazard | Minimum | Forecast | APS | |||||||||||||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||||||||||||
Pre-tax income | 20,000,000 | ||||||||||||||||||||||||||||||
Damage from Fire, Explosion or Other Hazard | Maximum | Forecast | APS | |||||||||||||||||||||||||||||||
Settlement Agreement | |||||||||||||||||||||||||||||||
Pre-tax income | $ 30,000,000 |
Regulatory Matters - Four Corne
Regulatory Matters - Four Corners and Cholla (Details) - APS - USD ($) $ in Millions | 1 Months Ended | ||
Sep. 30, 2018 | Apr. 30, 2018 | Mar. 31, 2020 | |
SCE | Four Corners Units 4 and 5 | |||
Business Acquisition [Line Items] | |||
Settlement agreement, ACC approved rate adjustment, annualized customer impact | $ 58.5 | $ 67.5 | |
Retired power plant costs | |||
Business Acquisition [Line Items] | |||
Net book value | $ 69 | ||
Navajo Plant | |||
Business Acquisition [Line Items] | |||
Net book value | $ 79 |
Regulatory Matters - Schedule o
Regulatory Matters - Schedule of Regulatory Assets (Details) - USD ($) $ in Thousands | Mar. 31, 2020 | Dec. 31, 2019 |
Detail of regulatory assets | ||
Current | $ 225,471 | $ 203,207 |
Non-Current | 1,302,448 | 1,304,073 |
Pension | ||
Detail of regulatory assets | ||
Current | 0 | 0 |
Non-Current | 652,691 | 660,223 |
Retired power plant costs | ||
Detail of regulatory assets | ||
Current | 28,182 | 28,182 |
Non-Current | 135,349 | 142,503 |
Income taxes — allowance for funds used during construction (AFUDC) equity | ||
Detail of regulatory assets | ||
Current | 6,815 | 6,800 |
Non-Current | 155,369 | 154,974 |
Deferred fuel and purchased power — mark-to-market (Note 7) | ||
Detail of regulatory assets | ||
Current | 51,954 | 36,887 |
Non-Current | 32,576 | 33,185 |
Deferred fuel and purchased power | ||
Detail of regulatory assets | ||
Current | 77,730 | 70,137 |
Non-Current | 0 | 0 |
Deferred property taxes | ||
Detail of regulatory assets | ||
Current | 8,569 | 8,569 |
Non-Current | 56,053 | 58,196 |
SCR deferral | ||
Detail of regulatory assets | ||
Current | 0 | 0 |
Non-Current | 58,258 | 52,644 |
Ocotillo deferral | ||
Detail of regulatory assets | ||
Current | 0 | 0 |
Non-Current | 51,767 | 38,144 |
Four Corners cost deferral | ||
Detail of regulatory assets | ||
Current | 8,077 | 8,077 |
Non-Current | 30,133 | 32,152 |
Deferred compensation | ||
Detail of regulatory assets | ||
Current | 0 | 0 |
Non-Current | 37,550 | 36,464 |
Lost fixed cost recovery | ||
Detail of regulatory assets | ||
Current | 28,885 | 26,067 |
Non-Current | 0 | 0 |
Income taxes — investment tax credit basis adjustment | ||
Detail of regulatory assets | ||
Current | 1,098 | 1,098 |
Non-Current | 24,920 | 24,981 |
Palo Verde VIEs (Note 6) | ||
Detail of regulatory assets | ||
Current | 0 | 0 |
Non-Current | 20,790 | 20,635 |
Coal reclamation | ||
Detail of regulatory assets | ||
Current | 1,068 | 1,546 |
Non-Current | 17,800 | 17,688 |
Loss on reacquired debt | ||
Detail of regulatory assets | ||
Current | 1,637 | 1,637 |
Non-Current | 11,636 | 12,031 |
Mead-Phoenix transmission line contributions in aid of construction (CIAC) | ||
Detail of regulatory assets | ||
Current | 332 | 332 |
Non-Current | 9,629 | 9,712 |
TCA balancing account | ||
Detail of regulatory assets | ||
Current | 6,048 | 6,324 |
Non-Current | 1,027 | 2,885 |
Tax expense of Medicare subsidy | ||
Detail of regulatory assets | ||
Current | 1,238 | 1,235 |
Non-Current | 4,881 | 4,940 |
AG-1 deferral | ||
Detail of regulatory assets | ||
Current | 2,787 | 2,787 |
Non-Current | 2,019 | 2,716 |
Tax expense adjustor mechanism | ||
Detail of regulatory assets | ||
Current | 942 | 1,612 |
Non-Current | 0 | 0 |
Other | ||
Detail of regulatory assets | ||
Current | 109 | 1,917 |
Non-Current | $ 0 | $ 0 |
Regulatory Matters - Schedule_2
Regulatory Matters - Schedule of Regulatory Liabilities (Details) - USD ($) $ in Thousands | Mar. 31, 2020 | Dec. 31, 2019 |
Detail of regulatory liabilities | ||
Current | $ 279,105 | $ 234,912 |
Non-Current | 2,067,801 | 2,267,835 |
Asset retirement obligations | ||
Detail of regulatory liabilities | ||
Current | 0 | 0 |
Non-Current | 311,517 | 418,423 |
Removal costs | ||
Detail of regulatory liabilities | ||
Current | 44,586 | 47,356 |
Non-Current | 135,450 | 136,072 |
Other postretirement benefits | ||
Detail of regulatory liabilities | ||
Current | 37,575 | 37,575 |
Non-Current | 130,270 | 139,634 |
Spent nuclear fuel | ||
Detail of regulatory liabilities | ||
Current | 6,638 | 6,676 |
Non-Current | 49,234 | 51,019 |
Four Corners coal reclamation | ||
Detail of regulatory liabilities | ||
Current | 5,461 | 1,059 |
Non-Current | 48,405 | 51,704 |
Income taxes — change in rates | ||
Detail of regulatory liabilities | ||
Current | 2,802 | 2,797 |
Non-Current | 51,152 | 68,265 |
Income taxes — deferred investment tax credit | ||
Detail of regulatory liabilities | ||
Current | 2,202 | 2,202 |
Non-Current | 49,910 | 50,034 |
Renewable energy standard | ||
Detail of regulatory liabilities | ||
Current | 45,872 | 39,287 |
Non-Current | 115 | 10,300 |
Demand side management | ||
Detail of regulatory liabilities | ||
Current | 1,702 | 15,024 |
Non-Current | 43,423 | 24,146 |
Sundance maintenance | ||
Detail of regulatory liabilities | ||
Current | 184 | 5,698 |
Non-Current | 13,515 | 11,319 |
Active union medical trust | ||
Detail of regulatory liabilities | ||
Current | 0 | 0 |
Non-Current | 7,986 | 2,041 |
Deferred property taxes | ||
Detail of regulatory liabilities | ||
Current | 0 | 0 |
Non-Current | 7,968 | 7,046 |
Tax expense adjustor mechanism | ||
Detail of regulatory liabilities | ||
Current | 6,615 | 7,018 |
Non-Current | 0 | 0 |
Deferred gains on utility property | ||
Detail of regulatory liabilities | ||
Current | 2,423 | 2,423 |
Non-Current | 3,577 | 4,163 |
FERC transmission true up | ||
Detail of regulatory liabilities | ||
Current | 3,304 | 1,045 |
Non-Current | 1,621 | 2,004 |
Other | ||
Detail of regulatory liabilities | ||
Current | 284 | 532 |
Non-Current | 132 | 255 |
ACC | Excess deferred income taxes - ACC - Tax Cuts and Jobs Act | ||
Detail of regulatory liabilities | ||
Current | 113,142 | 59,918 |
Non-Current | 976,018 | 1,054,053 |
United States Federal Energy Regulatory Commission | Excess deferred income taxes - ACC - Tax Cuts and Jobs Act | ||
Detail of regulatory liabilities | ||
Current | 6,315 | 6,302 |
Non-Current | $ 237,508 | $ 237,357 |
Retirement Plans and Other Po_3
Retirement Plans and Other Postretirement Benefits - Schedule of Net Benefit Cost (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2020 | Mar. 31, 2019 | |
Amortization of: | ||
Portion of cost (credit) charged to expense | $ (13,911) | $ (5,114) |
Pension Benefits | ||
Retirement Plans and Other Benefits | ||
Service cost — benefits earned during the period | 14,257 | 12,543 |
Interest cost on benefit obligation | 29,761 | 34,352 |
Expected return on plan assets | (46,806) | (42,893) |
Amortization of: | ||
Prior service credit | 0 | 0 |
Net actuarial loss | 9,011 | 11,239 |
Net periodic benefit cost (credit) | 6,223 | 15,241 |
Portion of cost (credit) charged to expense | 1,342 | 8,244 |
Other Benefits | ||
Retirement Plans and Other Benefits | ||
Service cost — benefits earned during the period | 5,717 | 4,714 |
Interest cost on benefit obligation | 6,512 | 7,526 |
Expected return on plan assets | (10,019) | (9,603) |
Amortization of: | ||
Prior service credit | (9,394) | (9,455) |
Net actuarial loss | 0 | 0 |
Net periodic benefit cost (credit) | (7,184) | (6,818) |
Portion of cost (credit) charged to expense | $ (5,456) | $ (4,817) |
Retirement Plans and Other Po_4
Retirement Plans and Other Postretirement Benefits - Narrative (Details) | 3 Months Ended |
Mar. 31, 2020USD ($) | |
Pension Benefits | |
Contributions | |
Minimum employer contributions for the next three years | $ 0 |
Maximum employer contributions for the next two years (up to) | 100,000,000 |
Other Benefits | |
Contributions | |
Estimated future employer contributions in next three years | $ 0 |
Palo Verde Sale Leaseback Var_3
Palo Verde Sale Leaseback Variable Interest Entities - Narrative (Details) | 3 Months Ended | ||
Mar. 31, 2020USD ($)power_plantLease | Mar. 31, 2019USD ($) | Dec. 31, 1986Trust | |
Palo Verde Sale Leaseback Variable Interest Entities | |||
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts | $ 4,873,000 | $ 4,873,000 | |
APS | |||
Palo Verde Sale Leaseback Variable Interest Entities | |||
Number of VIE lessor trusts | 3 | 3 | |
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts | $ 4,873,000 | $ 4,873,000 | |
Palo Verde VIE | APS | |||
Palo Verde Sale Leaseback Variable Interest Entities | |||
Increase in net income due to consolidation of Palo Verde Sale Leaseback Trusts | 5,000,000 | ||
Initial loss exposure to the VIE's noncontrolling equity participants during lease extension period | 304,000,000 | ||
Maximum loss exposure to the VIE's noncontrolling equity participants during lease extension period | $ 456,000,000 | ||
Palo Verde VIE | APS | Through 2023 | |||
Palo Verde Sale Leaseback Variable Interest Entities | |||
Number of leases under which assets are retained | Lease | 1 | ||
Palo Verde VIE | APS | Through 2033 | |||
Palo Verde Sale Leaseback Variable Interest Entities | |||
Number of leases under which assets are retained | Lease | 2 | ||
Palo Verde VIE | APS | Period 2017 through 2023 | |||
Palo Verde Sale Leaseback Variable Interest Entities | |||
Annual lease payments | $ 23,000,000 | ||
Palo Verde VIE | APS | Period 2024 through 2033 | |||
Palo Verde Sale Leaseback Variable Interest Entities | |||
Annual lease payments | $ 16,000,000 | ||
Palo Verde VIE | APS | Period 2024 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 | Mar. 31, 2020 | Dec. 31, 2019 |
Palo Verde Sale Leaseback Variable Interest Entities | ||
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation | $ 14,637,407 | $ 14,522,538 |
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets | ||
Equity — Noncontrolling interests | 127,414 | 122,540 |
APS | ||
Palo Verde Sale Leaseback Variable Interest Entities | ||
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation | 14,637,029 | 14,522,156 |
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets | ||
Equity — Noncontrolling interests | 127,414 | 122,540 |
Palo Verde VIE | ||
Palo Verde Sale Leaseback Variable Interest Entities | ||
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation | 100,938 | 101,906 |
Palo Verde VIE | APS | ||
Palo Verde Sale Leaseback Variable Interest Entities | ||
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation | 100,938 | 101,906 |
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets | ||
Equity — Noncontrolling interests | $ 127,414 | $ 122,540 |
Derivative Accounting - Narrati
Derivative Accounting - Narrative (Details) - USD ($) | Mar. 31, 2020 | Mar. 31, 2020 | Mar. 31, 2019 | Dec. 31, 2019 |
Derivative Accounting | ||||
Derivative liability | $ 87,361,000 | $ 87,361,000 | $ 72,132,000 | |
Commodity Contracts | ||||
Derivative Accounting | ||||
Derivative liability | 87,361,000 | 87,361,000 | $ 72,132,000 | |
Additional collateral to counterparties for energy related non-derivative instrument contracts | $ 97,000,000 | 97,000,000 | ||
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 | ||
Estimated loss before income taxes to be reclassified from accumulated other comprehensive income | $ 300,000 | |||
APS | ||||
Derivative Accounting | ||||
Percentage of unrealized gains and losses on certain derivatives deferred for future rate treatment | 100.00% | 100.00% | ||
Risk Management Assets | Credit Concentration Risk | ||||
Derivative Accounting | ||||
Concentration risk | 22.00% |
Derivative Accounting - Schedul
Derivative Accounting - Schedule of Gross Notional Amounts Outstanding (Details) - Commodity Contracts GWh in Thousands, Bcf in Thousands | Mar. 31, 2020GWhBcf | Dec. 31, 2019GWhBcf |
Outstanding gross notional amount of derivatives | ||
Power | GWh | 477 | 193 |
Gas | Bcf | 263 | 257 |
Derivative Accounting - Gains a
Derivative Accounting - Gains and Losses from Derivative Instruments (Details) - Commodity Contracts - USD ($) | 3 Months Ended | |
Mar. 31, 2020 | Mar. 31, 2019 | |
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 |
Designated as Hedging Instruments | Fuel and purchased power | ||
Gains and losses from derivative instruments | ||
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) | (414,000) | (436,000) |
Not Designated as Hedging Instruments | Fuel and purchased power | ||
Gains and losses from derivative instruments | ||
Net Gain (Loss) Recognized in Income | $ (30,078,000) | $ 8,170,000 |
Derivative Accounting - Derivat
Derivative Accounting - Derivative Instruments in the Balance Sheets (Details) - USD ($) | Mar. 31, 2020 | Dec. 31, 2019 |
Assets | ||
Gross Recognized Derivatives | $ 2,108,000 | $ 515,000 |
Liabilities | ||
Amount Reported on Balance Sheets | (87,361,000) | (72,132,000) |
Commodity Contracts | ||
Assets | ||
Gross Recognized Derivatives | 2,828,000 | 584,000 |
Amounts Offset | (1,532,000) | (474,000) |
Net Recognized Derivatives | 1,296,000 | 110,000 |
Other | 812,000 | 405,000 |
Amount Reported on Balance Sheets | 2,108,000 | 515,000 |
Liabilities | ||
Gross Recognized Derivatives | (87,708,000) | (71,421,000) |
Amounts Offset | 1,532,000 | 474,000 |
Net Recognized Derivatives | (86,176,000) | (70,947,000) |
Other | (1,185,000) | (1,185,000) |
Amount Reported on Balance Sheets | (87,361,000) | (72,132,000) |
Assets and Liabilities | ||
Gross Recognized Derivatives | (84,880,000) | (70,837,000) |
Amounts Offset | 0 | 0 |
Net Recognized Derivatives | (84,880,000) | (70,837,000) |
Other | (373,000) | (780,000) |
Amount Reported on Balance Sheets | (85,253,000) | (71,617,000) |
Cash collateral received from counterparties | 1,185,000 | 1,185,000 |
Commodity Contracts | Current assets | ||
Assets | ||
Gross Recognized Derivatives | 2,778,000 | 584,000 |
Amounts Offset | (1,482,000) | (474,000) |
Net Recognized Derivatives | 1,296,000 | 110,000 |
Other | 812,000 | 405,000 |
Amount Reported on Balance Sheets | 2,108,000 | 515,000 |
Commodity Contracts | Investments and other assets | ||
Assets | ||
Gross Recognized Derivatives | 50,000 | |
Amounts Offset | (50,000) | |
Net Recognized Derivatives | 0 | |
Other | 0 | |
Amount Reported on Balance Sheets | 0 | |
Commodity Contracts | Current liabilities | ||
Liabilities | ||
Gross Recognized Derivatives | (55,081,000) | (38,235,000) |
Amounts Offset | 1,482,000 | 474,000 |
Net Recognized Derivatives | (53,599,000) | (37,761,000) |
Other | (1,185,000) | (1,185,000) |
Amount Reported on Balance Sheets | (54,784,000) | (38,946,000) |
Assets and Liabilities | ||
Cash collateral received from counterparties | 1,185,000 | 1,185,000 |
Commodity Contracts | Deferred credits and other | ||
Liabilities | ||
Gross Recognized Derivatives | (32,627,000) | (33,186,000) |
Amounts Offset | 50,000 | 0 |
Net Recognized Derivatives | (32,577,000) | (33,186,000) |
Other | 0 | 0 |
Amount Reported on Balance Sheets | (32,577,000) | (33,186,000) |
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 | Mar. 31, 2020USD ($) |
Credit Risk and Credit-Related Contingent Features | |
Aggregate fair value of derivative instruments in a net liability position | $ 86,955 |
Cash collateral posted | 0 |
Additional cash collateral in the event credit-risk-related contingent features were fully triggered | $ 81,719 |
Commitments and Contingencies -
Commitments and Contingencies - Palo Verde Nuclear Generating Station and Contractual Obligations (Details) | Feb. 11, 2020USD ($) | Oct. 31, 2019USD ($) | Mar. 31, 2020USD ($)power_plant | Jun. 30, 2018USD ($)time_periodclaim | Dec. 31, 1986Trust |
Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste | |||||
Commitments and Contingencies | |||||
Litigation settlement amount | $ 15,400,000 | $ 16,000,000 | $ 84,300,000 | ||
APS | |||||
Commitments and Contingencies | |||||
Maximum insurance against public liability per occurrence for a nuclear incident (up to) | $ 13,800,000,000 | ||||
Maximum available nuclear liability insurance (up to) | 450,000,000 | ||||
Remaining nuclear liability insurance through mandatory industry wide retrospective assessment program | 13,300,000,000 | ||||
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 | 25,500,000 | ||||
Collateral assurance provided based on rating triggers | $ 73,400,000 | ||||
Period to provide collateral assurance based on rating triggers | 20 days | ||||
APS | Breach of Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste | |||||
Commitments and Contingencies | |||||
Litigation settlement amount | $ 4,500,000 | $ 4,700,000 | $ 24,500,000 | ||
Number of claims submitted | claim | 5 | ||||
Number of settlement agreement time periods | time_period | 5 |
Commitments and Contingencies_2
Commitments and Contingencies - Superfund-Related Matters, Southwest Power Outage and Clean Air Act (Details) - APS - Contaminated groundwater wells $ in Millions | Apr. 05, 2018plaintiffDefendant | Dec. 16, 2016plaintiff | Aug. 06, 2013Defendant | Mar. 31, 2020USD ($) |
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 | 2 | |||
Settled Litigation | ||||
Loss Contingencies [Line Items] | ||||
Number of plaintiffs | 2 |
Commitments and Contingencies_3
Commitments and Contingencies - Environmental Matters and Financial Assurances (Details) - USD ($) $ in Millions | Jul. 03, 2018 | Jul. 06, 2016 | Mar. 31, 2020 | Dec. 31, 2019 |
Financial Assurances | ||||
Equity contribution guarantees | $ 40 | |||
APS | Letters of Credit Expiring in 2020 | ||||
Financial Assurances | ||||
Outstanding letters of credit | 1.7 | |||
APS | Surety Bonds Expiring in 2020 | ||||
Financial Assurances | ||||
Surety bonds expiring, amount | 14 | |||
4C Acquisition, LLC | Four Corners | ||||
Environmental Matters | ||||
Percentage of share of cost of control | 7.00% | |||
Four Corners Coal Supply Agreement | ||||
Notes receivable | 40 | |||
4C Acquisition, LLC | Coal Supply Agreement Arbitration | Four Corners | ||||
Four Corners Coal Supply Agreement | ||||
Reimbursement payments due to 4CA | $ 10 | |||
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 | |||
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 | ||||
Percentage of share of cost of control | 63.00% | |||
Expected environmental cost | $ 400 | |||
Regional Haze Rules | APS | Natural gas tolling contract obligations | Four Corners Units 4 and 5 | ||||
Environmental Matters | ||||
Additional percentage share of cost of control | 7.00% | |||
Regional Haze Rules | APS | Four Corners | Four Corners Units 4 and 5 | ||||
Environmental Matters | ||||
Site contingency increase in loss exposure not accrued, best estimate | $ 45 | |||
Coal combustion waste | APS | Four Corners | ||||
Environmental Matters | ||||
Site contingency increase in loss exposure not accrued, best estimate | 22 | |||
Coal combustion waste | APS | Navajo Plant | ||||
Environmental Matters | ||||
Site contingency increase in loss exposure not accrued, best estimate | 1 | |||
Minimum | Coal combustion waste | APS | Cholla | ||||
Environmental Matters | ||||
Site contingency increase in loss exposure not accrued, best estimate | $ 15 | |||
Minimum | Coal combustion waste | APS | Cholla and Four Corners | ||||
Environmental Matters | ||||
Site contingency increase in loss exposure not accrued, best estimate | $ 10 | |||
Maximum | Coal combustion waste | APS | Cholla and Four Corners | ||||
Environmental Matters | ||||
Site contingency increase in loss exposure not accrued, best estimate | $ 15 |
Other Income and Other Expens_2
Other Income and Other Expense (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2020 | Mar. 31, 2019 | |
Other income: | ||
Interest income | $ 3,277 | $ 2,302 |
Miscellaneous | 8 | 23 |
Total other income | 12,569 | 7,169 |
Other expense: | ||
Non-operating costs | (2,658) | (2,704) |
Non-operating costs | 60 | (238) |
Miscellaneous | (2,186) | (1,416) |
Total other expense | (4,784) | (4,358) |
APS | ||
Other income: | ||
Interest income | 2,341 | 1,550 |
Miscellaneous | 8 | 22 |
Total other income | 11,633 | 6,416 |
Other expense: | ||
Non-operating costs | (2,482) | (2,467) |
Miscellaneous | (2,186) | (1,411) |
Total other expense | (4,668) | (3,878) |
SCR deferral | ||
Other income: | ||
Debt return on Four Corners SCR deferrals (Note 4) | 3,140 | 4,844 |
SCR deferral | APS | ||
Other income: | ||
Debt return on Four Corners SCR deferrals (Note 4) | 3,140 | 4,844 |
Ocotillo deferral | ||
Other income: | ||
Debt return on Four Corners SCR deferrals (Note 4) | 6,144 | 0 |
Ocotillo deferral | APS | ||
Other income: | ||
Debt return on Four Corners SCR deferrals (Note 4) | $ 6,144 | $ 0 |
Earnings Per Share (Details)
Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | |
Mar. 31, 2020 | Mar. 31, 2019 | |
Earnings Per Share [Abstract] | ||
Net income attributable to common shareholders | $ 29,993 | $ 17,918 |
Weighted average common shares outstanding - basic (in shares) | 112,594 | 112,337 |
Net effect of dilutive securities: | ||
Contingently issuable performance shares and restricted stock units (in shares) | 268 | 398 |
Weighted average common shares outstanding — diluted (in shares) | 112,862 | 112,735 |
Earnings per weighted-average common share outstanding | ||
Net income attributable to common shareholders - basic (in dollars per share) | $ 0.27 | $ 0.16 |
Net income attributable to common shareholders - diluted (in dollars per share) | $ 0.27 | $ 0.16 |
Fair Value Measurements - Asset
Fair Value Measurements - Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($) $ in Thousands | Mar. 31, 2020 | Dec. 31, 2019 |
Assets | ||
Cash equivalents | $ 26,130 | |
Commodity contracts, assets | 2,108 | $ 515 |
Commodity contracts, liabilities | (719) | (69) |
Nuclear decommissioning trust | 920,426 | 1,010,775 |
Nuclear decommissioning trust, other | 418,553 | 521,245 |
Other special use funds | 252,723 | 245,095 |
Other special use funds, other | 1,331 | 474 |
Total assets | 1,201,387 | 1,256,385 |
Total assets, other | 419,165 | 521,650 |
Liabilities | ||
Total, other | (346) | (711) |
Amount reported on balance sheet | (87,361) | (72,132) |
Equity securities | ||
Assets | ||
Nuclear decommissioning trust | 13,542 | 13,273 |
Nuclear decommissioning trust, other | 2,090 | 2,401 |
Other special use funds | 8,083 | 7,616 |
Other special use funds, other | 1,331 | 474 |
U.S. commingled equity funds | ||
Assets | ||
Nuclear decommissioning trust | 416,463 | 518,844 |
U.S. Treasury debt | ||
Assets | ||
Nuclear decommissioning trust | 152,951 | 160,607 |
Other special use funds | 238,637 | 232,848 |
Corporate debt | ||
Assets | ||
Nuclear decommissioning trust | 112,667 | 115,869 |
Mortgage-backed securities | ||
Assets | ||
Nuclear decommissioning trust | 115,790 | 118,795 |
Municipal bonds | ||
Assets | ||
Nuclear decommissioning trust | 98,605 | 73,040 |
Other special use funds | 6,003 | 4,631 |
Other fixed income | ||
Assets | ||
Nuclear decommissioning trust | 10,408 | 10,347 |
Level 1 | ||
Assets | ||
Cash equivalents | 26,130 | |
Commodity contracts, assets | 0 | 0 |
Nuclear decommissioning trust | 164,403 | 171,479 |
Other special use funds | 245,389 | 239,990 |
Total assets | 435,922 | 411,469 |
Liabilities | ||
Gross derivative liability | 0 | 0 |
Level 1 | Equity securities | ||
Assets | ||
Nuclear decommissioning trust | 11,452 | 10,872 |
Other special use funds | 6,752 | 7,142 |
Level 1 | U.S. commingled equity funds | ||
Assets | ||
Nuclear decommissioning trust | 0 | 0 |
Level 1 | U.S. Treasury debt | ||
Assets | ||
Nuclear decommissioning trust | 152,951 | 160,607 |
Other special use funds | 238,637 | 232,848 |
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 | 2,325 | 551 |
Nuclear decommissioning trust | 337,470 | 318,051 |
Other special use funds | 6,003 | 4,631 |
Total assets | 345,798 | 323,233 |
Liabilities | ||
Gross derivative liability | (79,583) | (67,992) |
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 | 112,667 | 115,869 |
Level 2 | Mortgage-backed securities | ||
Assets | ||
Nuclear decommissioning trust | 115,790 | 118,795 |
Level 2 | Municipal bonds | ||
Assets | ||
Nuclear decommissioning trust | 98,605 | 73,040 |
Other special use funds | 6,003 | 4,631 |
Level 2 | Other fixed income | ||
Assets | ||
Nuclear decommissioning trust | 10,408 | 10,347 |
Level 3 | ||
Assets | ||
Commodity contracts, assets | 502 | 33 |
Nuclear decommissioning trust | 0 | 0 |
Other special use funds | 0 | 0 |
Total assets | 502 | 33 |
Liabilities | ||
Gross derivative liability | (8,124) | (3,429) |
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 | $ 416,463 | $ 518,844 |
Fair Value Measurements - Finan
Fair Value Measurements - Financial Instruments Not Carried at Fair Value (Details) - USD ($) $ in Millions | Mar. 31, 2020 | Dec. 31, 2019 |
Fair Value Disclosures [Abstract] | ||
Stated interest rate for notes receivable | 3.90% | |
Note receivable, net book value | $ 40 | $ 44 |
Investments in Nuclear Decomm_3
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Details) - APS - USD ($) $ in Thousands | 3 Months Ended | ||
Mar. 31, 2020 | Mar. 31, 2019 | Dec. 31, 2019 | |
Nuclear decommissioning trust fund assets | |||
Fair Value | $ 1,173,149 | $ 1,255,870 | |
Total Unrealized Gains | 276,150 | 363,476 | |
Total Unrealized Losses | (4,728) | (669) | |
Amortized cost | 697,000 | 691,000 | |
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds | |||
Realized gains | 3,313 | $ 1,103 | |
Realized losses | (2,227) | (1,405) | |
Proceeds from the sale of securities | 195,087 | 179,048 | |
Equity securities | |||
Nuclear decommissioning trust fund assets | |||
Equity securities | 434,667 | 536,858 | |
Total Unrealized Gains | 234,695 | 337,681 | |
Total Unrealized Losses | (1,201) | 0 | |
Available for sale-fixed income securities | |||
Nuclear decommissioning trust fund assets | |||
Fair Value | 735,061 | 716,137 | |
Total Unrealized Gains | 41,455 | 25,795 | |
Total Unrealized Losses | (3,527) | (669) | |
Fair value of fixed income securities, summarized by contractual maturities | |||
Less than one year | 90,281 | ||
1 year – 5 years | 299,561 | ||
5 years – 10 years | 112,834 | ||
Greater than 10 years | 232,385 | ||
Total | 735,061 | ||
Other | |||
Nuclear decommissioning trust fund assets | |||
Fair Value | 3,421 | 2,875 | |
Total Unrealized Gains | 0 | 0 | |
Total Unrealized Losses | 0 | 0 | |
Nuclear Decommissioning Trusts [Member] | |||
Nuclear decommissioning trust fund assets | |||
Fair Value | 920,426 | 1,010,775 | |
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds | |||
Realized gains | 3,313 | 1,103 | |
Realized losses | (2,227) | (1,405) | |
Proceeds from the sale of securities | 178,196 | 122,593 | |
Nuclear Decommissioning Trusts [Member] | Equity securities | |||
Nuclear decommissioning trust fund assets | |||
Equity securities | 427,915 | 529,716 | |
Nuclear Decommissioning Trusts [Member] | Available for sale-fixed income securities | |||
Nuclear decommissioning trust fund assets | |||
Fair Value | 490,421 | 478,658 | |
Fair value of fixed income securities, summarized by contractual maturities | |||
Less than one year | 11,911 | ||
1 year – 5 years | 137,509 | ||
5 years – 10 years | 112,834 | ||
Greater than 10 years | 228,167 | ||
Total | 490,421 | ||
Nuclear Decommissioning Trusts [Member] | Other | |||
Nuclear decommissioning trust fund assets | |||
Fair Value | 2,090 | 2,401 | |
Other Special Use Funds [Member] | |||
Nuclear decommissioning trust fund assets | |||
Fair Value | 252,723 | 245,095 | |
Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds | |||
Realized gains | 0 | 0 | |
Realized losses | 0 | 0 | |
Proceeds from the sale of securities | 16,891 | $ 56,455 | |
Other Special Use Funds [Member] | Equity securities | |||
Nuclear decommissioning trust fund assets | |||
Equity securities | 6,752 | 7,142 | |
Other Special Use Funds [Member] | Available for sale-fixed income securities | |||
Nuclear decommissioning trust fund assets | |||
Fair Value | 244,640 | 237,479 | |
Other Special Use Funds [Member] | Other | |||
Nuclear decommissioning trust fund assets | |||
Fair Value | 1,331 | $ 474 | |
Coal Reclamation Escrow Accounts [Member] | Available for sale-fixed income securities | |||
Fair value of fixed income securities, summarized by contractual maturities | |||
Less than one year | 37,498 | ||
1 year – 5 years | 18,487 | ||
5 years – 10 years | 0 | ||
Greater than 10 years | 4,218 | ||
Total | 60,203 | ||
Active union medical trust | Available for sale-fixed income securities | |||
Fair value of fixed income securities, summarized by contractual maturities | |||
Less than one year | 40,872 | ||
1 year – 5 years | 143,565 | ||
5 years – 10 years | 0 | ||
Greater than 10 years | 0 | ||
Total | $ 184,437 |
Changes in Accumulated Other _3
Changes in Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2020 | Mar. 31, 2019 | |
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
Balance at beginning of period | $ 5,553,188 | $ 5,348,705 |
OCI (loss) before reclassifications | 292 | |
Amounts reclassified from accumulated other comprehensive loss | 1,225 | 1,207 |
Balance at end of period | 5,596,832 | 5,381,725 |
Pension and Other Postretirement Benefits | ||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
Balance at beginning of period | (56,522) | (45,997) |
OCI (loss) before reclassifications | 0 | |
Amounts reclassified from accumulated other comprehensive loss | 1,205 | 879 |
Balance at end of period | (55,317) | (45,118) |
Derivative Instruments | ||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
Balance at beginning of period | (574) | (1,711) |
OCI (loss) before reclassifications | 292 | |
Amounts reclassified from accumulated other comprehensive loss | 20 | 328 |
Balance at end of period | (262) | (1,383) |
Accumulated Other Comprehensive Income (Loss) | ||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
Balance at beginning of period | (57,096) | (47,708) |
Balance at end of period | (55,579) | (46,501) |
APS | ||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
Balance at beginning of period | 5,998,803 | 5,786,797 |
OCI (loss) before reclassifications | 292 | |
Amounts reclassified from accumulated other comprehensive loss | 1,033 | 1,080 |
Balance at end of period | 6,040,344 | 5,821,026 |
APS | Pension and Other Postretirement Benefits | ||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
Balance at beginning of period | (34,948) | (25,396) |
OCI (loss) before reclassifications | 0 | |
Amounts reclassified from accumulated other comprehensive loss | 1,013 | 752 |
Balance at end of period | (33,935) | (24,644) |
APS | Derivative Instruments | ||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
Balance at beginning of period | (574) | (1,711) |
OCI (loss) before reclassifications | 292 | |
Amounts reclassified from accumulated other comprehensive loss | 20 | 328 |
Balance at end of period | (262) | (1,383) |
APS | Accumulated Other Comprehensive Income (Loss) | ||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
Balance at beginning of period | (35,522) | (27,107) |
Balance at end of period | $ (34,197) | $ (26,027) |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended |
Mar. 31, 2020 | Dec. 31, 2017 | |
Income Tax [Line Items] | ||
Reduction in net deferred income tax liabilities | $ 1,140 | |
Amortization of an excess deferred tax liability | $ 6 | |
Regulatory liability, amortization period | 28 years 6 months | |
Domestic Tax Authority | ||
Income Tax [Line Items] | ||
Amortization of an excess deferred tax liability | $ 14 |
Asset Retirement Obligations -
Asset Retirement Obligations - Narrative (Details) - APS $ in Millions | 3 Months Ended |
Mar. 31, 2020USD ($) | |
Four Corners | |
Asset Retirement Obligations | |
Asset retirement obligation, period increase (decrease) | $ (11) |
Navajo Generating Station | |
Asset Retirement Obligations | |
Asset retirement obligation, period increase (decrease) | $ 5 |
Asset Retirement Obligations _2
Asset Retirement Obligations - Roll-Forward (Details) - APS $ in Thousands | 3 Months Ended |
Mar. 31, 2020USD ($) | |
Change in asset retirement obligations | |
Asset retirement obligations at the beginning of year | $ 657,218 |
Changes attributable to: | |
Accretion expense | 10,219 |
Settlements | (2,295) |
Newly incurred liabilities | (5,821) |
Asset retirement obligations at the end of year | $ 659,321 |