Document And Entity Information
Document And Entity Information | 3 Months Ended |
Mar. 31, 2021shares | |
Entity Information [Line Items] | |
Entity Registrant Name | PUGET ENERGY INC /WA |
Entity Central Index Key | 0001085392 |
Current Fiscal Year End Date | --12-31 |
Entity Current Reporting Status | Yes |
Entity Filer Category | Non-accelerated Filer |
Entity Common Stock, Shares Outstanding | 200 |
Document Fiscal Year Focus | 2021 |
Document Fiscal Period Focus | Q1 |
Document Type | 10-Q |
Amendment Flag | false |
Document Period End Date | Mar. 31, 2021 |
Entity Emerging Growth Company | false |
Entity Small Business | true |
Entity Shell Company | false |
Document Transition Report | false |
Document Quarterly Report | true |
Subsidiaries [Member] | |
Entity Information [Line Items] | |
Entity Registrant Name | PUGET SOUND ENERGY INC |
Entity Central Index Key | 0000081100 |
Current Fiscal Year End Date | --12-13 |
Entity Current Reporting Status | Yes |
Entity Filer Category | Non-accelerated Filer |
Entity Common Stock, Shares Outstanding | 85,903,791 |
Document Fiscal Year Focus | 2021 |
Document Fiscal Period Focus | Q1 |
Document Type | 10-Q |
Amendment Flag | false |
Document Period End Date | Mar. 31, 2021 |
Entity Emerging Growth Company | false |
Entity Small Business | true |
Entity Shell Company | false |
Document Transition Report | false |
Document Quarterly Report | true |
CONSOLIDATED STATEMENTS OF INCO
CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2021 | Mar. 31, 2020 | |
Operating revenue: | ||
Electric | $ 758,592 | $ 669,090 |
Natural Gas | 392,906 | 371,031 |
Other | 8,588 | 6,009 |
Total operating revenue | 1,160,086 | 1,046,130 |
Energy costs: | ||
Purchased electricity | 205,410 | 165,742 |
Electric generation fuel | 60,418 | 63,624 |
Residential exchange | (25,802) | (24,634) |
Purchased natural gas | 155,015 | 154,876 |
Unrealized (gain) loss on derivative instruments, net | (23,002) | 48,541 |
Utility operations and maintenance | 160,540 | 154,922 |
Non-utility expense and other | 9,906 | 12,962 |
Depreciation & Amortization | 208,431 | 164,816 |
Conservation amortization | 34,060 | 27,393 |
Taxes other than income taxes | 110,310 | 105,504 |
Total operating expenses | 895,286 | 873,746 |
Operating income (loss) | 264,800 | 172,384 |
Other income (expense): | ||
Other income | 13,630 | 14,059 |
Other expense | (1,510) | (2,282) |
Interest charges: | ||
AFUDC | 3,586 | 3,643 |
Interest expense | (89,360) | (88,884) |
Income (loss) before income taxes | 191,146 | 98,920 |
Income tax (benefit) expense | 2,153 | 3,984 |
Net income (loss) | 188,993 | 94,936 |
Subsidiaries [Member] | ||
Operating revenue: | ||
Electric | 758,592 | 669,090 |
Natural Gas | 392,906 | 371,031 |
Other | 8,588 | 6,009 |
Total operating revenue | 1,160,086 | 1,046,130 |
Energy costs: | ||
Purchased electricity | 205,410 | 165,742 |
Electric generation fuel | 60,418 | 63,624 |
Residential exchange | (25,802) | (24,634) |
Purchased natural gas | 155,015 | 154,876 |
Unrealized (gain) loss on derivative instruments, net | (23,002) | 48,541 |
Utility operations and maintenance | 160,540 | 154,922 |
Non-utility expense and other | 9,418 | 12,735 |
Depreciation & Amortization | 208,362 | 164,771 |
Conservation amortization | 34,060 | 27,393 |
Taxes other than income taxes | 110,310 | 105,504 |
Total operating expenses | 894,729 | 873,474 |
Operating income (loss) | 265,357 | 172,656 |
Other income (expense): | ||
Other income | 11,034 | 11,283 |
Other expense | (1,510) | (2,282) |
Interest charges: | ||
AFUDC | 3,586 | 3,643 |
Interest expense | (62,371) | (60,714) |
Income (loss) before income taxes | 216,096 | 124,586 |
Income tax (benefit) expense | 16,626 | 13,265 |
Net income (loss) | $ 199,470 | $ 111,321 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2021 | Mar. 31, 2020 | |
Net Income (Loss) Attributable to Parent | $ 188,993 | $ 94,936 |
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent [Abstract] | ||
Net unrealized gain (loss) from pension and postretirement plans, net of tax | 2,385 | 5,170 |
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent, Total | 2,385 | 5,170 |
Comprehensive Income (Loss), Net of Tax, Attributable to Parent, Total | 191,378 | 100,106 |
Subsidiaries [Member] | ||
Net Income (Loss) Attributable to Parent | 199,470 | 111,321 |
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent [Abstract] | ||
Net unrealized gain (loss) from pension and postretirement plans, net of tax | 4,458 | 7,710 |
Amortization Of Financing Cash Flow Hedge Contracts To Earnings During Period Net Of Tax | 96 | 96 |
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent, Total | 4,554 | 7,806 |
Comprehensive Income (Loss), Net of Tax, Attributable to Parent, Total | $ 204,024 | $ 119,127 |
CONSOLIDATED STATEMENTS OF CO_2
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2021 | Mar. 31, 2020 | |
Net unrealized gain (loss) from pension and postretirement plans, net of tax | $ 634 | $ 1,373 |
Subsidiaries [Member] | ||
Net unrealized gain (loss) from pension and postretirement plans, net of tax | 1,185 | 2,047 |
Amortization of treasury interest rate swaps to earnings, net of tax | $ 26 | $ 26 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Mar. 31, 2021 | Dec. 31, 2020 |
Utility Plant [Abstract] | ||
Public Utilities Property Plant And Equipment Electric Plant | $ 9,288,156 | $ 9,200,231 |
Public Utilities Property Plant And Equipment Gas Plant | 4,296,864 | 4,227,532 |
Public Utilities Property Plant And Equipment Common Plant | 1,085,442 | 1,116,524 |
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation | (3,736,675) | (3,671,094) |
Public Utilities, Property, Plant and Equipment, Net, Total | 10,933,787 | 10,873,193 |
Other Property And Investments [Abstract] | ||
Goodwill | 1,656,513 | 1,656,513 |
Other Property And Investments | 327,674 | 324,184 |
Total Other Property And Investments | 1,984,187 | 1,980,697 |
Assets, Current [Abstract] | ||
Cash and Cash Equivalents, at Carrying Value | 36,507 | 52,307 |
Restricted Cash and Cash Equivalents, Current | 24,443 | 29,544 |
Accounts Receivable, after Allowance for Credit Loss, Current | 374,296 | 352,132 |
Unbilled Revenues | 219,450 | 221,871 |
Other Inventory, Supplies, Gross | 117,891 | 118,333 |
Fuel And Gas Inventory At Average Cost | 38,743 | 48,795 |
Derivative Asset, Current | 47,221 | 33,015 |
Prepaid Expense and Other Assets, Current | 49,630 | 45,746 |
Power Contract Acquisition Adjustment Gain Current | 15,694 | 14,874 |
Assets, Current, Total | 923,875 | 916,617 |
Other Longterm And Regulatory Assets [Abstract] | ||
Power Cost Adjustment Mechanism Asset, Noncurrent | 71,257 | 82,801 |
purchase gas adjustment, long-term | 46,787 | 87,655 |
Regulatory Assets Related To Power Contracts | 11,398 | 11,728 |
Other Regulatory Assets | 737,377 | 747,651 |
Derivative Asset, Noncurrent | 4,925 | 8,805 |
Power Contract Acquisition Adjustment Non Current | 75,601 | 80,900 |
Operating Lease, Right-of-Use Asset | 194,245 | 172,167 |
Other Assets, Noncurrent | 86,680 | 80,751 |
Total Longterm And Regulatory Assets | 1,228,270 | 1,272,458 |
Assets, Total | 15,070,119 | 15,042,965 |
Capitalization [Abstract] | ||
Common stock | 0 | 0 |
Additional Paid in Capital | 3,313,532 | 3,313,532 |
Retained Earnings (Accumulated Deficit) | 1,078,841 | 912,787 |
Accumulated Other Comprehensive Income (Loss), Net of Tax | (84,052) | (86,437) |
Stockholders' Equity Attributable to Parent, Total | 4,308,321 | 4,139,882 |
Long-term Debt, Excluding Current Maturities [Abstract] | ||
Senior Notes, Noncurrent | 4,212,000 | 4,212,000 |
Long-term Pollution Control Bond | 161,860 | 161,860 |
Other Long-term Debt, Noncurrent | 1,733,500 | 1,724,700 |
Debt discount and other | (203,026) | (206,120) |
Long-term Debt, Excluding Current Maturities, Total | 5,904,334 | 5,892,440 |
Capitalization, Long-term Debt and Equity, Total | 10,212,655 | 10,032,322 |
Liabilities, Current [Abstract] | ||
Accounts Payable, Current | 324,037 | 342,404 |
Short-term Debt | 191,000 | 373,800 |
Long-term Debt, Current Maturities | 526,345 | 526,412 |
Accrued Expenses [Abstract] | ||
Taxes Payable, Current | 134,228 | 110,752 |
Employee-related Liabilities, Current | 35,295 | 42,530 |
Interest Payable, Current | 79,400 | 73,647 |
Derivative Liability, Current | 19,839 | 31,441 |
Power Contract Acquisition Adjustment Loss Current | 2,036 | 2,039 |
Operating Lease, Liability, Current | 19,238 | 19,204 |
Other Liabilities, Current | 88,335 | 73,385 |
Liabilities, Current, Total | 1,419,753 | 1,595,614 |
Longterm And Regulatory Liabilities [Abstract] | ||
Deferred Tax and Other Liabilities, Noncurrent | 846,692 | 810,729 |
Derivative Liability, Noncurrent | 24,332 | 29,833 |
Regulatory Liabilities, Noncurrent | 735,368 | 732,498 |
Deferred Tax Liabilities, Regulatory Assets and Liabilities | 924,567 | 953,274 |
Regulatory Liabilities Related To Power Contracts | 91,295 | 95,774 |
Power Contract Acquisition Adjustment Loss Non Current | 9,362 | 9,689 |
Operating Lease, Liability, Noncurrent | 182,288 | 160,980 |
Other Deferred Credits | 623,807 | 622,252 |
Total Longterm And Regulatory Liabilities | 3,437,711 | 3,415,029 |
Commitments and Contingencies | ||
Liabilities and Equity, Total | $ 15,070,119 | 15,042,965 |
Common stock, par value (in dollars per share) | $ 0.01 | |
Common stock, shares authorized (in shares) | 1,000 | |
Common Stock, Shares, Outstanding | 200 | |
Subsidiaries [Member] | ||
Utility Plant [Abstract] | ||
Public Utilities Property Plant And Equipment Electric Plant | $ 11,116,750 | 11,035,402 |
Public Utilities Property Plant And Equipment Gas Plant | 4,855,247 | 4,786,419 |
Public Utilities Property Plant And Equipment Common Plant | 1,107,719 | 1,139,120 |
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation | (6,145,929) | (6,087,748) |
Public Utilities, Property, Plant and Equipment, Net, Total | 10,933,787 | 10,873,193 |
Other Property And Investments [Abstract] | ||
Other Property And Investments | 83,620 | 83,855 |
Total Other Property And Investments | 83,620 | 83,855 |
Assets, Current [Abstract] | ||
Cash and Cash Equivalents, at Carrying Value | 36,051 | 51,177 |
Restricted Cash and Cash Equivalents, Current | 24,443 | 29,544 |
Accounts Receivable, after Allowance for Credit Loss, Current | 376,228 | 355,850 |
Unbilled Revenues | 219,450 | 221,871 |
Other Inventory, Supplies, Gross | 117,891 | 118,333 |
Fuel And Gas Inventory At Average Cost | 37,479 | 47,531 |
Derivative Asset, Current | 47,221 | 33,015 |
Prepaid Expense and Other Assets, Current | 49,630 | 45,746 |
Assets, Current, Total | 908,393 | 903,067 |
Other Longterm And Regulatory Assets [Abstract] | ||
Power Cost Adjustment Mechanism Asset, Noncurrent | 71,257 | 82,801 |
purchase gas adjustment, long-term | 46,787 | 87,655 |
Other Regulatory Assets | 737,377 | 747,651 |
Derivative Asset, Noncurrent | 4,925 | 8,805 |
Operating Lease, Right-of-Use Asset | 194,245 | 172,167 |
Other Assets, Noncurrent | 85,294 | 79,231 |
Total Longterm And Regulatory Assets | 1,139,885 | 1,178,310 |
Assets, Total | 13,065,685 | 13,038,425 |
Capitalization [Abstract] | ||
Common stock | 859 | 859 |
Additional Paid in Capital | 3,485,105 | 3,485,105 |
Retained Earnings (Accumulated Deficit) | 1,023,818 | 876,401 |
Accumulated Other Comprehensive Income (Loss), Net of Tax | (176,402) | (180,956) |
Stockholders' Equity Attributable to Parent, Total | 4,333,380 | 4,181,409 |
Long-term Debt, Excluding Current Maturities [Abstract] | ||
Senior Notes, Noncurrent | 4,212,000 | 4,212,000 |
Long-term Pollution Control Bond | 161,860 | 161,860 |
Debt discount and other | (35,337) | (35,816) |
Long-term Debt, Excluding Current Maturities, Total | 4,338,523 | 4,338,044 |
Capitalization, Long-term Debt and Equity, Total | 8,671,903 | 8,519,453 |
Liabilities, Current [Abstract] | ||
Accounts Payable, Current | 324,152 | 342,504 |
Short-term Debt | 191,000 | 373,800 |
Long-term Debt, Current Maturities | 2,345 | 2,412 |
Accrued Expenses [Abstract] | ||
Taxes Payable, Current | 130,781 | 107,254 |
Employee-related Liabilities, Current | 35,295 | 42,530 |
Interest Payable, Current | 58,002 | 48,189 |
Derivative Liability, Current | 19,839 | 31,441 |
Operating Lease, Liability, Current | 19,238 | 19,204 |
Other Liabilities, Current | 88,335 | 73,385 |
Liabilities, Current, Total | 868,987 | 1,040,719 |
Longterm And Regulatory Liabilities [Abstract] | ||
Deferred Tax and Other Liabilities, Noncurrent | 1,038,347 | 987,382 |
Derivative Liability, Noncurrent | 24,332 | 29,833 |
Regulatory Liabilities, Noncurrent | 734,104 | 731,234 |
Deferred Tax Liabilities, Regulatory Assets and Liabilities | 925,277 | 953,987 |
Operating Lease, Liability, Noncurrent | 182,288 | 160,980 |
Other Deferred Credits | 620,447 | 614,837 |
Total Longterm And Regulatory Liabilities | 3,524,795 | 3,478,253 |
Commitments and Contingencies | ||
Liabilities and Equity, Total | $ 13,065,685 | $ 13,038,425 |
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized (in shares) | 150,000,000 | 150,000,000 |
Common Stock, Shares, Outstanding | 85,903,791 | 85,903,791 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands | Mar. 31, 2021 | Dec. 31, 2020 |
ASSETS | ||
Construction work in progress | $ 749,572 | $ 712,204 |
Assets, Current [Abstract] | ||
Allowance for doubtful accounts | 30,392 | 20,080 |
Common shareholder’s equity: | ||
Public Utilities, Property, Plant and Equipment, Construction Work in Progress | 749,572 | 712,204 |
Allowance for doubtful accounts | $ 30,392 | 20,080 |
Common stock, par value (in dollars per share) | $ 0.01 | |
Common stock, shares authorized (in shares) | 1,000 | |
Common Stock, Shares, Outstanding | 200 | |
Subsidiaries [Member] | ||
ASSETS | ||
Construction work in progress | $ 749,572 | 712,204 |
Assets, Current [Abstract] | ||
Allowance for doubtful accounts | 30,392 | 20,080 |
Common shareholder’s equity: | ||
Public Utilities, Property, Plant and Equipment, Construction Work in Progress | 749,572 | 712,204 |
Allowance for doubtful accounts | $ 30,392 | $ 20,080 |
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized (in shares) | 150,000,000 | 150,000,000 |
Common Stock, Shares, Outstanding | 85,903,791 | 85,903,791 |
CONSOLIDATED STATEMENTS OF COMM
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY Statement - USD ($) $ in Thousands | Total | Common Stock [Member] | Additional Paid-in Capital [Member] | Retained Earnings [Member] | AOCI Attributable to Parent [Member] | Subsidiaries [Member] | Subsidiaries [Member]Common Stock [Member] | Subsidiaries [Member]Additional Paid-in Capital [Member] | Subsidiaries [Member]Retained Earnings [Member] | Subsidiaries [Member]AOCI Attributable to Parent [Member] |
Beginning Balance (in shares) at Dec. 31, 2019 | 200 | 85,903,791 | ||||||||
Beginning Balance at Dec. 31, 2019 | $ 4,000,299 | $ 0 | $ 3,308,957 | $ 775,491 | $ (84,149) | $ 4,048,680 | $ 859 | $ 3,485,105 | $ 751,193 | $ (188,477) |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||
Net Income (Loss) Attributable to Parent | 94,936 | 94,936 | 111,321 | 111,321 | ||||||
Dividends, Common Stock | (22,645) | (22,645) | (53,794) | (53,794) | ||||||
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent | 5,170 | 5,170 | 7,806 | 7,806 | ||||||
Ending Balance (in shares) at Mar. 31, 2020 | 200 | 85,903,791 | ||||||||
Ending Balance at Mar. 31, 2020 | 4,077,760 | $ 0 | 3,308,957 | 847,782 | (78,979) | $ 4,114,013 | $ 859 | 3,485,105 | 808,720 | (180,671) |
Beginning Balance (in shares) at Dec. 31, 2020 | 200 | 85,903,791 | 85,903,791 | |||||||
Beginning Balance at Dec. 31, 2020 | 4,139,882 | $ 0 | 3,313,532 | 912,787 | (86,437) | $ 4,181,409 | $ 859 | 3,485,105 | 876,401 | (180,956) |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||
Net Income (Loss) Attributable to Parent | 188,993 | 188,993 | 199,470 | 199,470 | ||||||
Dividends, Common Stock | (22,939) | (22,939) | (52,053) | (52,053) | ||||||
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent | $ 2,385 | 2,385 | $ 4,554 | 4,554 | ||||||
Ending Balance (in shares) at Mar. 31, 2021 | 200 | 200 | 85,903,791 | 85,903,791 | ||||||
Ending Balance at Mar. 31, 2021 | $ 4,308,321 | $ 0 | $ 3,313,532 | $ 1,078,841 | $ (84,052) | $ 4,333,380 | $ 859 | $ 3,485,105 | $ 1,023,818 | $ (176,402) |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2021 | Mar. 31, 2020 | Dec. 31, 2020 | |
Net Cash Provided by (Used in) Operating Activities [Abstract] | |||
Net Income (Loss) Attributable to Parent | $ 188,993 | $ 94,936 | |
Adjustments to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities [Abstract] | |||
Depreciation & Amortization | 208,431 | 164,816 | |
Conservation amortization | 34,060 | 27,393 | |
Deferred Income Taxes and Tax Credits | 6,622 | 8,602 | |
Unrealized Gain (Loss) on Derivatives | (23,002) | 48,541 | |
Afudc Equity | (5,780) | (5,603) | |
Monetized production tax credits | (45,178) | (23,543) | |
Other Noncash Income (Expense) | 3,518 | (6,075) | |
Increase (Decrease) in Other Regulatory Assets | (14,351) | (16,865) | |
Purchased gas adjustment | 40,868 | 41,429 | |
Increase (Decrease) in Other Operating Assets | (5,695) | (27,016) | |
Increase (Decrease) in Operating Capital [Abstract] | |||
Increase (Decrease) in Accounts and Other Receivables | (19,743) | 24,120 | |
Increase (Decrease) in Materials and Supplies | 442 | 1,072 | |
Increase (Decrease) in Fuel Inventories | 10,052 | 14,497 | |
Increase (Decrease) in Prepaid Expense and Other Assets | (3,884) | 251 | |
Increase (Decrease) in Accounts Payable | (14,868) | (45,236) | |
Increase (Decrease) in Income Taxes Payable | 23,476 | 21,178 | |
Increase (Decrease) in Other Accounts Payable and Accrued Liabilities | (512) | (11,126) | |
Net Cash Provided by (Used in) Operating Activities, Total | 383,449 | 311,371 | |
Net Cash Provided by (Used in) Investing Activities [Abstract] | |||
Construction expenditures excluding equity allowance for funds used during construction | (213,781) | (223,707) | |
Payments for (Proceeds from) Other Investing Activities | 362 | (233) | |
Net Cash Provided by (Used in) Investing Activities, Total | (213,419) | (223,940) | |
Net Cash Provided by (Used in) Financing Activities [Abstract] | |||
Proceeds from (Repayments of) Short-term Debt | (182,800) | (100,000) | |
Payments of Dividends | (22,939) | (22,645) | |
Proceeds from Issuance of Long-term Debt | 8,800 | 7,400 | |
Repayments of Long-term Debt | (66) | 0 | |
Proceeds from (Payments for) Other Financing Activities | 6,074 | 3,670 | |
Net Cash Provided by (Used in) Financing Activities, Total | (190,931) | (111,575) | |
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect, Total | (20,901) | (24,144) | |
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Beginning Balance | 81,851 | 66,146 | $ 66,146 |
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Ending Balance | 60,950 | 42,002 | 81,851 |
Supplemental Cash Flow Information [Abstract] | |||
Interest Paid, Excluding Capitalized Interest, Operating Activities | 77,160 | 78,636 | |
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract] | |||
Capital Expenditures Incurred but Not yet Paid | 54,805 | 56,699 | |
Subsidiaries [Member] | |||
Net Cash Provided by (Used in) Operating Activities [Abstract] | |||
Net Income (Loss) Attributable to Parent | 199,470 | 111,321 | |
Adjustments to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities [Abstract] | |||
Depreciation & Amortization | 208,362 | 164,771 | |
Conservation amortization | 34,060 | 27,393 | |
Deferred Income Taxes and Tax Credits | 21,044 | 12,215 | |
Unrealized Gain (Loss) on Derivatives | (23,002) | 48,541 | |
Afudc Equity | (5,780) | (5,603) | |
Monetized production tax credits | (45,178) | (23,543) | |
Other Noncash Income (Expense) | 885 | (8,711) | |
Increase (Decrease) in Other Regulatory Assets | (14,351) | (16,865) | |
Purchased gas adjustment | 40,868 | 41,429 | |
Increase (Decrease) in Other Operating Assets | (3,077) | (23,801) | |
Increase (Decrease) in Operating Capital [Abstract] | |||
Increase (Decrease) in Accounts and Other Receivables | (17,957) | 25,892 | |
Increase (Decrease) in Materials and Supplies | 442 | 1,072 | |
Increase (Decrease) in Fuel Inventories | 10,052 | 14,497 | |
Increase (Decrease) in Prepaid Expense and Other Assets | (3,884) | 251 | |
Increase (Decrease) in Accounts Payable | (14,853) | (36,201) | |
Increase (Decrease) in Income Taxes Payable | 23,527 | 26,850 | |
Increase (Decrease) in Other Accounts Payable and Accrued Liabilities | 3,549 | (7,607) | |
Net Cash Provided by (Used in) Operating Activities, Total | 414,177 | 351,901 | |
Net Cash Provided by (Used in) Investing Activities [Abstract] | |||
Construction expenditures excluding equity allowance for funds used during construction | (205,927) | (225,612) | |
Payments for (Proceeds from) Other Investing Activities | 362 | (233) | |
Net Cash Provided by (Used in) Investing Activities, Total | (205,565) | (225,845) | |
Net Cash Provided by (Used in) Financing Activities [Abstract] | |||
Proceeds from (Repayments of) Short-term Debt | (182,800) | (100,000) | |
Payments of Dividends | (52,053) | (53,794) | |
Repayments of Long-term Debt | (66) | 0 | |
Proceeds from (Payments for) Other Financing Activities | 6,080 | 3,668 | |
Net Cash Provided by (Used in) Financing Activities, Total | (228,839) | (150,126) | |
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect, Total | (20,227) | (24,070) | |
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Beginning Balance | 80,721 | 64,891 | 64,891 |
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Ending Balance | 60,494 | 40,821 | $ 80,721 |
Supplemental Cash Flow Information [Abstract] | |||
Interest Paid, Excluding Capitalized Interest, Operating Activities | 47,749 | 47,115 | |
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract] | |||
Capital Expenditures Incurred but Not yet Paid | $ 54,805 | $ 56,699 |
Summary of Consolidation and Si
Summary of Consolidation and Significant Accounting Policy | 3 Months Ended |
Mar. 31, 2021 | |
Accounting Policies [Abstract] | |
Significant Accounting Policies | Summary of Consolidation and Significant Accounting Policy Basis of Presentation Puget Energy is an energy services holding company that owns Puget Sound Energy. PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering approximately 6,000 square miles, primarily in the Puget Sound region. Puget Energy also has a wholly-owned non-regulated subsidiary, Puget LNG, LLC, which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma LNG facility, currently under construction. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that are incurred by PSE and allocated to Puget LNG are related party transactions by nature. In 2009, Puget Holdings LLC (Puget Holdings), owned by a consortium of long-term infrastructure investors, completed its merger with Puget Energy (the merger). As a result of the merger, all of Puget Energy’s common stock is indirectly owned by Puget Holdings. The acquisition of Puget Energy was accounted for in accordance with FASB ASC 805, “Business Combinations”, as of the date of the merger. ASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger date. The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries. PSE’s consolidated financial statements include the accounts of PSE and its subsidiary. Puget Energy and PSE are collectively referred to herein as “the Company”. The consolidated financial statements are presented after elimination of all significant intercompany items and transactions. PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any ASC 805, “Business Combinations” purchase accounting adjustments. The preparation of financial statements in conformity with U.S. 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 the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. Allowance for Credit Losses Management measures expected credit losses on trade receivables on a collective basis by receivable type, which include electric retail receivables, gas retail receivables, and electric wholesale receivables. The estimate of expected credit losses considers historical credit loss information that is adjusted for current conditions and reasonable and supportable forecasts. The allowance increased during 2020 due to both an increase in the provision combined with a reduction in receivables charged-off during the period. T he Ratepayer Assistance and Preservation of Essential Services proclamation issued by the governor in April 2020 included a moratorium on disconnecting customers, which resulted in a cessation of account receivable write-offs for non-payment. The following table presents the activity in the allowance for credit losses for accounts receivable for the three months ended March 31, 2021 and 2020: Puget Energy and Three Months Ended (Dollars in Thousands) 2021 2020 Allowance for credit losses: Beginning balance $ 20,080 $ 8,294 Provision for credit loss expense 12,452 4,894 Receivables charged-off (2,140) (3,374) Total ending allowance balance $ 30,392 $ 9,814 Tacoma LNG Facility In August 2015, PSE filed a proposal with the Washington Commission to develop a liquified natural gas (LNG) facility at the Port of Tacoma. Currently under construction at the Port of Tacoma, the facility is expected to be operational in 2021. The Tacoma LNG facility is designed to provide peak-shaving services to PSE’s natural gas customers. By storing surplus natural gas, PSE is able to meet the requirements of peak consumption. LNG will also provide fuel to transportation customers, particularly in the marine market. On January 24, 2018, Puget Sound Clean Air Agency (PSCAA) determined a Supplemental Environmental Impact Statement (SEIS) was necessary in order to rule on the air quality permit for the facility. As a result of requiring a SEIS, the Company's construction schedule was impacted. PSE received the SEIS which concluded the LNG facility would result in a net decrease in GHG emissions providing, in part, that the natural gas for the facility was sourced from British Columbia or Alberta. On December 10, 2019, the PSCAA approved the Notice of Construction permit, a decision which has been appealed to the Washington Pollution Control Hearings Board by each of the Puyallup Tribe of Indians and nonprofit law firm Earthjustice. A meeting with the Washington Pollution Control Hearings Board occurred in April 2021 and a decision is forthcoming. The facility achieved mechanical completion in February 2021, however, it remains nonoperational as additional construction and testing are completed. Pursuant to an order by the Washington Utilities and Transportation Commission (Washington Commission), PSE will be allocated approximately 43.0% of common capital and operating costs, consistent with the regulated portion of the Tacoma LNG facility. The remaining 57.0% of common capital and operating costs of the Tacoma LNG facility will be allocated to Puget LNG. Per this allocation of costs, $239.4 million and $231.6 million of construction work in progress related to Puget LNG's portion of the Tacoma LNG facility is reported in the Puget Energy "Other property and investments" line item as of March 31, 2021 and December 31, 2020, respectively. Additionally, $0.2 million and $0.3 million of operating costs are reported in the Puget Energy "Non-utility expense and other" financial statement line item for the three months ended March 31, 2021, and March 31, 2020, respectively. Additionally, $216.5 million and $207.7 million of construction work in progress related to PSE’s portion of the Tacoma LNG facility is reported in the PSE “Utility plant - Natural gas plant” financial statement line item as of March 31, 2021 and December 31, 2020, respectively, as PSE is a regulated entity. Variable Interest Entities On April 12, 2017, PSE entered into a power purchase agreement (PPA) with Skookumchuck Wind Energy Project, LLC (Skookumchuck) pursuant to which Skookumchuck would develop a wind generation facility and, once completed, sell bundled energy and associated attributes, namely renewable energy certificates (RECs) to PSE over a term of 20 years. Skookumchuck commenced commercial operation in November 2020. PSE has no equity investment in Skookumchuck but is Skookumchuck’s only customer. Based on the terms of the contract, PSE will receive all of the output of the facility, subject to curtailment rights. PSE has concluded that Skookumchuck is a variable interest entity (VIE) and that PSE is not the primary beneficiary of this VIE since it does not control the commercial and operating activities of the facility. Additionally, PSE does not have the obligation to absorb losses or receive benefits. Therefore, PSE will not consolidate the VIE. Purchased energy of $5.7 million was recognized in purchased electricity on the Company's consolidated statements of income and $3.6 million is included in accounts payable on the Company's consolidated balance sheet for the quarter ended March 31, 2021. |
New Accounting Pronouncements
New Accounting Pronouncements | 3 Months Ended |
Mar. 31, 2021 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
New Accounting Pronouncements | New Accounting Pronouncements Reference Rate Reform In March 2020, the FASB issued ASU 2020-04, "Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting ” (Issued March 2020): ASU 2020-04 provides temporary optional expedients and exceptions to the current guidance on contract modifications to ease the financial reporting burdens related to the expected market transition from LIBOR and other interbank offered rates to alternative reference rates. The Company has term loans, credit agreements, and promissory notes that reference LIBOR. As of March 31, 2021, the Company has not utilized any of the expedients discussed within this ASU, however, it continues to assess other agreements to determine if LIBOR is included and if the expedients would be utilized through the allowed period of December 2022. |
Revenue
Revenue | 3 Months Ended |
Mar. 31, 2021 | |
Revenue from Contract with Customer [Abstract] | |
Revenue | Revenue The following table presents disaggregated revenue from contracts with customers, and other revenue by major source: Puget Energy and (Dollars in Thousands) Three Months Ended Revenue from contracts with customers: 2021 2020 Electric retail $ 664,102 $ 607,693 Natural gas retail 387,863 365,637 Other 56,129 43,774 Total revenue from contracts with customers 1,108,094 1,017,104 Alternative revenue programs (1,928) 1,150 Other non-customer revenue 53,920 27,876 Total operating revenue $ 1,160,086 $ 1,046,130 Revenue at PSE is recognized when performance obligations under the terms of a contract or tariff with our customers are satisfied. Performance obligations are satisfied generally through performance of PSE's obligation over time or with transfer of control of electric power, natural gas, and other revenue from contracts with customers. Revenue is measured as the amount of consideration expected to be received in exchange for transferring goods and services. Electric and Natural Gas Retail Revenue Electric and natural gas retail revenue consists of tariff-based sales of electricity and natural gas to PSE's customers. For tariff contracts, PSE has elected the portfolio approach practical expedient model to apply the revenue from contracts with customers to groups of contracts. The Company determined that the portfolio approach will not differ from considering each contract or performance obligation separately. Electric and natural gas tariff contracts include the performance obligation of standing ready to perform electric and natural gas services. The electricity and natural gas the customer chooses to consume is considered an option and is recognized over time using the output method when the customer simultaneously consumes the electricity or natural gas. PSE has elected the right to invoice practical expedient for unbilled retail revenue. The obligation of standing ready to perform electric service and the consumption of electricity and natural gas at market value implies a right to consideration for performance completed to date. The Company believes that tariff prices approved by the Washington Commission represent stand-alone selling prices for the performance obligations under ASC 606. PSE collects Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes and presents the taxes on a gross basis, as PSE is the taxpayer for those excise and municipal taxes. Other Revenue from Contracts with Customers Other revenue from contracts with customers is primarily comprised of electric transmission, natural gas transportation, biogas, and wholesale revenue sold on an intra-month basis. Electric Transmission and Natural Gas Transportation Revenue Transmission and transportation tariff contracts include the performance obligation to transmit and transport electricity or natural gas. Transfer of control and recognition of revenue occurs over time as the customer simultaneously receives the transmission and transportation services. Measurement of satisfaction of this performance obligation is determined using the output method. Similar to retail revenue, the Company utilizes the right to invoice practical expedient as PSE’s right to consideration is tied directly to the value of power and natural gas transmitted and transported each month. The price is based on the tariff rates that were approved by the Washington Commission or the FERC and, therefore, corresponds directly to the value to the customer for performance completed to date. Biogas Biogas is a renewable natural gas fuel that PSE purchases and sells along with the renewable green attributes derived from the renewable natural gas. Biogas contracts include the performance obligations of biogas and renewable credit delivery upon PSE receiving produced biogas from its supplier. Transfer of control and recognition of revenue occurs at a point in time as biogas is considered a storable commodity and may not be consumed as it is delivered. Wholesale Wholesale revenue at PSE includes sales of electric power and non-core natural gas to other utilities or marketers. Wholesale revenue contracts include the performance obligation of physical electric power or natural gas. There are typically no added fixed or variable amounts on top of the established rate for power or natural gas and contracts always have a stated, fixed quantity of power or natural gas delivered. Transfer of control and recognition of revenue occurs at a point in time when the customer takes physical possession of electric power or natural gas. Non-core gas consists of natural gas supply in excess of natural gas used for generation, sold to third parties to mitigate the costs of firm transportation and storage capacity for its core natural gas customers. PSE reports non-core gas sold net of costs as PSE does not take control of the natural gas but is merely an agent within the market that connects a seller to a purchaser. Other Revenue In accordance with ASC 606, PSE separately presents revenue not collected from contracts with customers that falls under other accounting guidance. Transaction Price Allocated to Remaining Performance Obligations In December 2020, PLNG entered into a contract with one customer where PLNG is selling LNG over a 10-year delivery period beginning no later than 2024. The contract requires the customer to purchase a minimum annual quantity even if the customer does not take delivery. The price of the LNG includes a fixed charge, a fuel charge that includes both a market index and fixed margin component and other variable consideration. The fixed transaction price is allocated to the remaining performance obligations which is determined by the fixed charge components multiplied by the outstanding minimum annual quantity. Based on management’s best estimate of commencement, the Company expects to recognize this revenue over the following time periods: Puget Energy (Dollars in Thousands) 2024 2025 2026 2027 2028 Thereafter Total Remaining Performance Obligations $ 15,359 $ 19,710 $ 19,454 $ 19,454 $ 19,454 $ 102,135 $ 195,566 |
Accounting for Derivative Instr
Accounting for Derivative Instruments and Hedging Activities | 3 Months Ended |
Mar. 31, 2021 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Accounting for Derivative Instruments and Hedging Activities | Accounting for Derivative Instruments and Hedging Activities PSE employs various energy portfolio optimization strategies but is not in the business of assuming risk for the purpose of realizing speculative trading revenue. The nature of serving regulated electric customers with its portfolio of owned and contracted electric generation resources exposes PSE and its customers to some volumetric and commodity price risks within the sharing mechanism of the power cost adjustment (PCA). Therefore, wholesale market transactions and PSE's related hedging strategies are focused on reducing costs and risks where feasible; thus, reducing volatility of costs in the portfolio. In order to manage its exposure to the variability in future cash flows for forecasted energy transactions, PSE utilizes a programmatic hedging strategy which extends out three years. PSE's hedging strategy includes a risk-responsive component for the core natural gas portfolio, which utilizes quantitative risk-based measures with defined objectives to balance both portfolio risk and hedge costs. PSE's energy risk portfolio management function monitors and manages these risks using analytical models and tools. In order to manage risks effectively, PSE enters into forward physical electric and natural gas purchase and sale agreements, fixed-for-floating swap contracts, and commodity call/put options. Currently, the Company does not apply cash flow hedge accounting and therefore records all mark-to-market gains or losses through earnings. The Company manages its interest rate risk through the issuance of mostly fixed-rate debt with varied maturities. The Company utilizes internal cash from operations, borrowings under its commercial paper program and its credit facilities to meet short-term funding needs. The Company may enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts. The following table presents the volumes, fair values and classification of the Company's derivative instruments recorded on the balance sheets: Puget Energy and March 31, 2021 December 31, 2020 (Dollars in Thousands) Volumes Assets 1 Liabilities 2 Volumes Assets 1 Liabilities 2 Electric portfolio derivatives * $ 32,366 $ 33,743 * $ 22,544 $ 46,922 Natural gas derivatives (MMBtus) 3 331 19,780 10,428 320 19,276 14,352 Total derivative contracts $ 52,146 $ 44,171 $ 41,820 $ 61,274 Current $ 47,221 $ 19,839 $ 33,015 $ 31,441 Long-term 4,925 24,332 8,805 29,833 Total derivative contracts $ 52,146 $ 44,171 $ 41,820 $ 61,274 _______________ 1 Balance sheet classification: Current and Long-term Unrealized gain on derivative instruments. 2 Balance sheet classification: Current and Long-term Unrealized loss on derivative instruments. 3 All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the purchased gas adjustment (PGA) mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers. * Electric portfolio derivatives consist of electric generation fuel of 221.4 million One Million British Thermal Units (MMBtu) and purchased electricity of 4.4 million Megawatt Hours (MWhs) at March 31, 2021, and 212.2 million MMBtus and 6.6 million MWhs at December 31, 2020. It is the Company's policy to record all derivative transactions on a gross basis at the contract level without offsetting assets or liabilities. The Company generally enters into transactions using the following master agreements: WSPP, Inc. (WSPP) agreements, which standardize physical power contracts; International Swaps and Derivatives Association (ISDA) agreements, which standardize financial natural gas and electric contracts; and North American Energy Standards Board (NAESB) agreements, which standardize physical natural gas contracts. The Company believes that such agreements reduce credit risk exposure because such agreements provide for the netting and offsetting of monthly payments as well as the right of set-off in the event of counterparty default. The set-off provision can be used as a final settlement of accounts which extinguishes the mutual debts owed between the parties in exchange for a new net amount. For further details regarding the fair value of derivative instruments, see Note 5, "Fair Value Measurements," to the consolidated financial statements included in Item 1 of this report. The following tables present the potential effect of netting arrangements, including rights of set-off associated with the Company's derivative assets and liabilities: Puget Energy and At March 31, 2021 Gross Amount Recognized in the Statement of Financial Position 1 Gross Amounts Offset in the Statement of Financial Position Net of Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position (Dollars in Thousands) Commodity Contracts Cash Collateral Received/Posted Net Amount Assets: Energy derivative contracts $ 52,146 $ — $ 52,146 $ (21,105) $ — $ 31,041 Liabilities: Energy derivative contracts $ 44,171 $ — $ 44,171 $ (21,105) $ (143) $ 22,923 Puget Energy and At December 31, 2020 Gross Amount Recognized in the Statement of Financial Position 1 Gross Amounts Offset in the Statement of Financial Position Net of Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position (Dollars in Thousands) Commodity Contracts Cash Collateral Received/Posted Net Amount Assets: Energy derivative contracts $ 41,820 $ — $ 41,820 $ (21,696) $ — $ 20,124 Liabilities: Energy derivative contracts $ 61,274 $ — $ 61,274 $ (21,696) $ (9,343) $ 30,235 _______________ 1 All derivative contract deals are executed under ISDA, NAESB and WSPP master netting agreements with right of set-off. The following table presents the effect and classification of the realized and unrealized gains (losses) of the Company's derivatives recorded on the statements of income: Puget Energy and Three Months Ended (Dollars in Thousands) Classification 2021 2020 Gas for Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net $ 1,628 $ (9,755) Realized Electric generation fuel 8,313 1,296 Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net 21,374 (38,786) Realized Purchased electricity (13,303) (5,935) Total gain (loss) recognized in income on derivatives $ 18,012 $ (53,180) The Company is exposed to credit risk primarily through buying and selling electricity and natural gas to serve its customers. Credit risk is the potential loss resulting from a counterparty's non-performance under an agreement. The Company manages credit risk with policies and procedures for, among other things, counterparty credit analysis, exposure measurement, and exposure monitoring and mitigation. The Company monitors counterparties for significant swings in credit default swap rates, credit rating changes by external rating agencies, ownership changes or financial distress. Where deemed appropriate, the Company may request collateral or other security from its counterparties to mitigate potential credit default losses. Criteria employed in this decision include, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure. It is possible that volatility in energy commodity prices could cause the Company to have material credit risk exposure with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. However, as of March 31, 2021, approximately 99.2% of the Company's energy portfolio exposure, excluding normal purchase normal sale (NPNS) transactions, is with counterparties that are rated investment grade by rating agencies and 0.8% are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated by the major rating agencies. The Company computes credit reserves at a master agreement level by counterparty. The Company considers external credit ratings and market factors in the determination of reserves, such as credit default swaps and bond spreads. The Company recognizes that external ratings may not always reflect how a market participant perceives a counterparty's risk of default. The Company uses both default factors published by Standard & Poor's and factors derived through analysis of market risk, which reflect the application of an industry standard recovery rate. The Company selects a default factor by counterparty at an aggregate master agreement level based on a weighted average default tenor for that counterparty's deals. The default tenor is determined by weighting the fair value and contract tenors for all deals for each counterparty to derive an average value. The default factor used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels. The Company applies the counterparty's default factor to compute credit reserves for counterparties that are in a net asset position. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. Credit reserves are netted against the unrealized gain (loss) positions. The majority of the Company's derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. PSE also transacts power futures contracts on the Intercontinental Exchange (ICE), and natural gas contracts on the ICE NGX exchange platform. Execution of contracts on ICE requires the daily posting of margin calls as collateral through a futures and clearing agent. As of March 31, 2021, PSE had cash posted as collateral of $3.2 million related to contracts executed on the ICE platform. Also, as of March 31, 2021, PSE had $12.0 million in cash posted as collateral and a $1.0 million letter of credit posted as a condition of transacting on the ICE NGX platform. PSE did not trigger any collateral requirements with any of its counterparties nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades during the three months ended March 31, 2021. The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral the Company could be required to post: Puget Energy and (Dollars in Thousands) At March 31, 2021 At December 31, 2020 Fair Value 1 Posted Contingent Fair Value 1 Posted Contingent Contingent Feature Liability Collateral Collateral Liability Collateral Collateral Credit rating 2 $ 21,991 $ — $ 21,991 $ 26,966 $ — $ 26,966 Requested credit for adequate assurance 7,330 — — 6,576 — — Forward value of contract 3 143 11,990 N/A 9,343 20,903 N/A Total $ 29,464 $ 11,990 $ 21,991 $ 42,885 $ 20,903 $ 26,966 _______________ 1 Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes NPNS, accounts payable and accounts receivable. 2 Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to demand collateral. 3 . Collateral requirements may vary, based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds. |
Fair Value Measurements
Fair Value Measurements | 3 Months Ended |
Mar. 31, 2021 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Fair Value Measurements ASC 820 established a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy categorizes the inputs into three levels with the highest priority given to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority given to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows: Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities. Equity securities that are also classified as cash equivalents are considered Level 1 if there are unadjusted quoted prices in active markets for identical assets or liabilities. Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded derivatives such as over-the-counter forwards and options. Level 3 - Pricing inputs include significant inputs that have little or no observability as of the reporting date. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. Financial assets and liabilities measured at fair value are classified in their entirety in the appropriate fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The Company primarily determines fair value measurements classified as Level 2 or Level 3 using a combination of the income and market valuation approaches. The process of determining the fair values is the responsibility of the derivative accounting department which reports to the Controller and Principal Accounting Officer. Inputs used to estimate the fair value of forwards, swaps and options include market-price curves, contract terms and prices, credit-risk adjustments, and discount factors. Additionally, for options, the Black-Scholes option valuation model and implied market volatility curves are used. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs as substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. On a daily basis, the Company obtains quoted forward prices for the electric and natural gas markets from an independent external pricing service. The Company considers its electric and natural gas contracts as Level 2 derivative instruments as such contracts are commonly traded as over-the-counter forwards with indirectly observable price quotes. However, certain energy derivative instruments with maturity dates falling outside the range of observable price quotes are classified as Level 3 in the fair value hierarchy. Management's assessment is based on the trading activity in real-time and forward electric and natural gas markets. Each quarter, the Company confirms the validity of pricing-service quoted prices used to value Level 2 commodity contracts with the actual prices of commodity contracts entered into during the most recent quarter. Assets and Liabilities with Estimated Fair Value The carrying values of cash and cash equivalents, restricted cash, and short-term debt as reported on the balance sheet are reasonable estimates of their fair value due to the short-term nature of these instruments and are classified as Level 1 in the fair value hierarchy. The carrying value of other investments of $52.0 million and $52.7 million at March 31, 2021 and December 31, 2020 respectively, are included in "Other property and investments" on the balance sheet. These values are also reasonable estimates of their fair value and classified as Level 2 in the fair value hierarchy as they are valued based on market rates for similar transactions. The fair value of the long-term notes was estimated using the discounted cash flow method with the U.S. Treasury yields and the Company's credit spreads as inputs, interpolating to the maturity date of each issue. The carrying values and estimated fair values were as follows: Puget Energy March 31, 2021 December 31, 2020 (Dollars in Thousands) Level Carrying Fair Carrying Fair Liabilities: Long-term debt (fixed-rate), net of discount 1 2 $ 5,670,834 $ 7,063,347 $ 5,667,740 $ 7,755,946 Long-term debt (variable-rate) 2 233,500 233,500 224,700 224,700 Total liabilities $ 5,904,334 $ 7,296,847 $ 5,892,440 $ 7,980,646 Puget Sound Energy March 31, 2021 December 31, 2020 (Dollars in Thousands) Level Carrying Fair Carrying Fair Liabilities: Long-term debt (fixed-rate), net of discount 2 2 $ 4,338,523 $ 5,446,409 $ 4,338,044 $ 6,086,358 Total liabilities $ 4,338,523 $ 5,446,409 $ 4,338,044 $ 6,086,358 _______________ 1 The carrying value includes debt issuances costs of $21.9 million and $22.7 million for March 31, 2021 and December 31, 2020, respectively, which are not included in fair value. 2 The carrying value includes debt issuances costs of $22.6 million and $22.9 million for March 31, 2021 and December 31, 2020, respectively, which are not included in fair value. Assets and Liabilities Measured at Fair Value on a Recurring Basis The following table presents the Company's financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis: Puget Energy and Fair Value Fair Value (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Assets: Electric derivative instruments $ 31,980 $ 386 $ 32,366 $ 21,947 $ 597 $ 22,544 Natural gas derivative instruments 19,677 103 19,780 19,139 137 19,276 Total assets $ 51,657 $ 489 $ 52,146 $ 41,086 $ 734 $ 41,820 Liabilities: Electric derivative instruments $ 12,187 $ 21,556 $ 33,743 $ 22,607 $ 24,315 $ 46,922 Natural gas derivative instruments 8,491 1,937 10,428 13,080 1,272 14,352 Total liabilities $ 20,678 $ 23,493 $ 44,171 $ 35,687 $ 25,587 $ 61,274 The following table presents the Company's reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy: Puget Energy and Three Months Ended (Dollars in Thousands) 2021 2020 Level 3 Roll-Forward Net Asset/(Liability) Electric Natural Gas Total Electric Natural Gas Total Balance at beginning of period $ (23,718) $ (1,135) $ (24,853) $ (3,379) $ 1,282 $ (2,097) Changes during period: Realized and unrealized energy derivatives: Included in earnings 1 820 — 820 (24,552) — (24,552) Included in regulatory assets / liabilities — (888) (888) — 323 323 Settlements 1,728 189 1,917 1,626 (513) 1,113 Transferred into Level 3 — — — — — — Transferred out of Level 3 — — — — — — Balance at end of period $ (21,170) $ (1,834) $ (23,004) $ (26,305) $ 1,092 $ (25,213) _______________ 1 Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $0.8 million and zero for three months ended March 31, 2021 and 2020, respectively. Realized gains and losses on energy derivatives for Level 3 recurring items are included in energy costs in the Company's consolidated statements of income under purchased electricity, electric generation fuel or purchased natural gas when settled. Unrealized gains and losses on energy derivatives for Level 3 recurring items are included in net unrealized (gain) loss on derivative instruments in the Company's consolidated statements of income. The Company does not use internally developed models to make adjustments to significant unobservable pricing inputs. The only significant unobservable input into the fair value measurement of the Company's Level 3 assets and liabilities is the forward price for electric and natural gas contracts. The weighted average price is calculated as the total market value divided by the total volume of the Company's Level 3 electric and gas commodity contracts, respectively, as of the reporting date. The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of March 31, 2021 Puget Energy and Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Average Electric $ 386 $ 21,556 Discounted cash flow Power prices (per MWh) $ 22.87 $ 44.21 $ 32.56 Natural gas $ 103 $ 1,937 Discounted cash flow Natural gas prices (per MMBtu) $ 2.10 $ 3.57 $ 2.70 _______________ 1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions. The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of December 31, 2020: Puget Energy and Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Average Electric $ 597 $ 24,315 Discounted cash flow Power prices (per MWh) $ 22.82 $ 41.66 $ 31.54 Natural gas $ 137 $ 1,272 Discounted cash flow Natural gas prices (per MMBtu) $ 1.89 $ 3.42 $ 2.47 ___________ 1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions. The significant unobservable inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. Consequently, significant increases or decreases in the forward prices of electricity or natural gas in isolation would result in a significantly higher or lower fair value for Level 3 assets and liabilities. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets. As of March 31, 2021, and December 31, 2020, a hypothetical 10% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company's derivative portfolio, classified as Level 3 within the fair value hierarchy, by $4.9 million and $5.5 million, respectively. Long-Lived Assets Measured at Fair Value on a Nonrecurring Basis Puget Energy records the fair value of its intangible assets in accordance with ASC 360, “Property, Plant, and Equipment,” (ASC 360). The fair value assigned to the power contracts was determined using an income approach comparing the contract rate to the market rate for power over the remaining period of the contracts incorporating non-performance risk. Management also incorporated certain assumptions related to quantities and market presentation that it believes market participants would make in the valuation. The fair value of the power contracts is amortized as the contracts settle. ASC 360 requires long-lived assets to be tested for recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. One such triggering event is a significant decrease in the forward market prices of power. As of March 31, 2021, Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets and determined that no impairment was needed.. These intangible assets exist as a result of the merger in 2009, at which time the consolidated assets and liabilities were revalued in accordance with ASC 805, "Business Combinations". The following table presents the impairment recorded to the Company's intangible asset contracts in 2020, with corresponding reductions to the regulatory liability: Puget Energy (Dollars in Thousands) Valuation Date Contract Name Carrying Value Fair Value Write Down March 31, 2020 Rocky Reach $147,168 $94,603 $52,565 The valuations were measured using a discounted cash flow, income-based valuation methodology. Significant inputs included forward electricity prices and power contract pricing which provided future net cash flow estimates classified as Level 3 within the fair value hierarchy. The unobservable input averages disclosed below represent the arithmetic average of the inputs and are not weighted by volume. A less significant input is the discount rate reflective of a market participant's cost of capital used in the valuation. The following table presents the significant unobservable inputs used in estimating the impaired long-term power purchase contracts' fair value: Puget Energy Valuation Date Unobservable Input Low High Average March 31, 2020 Power prices (per MWh) $10.23 $29.05 $20.88 Power contract costs per quarter (in thousands) $6,308 $7,085 $6,468 |
Retirement Benefits
Retirement Benefits | 3 Months Ended |
Mar. 31, 2021 | |
Subsidiaries [Member] | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Pension and Other Postretirement Benefits Disclosure [Text Block] | Retirement Benefits PSE has a defined benefit pension plan (Qualified Pension Benefits) covering a substantial majority of PSE employees. Pension benefits earned are a function of age, salary, years of service and, in the case of employees in the cash balance formula plan, the applicable annual interest crediting rates. Starting January 1, 2014, all the United Association of Plumbers and Pipefitters (UA) represented employees receive annual pay contributions of 4.0% of eligible pay each year in the cash balance formula plan of the defined benefit pension. Starting January 1, 2014, for non-represented employees, and December 12, 2014, for employees represented by the International Brotherhood of Electrical Workers Union (IBEW), participants receive annual employer contributions of 4.0% of eligible pay each year in the cash balance formula of the defined benefit pension or 401k plan account. Those employees receiving contributions in the cash balance formula plan also receive interest credits, which are at least 1.0% per quarter. When an employee with a vested cash balance formula benefit leaves PSE, they will have annuity and lump sum options for distribution. PSE also has a non-qualified Supplemental Executive Retirement Plan (SERP) for certain key senior management employees that closed to new participants in 2019. PSE has an officer restoration benefit for new officers who join PSE or are promoted beginning in 2019, such that company contributions under PSE’s applicable tax-qualified plan, which otherwise would have been earned if not for IRS limitations, are credited to an account with the Deferred Compensation Plan. In addition to providing pension benefits, PSE provides legacy group health care and life insurance benefits (Plan) for certain retired employees. These benefits are provided principally through an insurance company. The insurance premiums, paid primarily by retirees, are based on the benefits provided during the prior year. On June 11, 2019, the Welfare Benefits Committee approved the termination of the Plan effective December 31, 2019, and the creation of a Retiree Health Reimbursement Account (HRA) Plan effective January 1, 2020. No eligible individual may become a participant or covered dependent in the Plan on or after January 1, 2020, and no benefits will be payable under insurance contracts or the Plan on or after January 1, 2020. Effective January 1, 2020, assets in the 401(h) account will be allocated to the Retiree HRA instead of the Plan to cover the Company's portion of premiums for health benefits for retiree and their beneficiaries. Puget Energy's retirement plans were remeasured as a result of the merger in 2009, which represents the difference between Puget Energy and PSE's retirement plans. In 2017, the FASB issued ASU 2017-07, requiring that an employer report the service cost component in the same line items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost (which include interest costs, expected return on plan assets, amortization of prior service cost or credits and actuarial gains and losses) are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. Pursuant to the standard, the Company has retrospectively included in the consolidated statements of income: (i) the components of service cost within utility operations and maintenance for PSE and within non-utility expense and other for Puget Energy, and (ii) all non-service cost components in other income. The following tables summarize the Company’s net periodic benefit cost for the three months ended March 31, 2021 and 2020: Puget Energy Qualified SERP Other Three Months Ended March 31, (Dollars in Thousands) 2021 2020 2021 2020 2021 2020 Components of net periodic benefit cost: Service cost $ 6,711 $ 5,997 $ 115 $ 228 $ 41 $ 49 Interest cost 5,578 6,298 293 378 77 91 Expected return on plan assets (12,081) (12,502) — — (91) (97) Amortization of prior service cost (476) (495) 87 87 2 — Amortization of net loss (gain) 2,830 1,981 587 586 (10) (22) Net periodic benefit cost $ 2,562 $ 1,279 $ 1,082 $ 1,279 $ 19 $ 21 Puget Sound Energy Qualified SERP Other Three Months Ended March 31, (Dollars in Thousands) 2021 2020 2021 2020 2021 2020 Components of net periodic benefit cost: Service cost $ 6,711 $ 5,997 $ 115 $ 228 $ 41 $ 49 Interest cost 5,578 6,298 293 378 77 91 Expected return on plan assets (12,081) (12,504) — — (91) (97) Amortization of prior service cost (378) (393) 87 87 2 — Amortization of net loss (gain) 5,311 4,656 635 659 (15) (36) Net periodic benefit cost $ 5,141 $ 4,054 $ 1,130 $ 1,352 $ 14 $ 7 The following table summarizes the Company’s change in benefit obligation for the periods ended March 31, 2021 and December 31, 2020: Puget Energy and Qualified SERP Other Three Months Ended Year Ended Three Months Ended Year Ended Three Months Ended Year Ended (Dollars in Thousands) March 31, December 31, March 31, December 31, March 31, December 31, Change in benefit obligation: Benefit obligation at beginning of period $ 849,383 $ 774,305 $ 46,742 $ 63,000 $ 12,114 $ 11,627 Amendments — — — — — 44 Service cost 6,711 24,337 115 756 41 190 Interest cost 5,578 25,180 293 1,464 77 368 Curtailment Loss / (Gain) — — — — — — Actuarial loss (gain) — 69,413 — 3,663 — 604 Benefits paid (11,625) (42,775) (496) (22,141) (237) (906) Medicare part D subsidy received — — — — 196 187 Administrative Expense — (1,077) — — — — Benefit obligation at end of period $ 850,047 $ 849,383 $ 46,654 $ 46,742 $ 12,191 $ 12,114 The aggregate expected contributions by the Company to fund the qualified pension plan, SERP and the other postretirement plans for the year ending December 31, 2021, are expected to be at least $18.0 million, $6.8 million and $0.3 million, respectively. During the three months ended March 31, 2021, the Company contributed $0.5 million to fund the SERP. During the three months ended March 31, 2020, the Company contributed $13.6 million to fund the SERP. The Company contributed an immaterial amount to fund the other postretirement plans. |
Regulation and Rates
Regulation and Rates | 3 Months Ended |
Mar. 31, 2021 | |
Subsidiaries [Member] | |
Entity Information [Line Items] | |
Regulation and Rates Disclosure | Regulation and Rates Power Cost Only Rate Case On December 9, 2020, PSE filed its 2020 power cost only rate case (PCORC). The filing proposed an increase of $78.5 million (or an average of approximately 3.7%) in the Company's overall power supply costs with an anticipated effective date in June 2021. On February 2, 2021, PSE supplemented the PCORC to update its power costs, leading to a requested increase from $78.5 million to $88.0 million (or an average of approximately 4.1%). On March 2, 2021, the parties to the PCORC reached a multiparty settlement in principle, with Public Counsel not joining the settlement, but also not opposing. The settlement agreement and supporting testimony was filed with the Washington Commission on April 2, 2021, who held hearings on the matter on April 22, 2021. The settlement resulted in an estimated revenue increase of $65.3 million or 3.1% and, pending approval by the Washington Commission, is expected to be effective June 2021. General Rate Case PSE filed a general rate case (GRC) with the Washington Commission on June 20, 2019 requesting an overall increase in electric and natural gas rates of 6.9% and 7.9% respectively. PSE requested a return on equity of 9.8% with an overall rate of return of 7.62%. In addition to the traditional areas of focus (revenue requirements, cost allocation, rate design and cost of capital), the Company completed an attrition study and included a portion of the attrition revenue requirement in the overall request in order address the expected regulatory lag in the rate year. Additionally, as the non-plant related excess deferred taxes that resulted from the Tax Cuts and Jobs Act (TCJA) remained outstanding from PSE’s Expedited Rate Filing (ERF) as discussed below, PSE requested in its GRC to pass back the amounts over four years. On September 17, 2019, PSE filed a supplemental filing in the GRC, which provided updates as discussed in the original filing, but did not impact the requested overall electric and natural gas rate increases, return on equity or overall rate of return as originally filed. On January 15, 2020, PSE filed rebuttal testimony that included a reduction to the requested return on equity to 9.5%, which decreased the rate of return to 7.48%. The requested rate increase for both electric and natural gas remained at 6.9% and 7.9%, respectively. For both electric and natural gas, PSE did not originally request its full attrition adjustment; therefore, the decrease in return on equity led to a reduction in the electric rate increase of only $1.5 million and did not have an impact on the natural gas rate increase. On July 8, 2020, the Washington Commission issued its order on PSE’s GRC. The ruling provided for a weighted cost of capital of 7.39% or 6.8% after-tax, and a capital structure of 48.5% in common equity with a return on equity of 9.4%. The order also resulted in a combined net increase to electric of $29.5 million, or 1.6%, and to natural gas of $36.5 million, or 4.0%. However, the Washington Commission extended the amortization of certain regulatory assets, PSE’s electric decoupling deferral, and PSE’s PGA deferral to mitigate the impact of the rate increase in response to the economic instability created by the COVID-19 pandemic, which reduced the electric revenue increase to approximately $0.9 million, or 0.05%, and the natural gas increase to $1.3 million, or 0.15%. The Washington Commission also determined that the Company’s proposed attrition adjustment of $23.9 million for electric and $16.2 million for natural gas was not in the public interest at this time. The order also effectively ends the deferral of depreciation expense associated with PSE’s advanced metering infrastructure (AMI) investment while allowing the deferral on the return on AMI investments through December 31, 2019. Additional AMI investments will be evaluated in future proceedings for deferrals of return until the AMI project is complete. On July 17, 2020, PSE filed a motion for clarification with the Washington Commission seeking clarification on several items. On July 31, 2020, the Washington Commission issued an order granting PSE’s motion for clarification. The ruling adjusted certain items from the final order issued on July 8, 2020, which led to a combined net increase to electric of $59.6 million, or 2.9%, an increase of $30.1 million above the $29.5 million granted in the final order. The order also led to a combined net increase to natural gas of $42.9 million, or 5.6%, an increase of $6.4 million above the $36.5 million granted in the final order. The Washington Commission maintained adjustments which mitigated the impacts of the rate increases in response to the economic instability created by the COVID-19 pandemic, which reduced the electric revenue increase to approximately $27.7 million, or 1.3%, and the natural gas increase to $0.2 million, or 0.02%. On August 6, 2020, PSE filed a petition for judicial review with the Superior Court of the State of Washington for King County (Superior Court) challenging the portion of the final order that requires PSE to pass back to customers the reversal of plant-related excess deferred income taxes in a manner that may deviate from the Internal Revenue Service (IRS) normalization and consistency rules. On August 7, 2020, PSE filed a motion to stay with the Superior Court related to the portions of the final order under judicial review. On September 14, 2020, the Superior Court denied PSE's motion to stay. PSE reviewed the original Washington Commission order including the ramifications of certain tax issues and requested a Private Letter Ruling (PLR) with the IRS regarding this matter. PSE will continue to utilize the average rate assumption method (ARAM) in the turnaround of certain accelerated tax depreciation benefits on PSE assets. On September 23, 2020, PSE filed a compliance filing with the Washington Commission. The natural gas tariffs became effective October 1, 2020 and the electric tariffs on October 15, 2020. On October 7, 2020, PSE, the Washington Commission and interveners agreed to dismiss the petition for judicial review. The agreement is based on a commitment from the Washington Commission that if the IRS ruling finds that the Washington Commission’s methodology for reversing plant-related excess deferred income taxes is impermissible, the Washington Commission will open a proceeding to review and enact the changes required by the IRS ruling. There is approximately $25.6 million in annual revenue requirement related to the 2019 GRC which PSE has requested it be allowed to track in order to allow the Washington Commission to decide if it is appropriate for PSE to recover, pending the outcome of the IRS ruling. Expedited Rate Filing On November 7, 2018, PSE filed an ERF with the Washington Commission. The filing requested to change rates associated with PSE’s delivery and fixed production costs. It did not include variable power costs, purchased gas costs or natural gas pipeline replacement program costs, which are recovered in separate mechanisms. The filing was based on historical test year costs and rate base, and followed the reporting requirements of a Commission Basis Report, as defined by the Washington Administrative Code, but used end of period rate base and certain annualizing adjustments. It did not include any forward-looking or pro-forma adjustments. Included in the filing was a reduction to the overall authorized rate of return from 7.6% to 7.49% to recognize a reduction in debt costs associated with recent debt activity. PSE requested an overall increase in electric rates of $18.9 million annually, which is a 0.9% increase, and an overall increase in natural gas rates of $21.7 million annually, which is a 2.7% increase. On January 22, 2019, all parties in the proceeding reached an agreement on settlement terms that resolved all issues in the filing. The settlement agreement was filed on January 30, 2019. The parties agreed to a $21.5 million rate increase for natural gas and no rate increase for electric which became effective March 1, 2019. As is discussed below, these rates include the offsetting effect of passing back to customers plant related excess deferred income taxes that resulted from the TCJA, using the average rate assumption method (ARAM) amounts to arrive at the settlement rate changes. The settlement agreement provides for the pass back of plant related excess deferred income taxes that resulted from the TCJA using the ARAM methodology based on 2018 amounts beginning March 1, 2019, in the amount of $6.1 million for natural gas customers and $25.9 million for electric customers. The settlement agreement left the determination for the regulatory treatment of the remaining items related to the TCJA, listed below, to PSE’s then-next GRC, filed June 20, 2019, and discussed above: 1) excess deferred taxes for non-plant-related book/tax differences for periods prior to March 1, 2019; 2) the deferred balance associated with the over-collection of income tax expense for the period January 1 through April 30, 2018, (the time period that encompasses the effective date of the TCJA to May 1, 2018, the effective date of the TCJA rate change); and 3) the turnaround of plant related excess deferred income taxes using the ARAM method for the period from January 2018 through February 2019, the rate effective date for the ERF. The settlement agreement provides that PSE may defer the depreciation expense associated with PSE’s ongoing investment in its AMI investment and may defer the return on the AMI investment that was included in the test year of the filing. As noted above, the 2019 GRC effectively ends all deferrals of AMI depreciation expense and deferrals of return on additional AMI investments will be evaluated in future proceedings. The rate of return adopted in the settlement for reporting and deferral purposes is 7.49%. On February 21, 2019, the Washington Commission approved the settlement with one condition: PSE passed back the deferred balance associated with the tax over-collection of $34.6 million for the period from January 1, 2018, through April 30, 2018, over a one-year period which ended May 1, 2020. Washington Commission Tax Deferral Filing The TCJA was signed into law in December 2017. As a result of this change, PSE re-measured its deferred tax balances under the new corporate tax rate. PSE filed an accounting petition on December 29, 2017, requesting deferred accounting treatment for the impacts of tax reform. The requested deferral accounting treatment resulted in the tax rate change being captured in the deferred income tax balance with an offset to the regulatory liability for deferred income taxes for GAAP purposes. Additionally, on March 30, 2018, PSE filed for a rate change for electric and natural gas customers associated with TCJA to reflect the decrease in the federal corporate income tax rate from 35.0% to 21.0%. The overall impact of the rate change, based on the annual period from May 2018 through April 2019, is a revenue decrease of $72.9 million, or 3.4% for electric and $23.6 million, or 2.7% for natural gas and became effective May 1, 2018, by operation of law. The March 30, 2018, rate change filing did not address excess deferred taxes or the deferred balance associated with the over-collection of income tax expense of $34.6 million for the period January 1 through April 30, 2018, (the time period that encompasses the effective date of the TCJA through May 1, 2018, the effective date of the rate change). The $34.6 million tax over-collection decreased PSE's revenue and increased the regulatory liability for a refund to customers. While the settlement agreement in the ERF provides for the pass back of plant related excess deferred income taxes that resulted from the TCJA using the ARAM methodology based on 2018 amounts through the PSE Schedule 141X tariff, the ongoing treatment of excess deferred taxes associated with non-plant-related book/tax differences and the treatment of the excess deferred taxes associated with plant related book/tax differences was left to be addressed in PSE’s GRC, which was filed on June 20, 2019. The Washington Commission also required in the ERF order that PSE pass back the deferred balance associated with the tax over-collection for the period from January 1, 2018, through April 30, 2018, as discussed above, over a one-year period which began May 1, 2019. Per PSE’s Schedule 141Y tariff, following the May 2019 through April 2020 refund period, if the residual balance of credit owed to customers will be greater than $0.1 million, PSE would submit a filing no later than July 31, 2020 with a proposal of passing back the residual balance effective September 1, 2020 through August 31, 2021. As this balance was greater than $0.1 million, PSE filed tariff revisions on July 20, 2020 and the Washington Commission approved the filing on August 27, 2020. Finally, the GRC final order determined that PSE is required to pass back 2019 and 2020 protected excess deferred tax reversals totaling $70.8 million over the 12 months following the rate effective period through PSE’s Schedule 141X tariff. The GRC final order also determined that PSE is required to pass back unprotected excess deferred tax balances totaling $38.9 million over 36 months following the rate effective period through PSE’s Schedule 141Z tariff. Further details of the outcome associated with PSE’s tax deferral filing are discussed in the ERF and GRC disclosures. Decoupling Filings While fluctuations in weather conditions will continue to affect PSE's billed revenue and energy supply expenses from month to month, PSE's decoupling mechanisms assist in mitigating the impact of weather on operating revenue and net income. Since 2013, the Washington Commission has allowed PSE to record a monthly adjustment to its electric and natural gas operating revenues related to electric transmission and distribution, natural gas operations and general administrative costs from most residential, commercial and industrial customers to mitigate the effects of abnormal weather, conservation impacts and changes in usage patterns per customer. As a result, these electric and natural gas revenues are recovered on a per customer basis regardless of actual consumption levels. PSE's energy supply costs, which are part of the PCA and PGA mechanisms, are not included in the decoupling mechanism. The revenue recorded under the decoupling mechanisms will be affected by customer growth and not actual consumption. Following each calendar year, PSE will recover from, or refund to, customers the difference between allowed decoupling revenue and the corresponding actual revenue during the following May to April time period. On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 GRC to extend the decoupling mechanism with several changes to the methodology that took effect on December 19, 2017. Electric and natural gas delivery revenues continue to be recovered on a per customer basis and electric fixed production energy costs are now decoupled and recovered on the basis of a fixed monthly amount. The allowed decoupling revenue for electric and natural gas customers will no longer increase annually each January 1 as occurred prior to December 19, 2017. Approved revenue per customer costs can only be changed in a GRC or ERF. Approved electric fixed production energy costs can only be changed in a GRC or a power cost only rate case. Other changes to the decoupling methodology approved by the Washington Commission include regrouping of electric and natural gas non-residential customers and the exclusion of certain electric schedules from the decoupling mechanism going forward. The rate test, which limits the amount of revenues PSE can collect in its annual filings, increased from 3.0% to 5.0% for natural gas customers but will remain at 3.0% for electric customers. The decoupling mechanism will be reviewed again in PSE’s first rate case filed in or after 2021, or in a separate proceeding, if appropriate. PSE’s decoupling mechanism over- and under- collections will still be collectible or refundable after this effective date even if the decoupling mechanism is not extended. On February 21, 2019, the Washington Commission approved the multi-party settlement agreement which was filed within PSE’s ERF filing. As part of this settlement agreement, electric and natural gas allowed delivery revenue per customer was updated to reflect changes in the approved revenue requirement. For electric, there were no changes to the annual allowed fixed power cost revenue. The changes took effect on March 1, 2019. On July 8, 2020, the Washington Commission issued the final order in Dockets UE-190529 and UG-190530, which instructed PSE to extend the collection of amortization balances for electric decoupling delivery and fixed power cost sections originally filed through the annual May 2020 decoupling filing. The extension requires PSE to move amortization balances as of August 31, 2020 of about $16.0 million for electric delivery and fixed power cost decoupling to be collected from customers for a two-year period, instead of the originally approved one-year period. Additionally, through approving the electric cost of service, the final order approved the re-allocation of decoupling balances from Schedule 40 to the remaining electric decoupling groups. On December 23, 2020, the Washington Commission approved PSE’s filing to update Schedule 142 decoupling amortization rates, with an effective date of January 1, 2021, by zeroing out rates still effective past October 15, 2020 on tariff sheet Schedule 142-H, which was replaced by rates on tariff sheet Schedule 142-I effective October 15, 2020. As part of this filing, PSE will true up the over-collection amounts for the period of October 15, 2020 through December 31, 2020 in PSE’s annual May 2021 decoupling filing. On March 31, 2021, PSE performed an analysis to determine if electric and natural gas decoupling revenue deferrals would be collected from customers within 24 months of the annual period, per ASC 980. If not, for GAAP purposes only, PSE would need to record a reserve against the decoupling revenue and corresponding regulatory asset balance. Once the reserve is probable of collection within 24 months from the end of the annual period, the reserve can be recognized as decoupling revenue. The analysis indicated that $0.9 million of electric deferred revenue will not be collected within 24 months of the annual period; therefore a reserve adjustment was booked to 2021 electric decoupling revenue. Natural gas deferred revenue will be collected within 24 months of the annual period; therefore, no reserve adjustment was booked to 2021 natural gas decoupling revenue. Power Cost Adjustment Mechanism PSE currently has a PCA mechanism that provides for the deferral of power costs that vary from the “power cost baseline” level of power costs. The “power cost baseline” levels are set, in part, based on normalized assumptions about weather and hydroelectric conditions. Excess power costs or savings are apportioned between PSE and its customers pursuant to the graduated scale set forth in the PCA mechanism and will trigger a surcharge or refund when the cumulative deferral trigger is reached. Effective January 1, 2017, the following graduated scale is used in the PCA mechanism: Company’s Share Customers' Share Annual Power Cost Variability Over Under Over Under Over or Under Collected by up to $17 million 100 % 100 % — % — % Over or Under Collected by between $17 million - $40 million 35 50 65 50 Over or Under Collected beyond $40 + million 10 10 90 90 For the three months ended March 31, 2021, in its PCA mechanism, PSE under recovered its allowable costs by $11.4 million of which zero was apportioned to customers and $0.3 million of interest was accrued on the deferred customer balance. This compares to an under recovery of allowable costs of $25.1 million for the three months ended March 31, 2020, of which $4.0 million was apportioned to customers and accrued $0.5 million of interest on the total deferred customer balance. Power Cost Adjustment Clause Filing On July 1, 2019, PSE updated its Schedule 95 rates in the Power Cost Adjustment Clause tariff to reflect the transition fee as required by Section 12 of the Microsoft Special Contract. Additionally, Schedule 95 rates also include portions of fixed power cost adjustments per the allowed decoupling rate re-allocation effective April 1, 2019, resulting from Microsoft becoming a transportation customer as well as small variable power cost adjustments. On July 8, 2020, the Washington Commission issued the final order in Dockets UE-190529 and UG-190530, which instructed PSE to remove Schedule 95 collection on decoupling allowed rates for Microsoft Special Contracts, which will be included in allowed rates under the Decoupling Schedule 142 effective October 15, 2020. PSE exceeded the $20.0 million cumulative deferral balance in its PCA mechanism in 2019. The surcharging of deferrals can be triggered by the Company when the balance in the deferral account is a credit of $20.0 million or more. Due to concerns about the economic impact of the COVID-19 pandemic on customers, PSE voluntarily, with Washington Commission Staff support, delayed filing an increase to its Schedule 95 rates in its annual PCA report filing in Docket UE-200398, which was approved on July 30, 2020. Subsequently, PSE filed to recover the deferred balance in Docket UE-200893, effective December 1, 2020, and the Washington Commission approved PSE’s request on November 24, 2020. During 2019, actual power costs were higher than baseline power costs, thereby creating an under-recovery of $67.2 million. Under the terms of the PCA’s sharing mechanism for under-recovered power costs, PSE absorbed $31.2 million of the under-recovered amount, and customers were responsible for the remaining $36.0 million, or $37.0 million including interest. As PSE had an approved balance owing from customers including interest at the start of 2019 totaling $4.7 million, the approved cumulative deferral balance for the PCA, as of December 2019, is $41.7 million. As previously stated, this filing is set to collect the customer’s share of the cumulative 2019 imbalance in PSE’s PCA mechanism. Purchased Gas Adjustment Mechanism On April 25, 2019, the Washington Commission approved PSE’s request for an out-of-cycle change to PGA rates with the rate change taking effect May 1, 2019. The out-of-cycle PGA filing was needed to begin amortizing a large PGA commodity deferral balance that had grown due to higher than projected commodity costs during the 2018/19 winter. These higher than projected commodity costs were primarily due to an October 9, 2018, rupture and subsequent explosion on Westcoast Pipeline which is one of the major pipelines feeding PSE’s distribution system. The pipeline was repaired in October 2018, however supply capacity on the pipeline was limited over the 2018/19 winter leading to higher prices. February weather was also much colder than normal which also increased the demand for natural gas. The out-of-cycle PGA rates were effective from May 1, 2019 through April 30, 2020 and on May 1, 2020 the rates were set to zero. At the end of the recovery period, an unamortized balance of $4.9 million remained which PSE requested to be amortized in its annual PGA filing for rates effective November 1, 2020. On October 24, 2019, the Washington Commission approved PSE’s request for PGA rates, with the rate change taking effect on November 1, 2019. As part of that filing, PSE requested PGA rates increase annual revenue by $17.8 million, while the new tracker rates increased by annual revenue of $100.6 million; this was in addition to continuing the collection on the remaining balance of $54.0 million from the out-of-cycle PGA. The tracker rates include deferral balances for the three separate amounts: (i) $114.4 million of under collected commodity balances deferred in February and March; (ii) a $10.8 million balance of over-collected commodity costs for the PGA rates effective November 1, 2018; and (iii) a $4.1 million remaining balance from the $54.7 million credit to customers, caused by the 2017 over-collection, established in the 2018 tracker. The high commodity deferral balances for winter months through March 2019 were the result of three noteworthy events that winter experienced by PSE: the rupture of a pipeline owned by Enbridge, Inc. in October 2018, unusually low temperatures in February and March, and a compressor failure in February at the Jackson Prairie storage facility. Additionally, to reduce customer impact, as part of the approved PGA filing, PSE will be collecting $114.4 million commodity deferrals and related interest over a two-year period, instead of the historic one-year period, from November 2019 through October 2021. On July 8, 2020, the Washington Commission issued the final order in Dockets UE-190529 and UG-190530, which instructed PSE to extend the collection of amortization balances for the portion of PGA amortization balances originally filed through the annual November 1, 2019 PGA filing under the Supplemental Schedule 106B. The extension requires PSE to move amortization balances for PGA Schedule 106B as of August 31, 2020 to be collected from customers for a three-year period, instead of the originally approved two-year period. On October 29, 2020, the Washington Commission approved PSE’s request for November 2020 PGA rates in Docket UG-200832, effective November 1, 2020. As part of that filing, PSE requested PGA rates increase annual revenue by $32.6 million, while the new tracker rates increased annual revenue by $37.4 million; this was in addition to continuing the collection on the remaining balance of $69.4 million under Supplemental Schedule 106B. The following table presents the PGA mechanism balances and activity at March 31, 2021 and December 31, 2020: (Dollars in Thousands) At March 31, At December 31, PGA receivable balance and activity 2021 2020 PGA receivable beginning balance $ 87,655 $ 132,766 Actual natural gas costs 113,175 314,792 Allowed PGA recovery (154,592) (363,886) Interest 549 3,983 PGA receivable ending balance $ 46,787 $ 87,655 Get to Zero Depreciation Deferral On April 10, 2019, PSE filed an accounting petition with the Washington Commission, requesting authorization to defer depreciation expense associated with Get to Zero (GTZ) projects that were placed in service after June 30, 2018. The GTZ project consists of a number of short-lived technology upgrades. The depreciation expense associated with the GTZ projects with lives of 10 years or less that were placed in service after June 30, 2018, were deferred beginning May 1 per the petition request. For the period ended March 31, 2021 and December 31, 2020, PSE deferred $4.6 million and $2.8 million of depreciation expense for GTZ, respectively. In addition to the deferral of depreciation expense, PSE had also requested to defer carrying charges on the GTZ deferral, to be calculated utilizing the Company’s currently authorized after tax rate of return, or 6.89% per the 2018 ERF. The GTZ accounting petition was consolidated with PSE’s 2019 GRC and on July 8, 2020, the Washington Commission issued its order in PSE’s 2019 GRC. The ruling authorized PSE to amortize deferred GTZ expenses as proposed in the original GRC filing. The ruling also allows continued deferral of the depreciation expense associated with GTZ investments not already approved for recovery with a book life of 10 years or less, through PSE's next GRC. Finally, the final order set the rate at which PSE could defer and recover carrying charges from PSE’s authorized rate of return to the quarterly interest rate established by the FERC. Crisis Affected Customer Assistance Program On April 6, 2020, PSE filed with the Washington Commission revisions to its currently effective Tariff WN U-60. The purpose of this filing is to incorporate into PSE’s low-income tariff a new temporary bill assistance program, Crisis Affected Customer Assistance Program (CACAP), to mitigate the economic impact of the COVID-19 pandemic on PSE’s customers. CACAP would allow PSE customers facing financial hardship due to COVID-19 to receive up to $1,000 in bill assistance. The program puts to immediate use $11.0 million in unspent low income funds from prior years, and supplements other forms of financial assistance. The program does not require an increase to rates and is fully compatible with other low income programs. Based on the COVID-19 pandemic and resulting state of emergency, the Washington Commission allowed the tariff revisions to become effective on April 13, 2020. PSE made an additional filing on July 21, 2020 to increase the amount of electric funds available for distribution by $4.5 million under the CACAP program. The program ended on September 30, 2020. On March 28, 2021 the Washington Commission approved PSE’s second Crisis Affected Customer Assistance Program (CACAP-2), effective April 12, 2021. CACAP-2 will provide up to $2,500 in bill assistance for each qualifying low-income household, per program year, with a total program budget of $20.0 million for electric customers and $7.7 million for natural gas customers. Storm Damage Deferral Accounting |
Commitments and Contingencies
Commitments and Contingencies | 3 Months Ended |
Mar. 31, 2021 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Colstrip PSE has a 50% ownership interest in Colstrip Units 1 and 2 and a 25% interest in each of Colstrip Units 3 and 4, which are coal-fired generating units located in Colstrip, Montana. In March 2013, the Sierra Club and the Montana Environmental Information Center filed a Clean Air Act citizen suit against all Colstrip owners in the U.S. District Court, District of Montana. In July 2016, PSE reached a settlement with the Sierra Club to dismiss all of the Clean Air Act allegations against the Colstrip Generating Station, which was approved by the court in September 2016. As part of the settlement that was signed by all Colstrip owners, Colstrip 1 and 2 owners, PSE and the operator of Colstrip, Talen Energy Corporation (Talen), agreed to retire the two oldest units (Units 1 and 2) at Colstrip in eastern Montana no later than July 1, 2022. Depreciation rates were updated in the GRC effective December 19, 2017, where PSE's depreciation increased for Colstrip Units 1 and 2 to recover plant costs to the expected shutdown date. Additionally, PSE has accelerated the depreciation of Colstrip Units 3 and 4, per the terms of the GRC settlement, to December 31, 2027. The GRC also repurposed PTCs and hydro-related treasury grants to recover unrecovered plant costs and to fund and recover decommissioning and remediation costs for Colstrip Units 1 through 4. Consistent with a June 2019 announcement, Talen permanently shut down Units 1 and 2 at the end of 2019 due to operational losses associated with the Units. Colstrip Units 1 and 2 were retired effective December 31, 2019. The Washington Clean Energy Transition Act requires the Washington Commission to provide recovery of the investment, decommissioning, and remediation costs associated with the facilities that are not recovered through the repurposed PTCs and hydro-related treasury grants. The full scope of decommissioning activities and costs may vary from the estimates that are available at this time. On December 10, 2019, PSE announced its intention to sell its interest in Colstrip Unit 4 to NorthWestern Energy for $1. Under this agreement, PSE would have retained its obligation to fund 25% of the environmental remediation and decommissioning costs associated with Unit 4 during PSE's ownership. The proposed agreement was subject to approval by the Washington Commission and the Montana Public Service Commission. Additionally, PSE had agreed to enter into a power purchase agreement with NorthWestern Energy for 90 MW through 2025 to facilitate the transition, and sell a portion of its dedicated Colstrip transmission system, conditioned upon regulatory approval. On August 14, 2020, an amendment to the agreement was executed selling a portion of PSE’s interest in Colstrip Unit 4 to Talen, in addition to NorthWestern Energy. However, after evaluating the likelihood of the regulatory approval process in both Washington and Montana, on October 29, 2020, PSE, NorthWestern Energy, and Talen mutually agreed to terminate the proposed sales agreement and the proposed power purchase agreement and relieve all claims against one another arising out of or relating to the sale agreement. The termination of the proposed sale and proposed PPA resulted in the withdrawal of PSE's filing with the Washington Commission. Colstrip Unit 4 is classified as Electric Utility Plant on the balance sheet, see Note 6, "Utility Plant," to the consolidated financial statements in the Company's most recent Annual Report on Form 10-K for the year ended December 31, 2020. Other Commitments and Contingencies In addition to the contractual obligations and consolidated commercial commitments disclosed in the Company's Annual Report on Form 10-K for the year ended December 31, 2020, during the three months ended March 31, 2021, the Company entered into new Electric Portfolio and Electric Wholesale Market Transaction contracts with estimated payment obligations totaling $777.4 million through 2042. For further information, see Note 16, "Commitments and Contingencies" to the consolidated financial statements included in Item 8 of the Company's Form 10-K for the period ended December 31, 2020. COVID-19 The outbreak of the Coronavirus Disease 2019 (COVID-19) has become a global pandemic. The Company is monitoring the impact of the pandemic and taking steps to mitigate known risks. The full impact on the Company's business from the pandemic, including governmental and regulatory response actions, is unknown at this time and difficult to predict. The Company provides a critical and essential service to its customers and the health and safety of its employees and customers is its first priority. The Company is continuously monitoring its supply chain and is working closely with essential vendors to understand the impact of COVID-19 to its business and does not currently expect service disruptions. Government mandated stay at home orders and private work from home mandates due to COVID-19 have affected electric and gas loads for residential, commercial, and industrial customers. During the quarter ended March 31, 2021, the Company delivered marginally higher electric and decreased natural gas loads of 0.1% and 3.7%, respectively, when comparing weather-adjusted actual to forecast. Decreases in commercial and industrial loads were partially offset by increases in residential loads. Electric retail revenue marginal increases included reduced electric supply costs and the effects of decoupling. The impact on natural gas revenue due to load was offset by gas supply cost and decoupling. The Company anticipates that electric and gas loads will continue to be impacted for the remainder of 2021, due to continued work place lock downs, work at home mandates, other government mandated quarantines, economic recession, and resurgence of the COVID-19 virus. At the date of this report, the Company is effectively managing operations during the pandemic in order to continue to provide critical service to its customers. The Company has flexibility with capital investments and other measures to maintain sufficient liquidity over the next twelve months. The situation remains fluid and future impacts to the Company that are presently unknown or unanticipated may occur. Furthermore, the severity of impact to the Company could increase the longer the global pandemic persists. On September 3, 2020, the Company filed an accounting petition with the Washington Commission, requesting authorization to defer the costs and foregone revenue net of offsets associated with the COVID-19 public health emergency. On November 6, 2020, PSE filed a revised petition which was approved on December 10, 2020 by the Washington Commission granting PSE's accounting petition in part by allowing the deferral of COVID-19 incremental costs and foregone revenue net of offsets. As of March 31, 2021, PSE deferred no costs related to this petition specific to COVID-19. |
Leases (Notes)
Leases (Notes) | 3 Months Ended |
Mar. 31, 2021 | |
Leases [Abstract] | |
Leases | Leases Other than the item discussed below, there have been no significant changes regarding the Company's leases as described in Note 9 in the Company’s Annual Report on Form 10-K for the year ended December 31, 2020. During the first quarter of 2021, mechanical completion was achieved for the Puget LNG facility which triggered an increase in the lease payments for the Port of Tacoma lease. This remeasurement resulted in an increase of the operating lease ROU asset and operating lease liabilities of $26.3 million. |
Leases | Leases Other than the item discussed below, there have been no significant changes regarding the Company's leases as described in Note 9 in the Company’s Annual Report on Form 10-K for the year ended December 31, 2020. During the first quarter of 2021, mechanical completion was achieved for the Puget LNG facility which triggered an increase in the lease payments for the Port of Tacoma lease. This remeasurement resulted in an increase of the operating lease ROU asset and operating lease liabilities of $26.3 million. |
Other
Other | 3 Months Ended |
Mar. 31, 2021 | |
Other [Abstract] | |
Other | Other Long-Term Debt As of March 31, 2021, Puget Energy maintained an $800.0 million credit facility, of which $23.5 million was drawn and outstanding under the facility. For further information, see Note 7, "Long-Term Debt" and Note 8, "Liquidity Facilities and Other Financing Arrangements" in the Company's most recent Annual Report on Form 10K for the year ended December 31, 2020. |
Short-term Debt | Short-Term Debt As of March 31, 2021, no amount was drawn under PSE's credit facility and $191.0 million was outstanding under the commercial paper program at PSE. For further information, see Note 8, "Liquidity Facilities and Other Financing Arrangements" in the Company's most recent Annual Report on Form 10K for the year ended December 31, 2020. |
Accounting Policies (Tables)
Accounting Policies (Tables) | 3 Months Ended |
Mar. 31, 2021 | |
Accounting Policies [Abstract] | |
Accounts Receivable, Allowance for Credit Loss | The following table presents the activity in the allowance for credit losses for accounts receivable for the three months ended March 31, 2021 and 2020: Puget Energy and Three Months Ended (Dollars in Thousands) 2021 2020 Allowance for credit losses: Beginning balance $ 20,080 $ 8,294 Provision for credit loss expense 12,452 4,894 Receivables charged-off (2,140) (3,374) Total ending allowance balance $ 30,392 $ 9,814 |
Revenue (Tables)
Revenue (Tables) | 3 Months Ended |
Mar. 31, 2021 | |
Revenue from Contract with Customer [Abstract] | |
Disaggregation of Revenue | The following table presents disaggregated revenue from contracts with customers, and other revenue by major source: Puget Energy and (Dollars in Thousands) Three Months Ended Revenue from contracts with customers: 2021 2020 Electric retail $ 664,102 $ 607,693 Natural gas retail 387,863 365,637 Other 56,129 43,774 Total revenue from contracts with customers 1,108,094 1,017,104 Alternative revenue programs (1,928) 1,150 Other non-customer revenue 53,920 27,876 Total operating revenue $ 1,160,086 $ 1,046,130 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | Based on management’s best estimate of commencement, the Company expects to recognize this revenue over the following time periods: Puget Energy (Dollars in Thousands) 2024 2025 2026 2027 2028 Thereafter Total Remaining Performance Obligations $ 15,359 $ 19,710 $ 19,454 $ 19,454 $ 19,454 $ 102,135 $ 195,566 |
Accounting for Derivative Ins_2
Accounting for Derivative Instruments and Hedging Activities (Tables) | 3 Months Ended |
Mar. 31, 2021 | |
Derivative [Line Items] | |
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value | The following table presents the volumes, fair values and classification of the Company's derivative instruments recorded on the balance sheets: Puget Energy and March 31, 2021 December 31, 2020 (Dollars in Thousands) Volumes Assets 1 Liabilities 2 Volumes Assets 1 Liabilities 2 Electric portfolio derivatives * $ 32,366 $ 33,743 * $ 22,544 $ 46,922 Natural gas derivatives (MMBtus) 3 331 19,780 10,428 320 19,276 14,352 Total derivative contracts $ 52,146 $ 44,171 $ 41,820 $ 61,274 Current $ 47,221 $ 19,839 $ 33,015 $ 31,441 Long-term 4,925 24,332 8,805 29,833 Total derivative contracts $ 52,146 $ 44,171 $ 41,820 $ 61,274 _______________ 1 Balance sheet classification: Current and Long-term Unrealized gain on derivative instruments. 2 Balance sheet classification: Current and Long-term Unrealized loss on derivative instruments. 3 All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the purchased gas adjustment (PGA) mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers. * Electric portfolio derivatives consist of electric generation fuel of 221.4 million One Million British Thermal Units (MMBtu) and purchased electricity of 4.4 million Megawatt Hours (MWhs) at March 31, 2021, and 212.2 million MMBtus and 6.6 million MWhs at December 31, 2020. |
Offsetting Assets and Liabilities | The following tables present the potential effect of netting arrangements, including rights of set-off associated with the Company's derivative assets and liabilities: Puget Energy and At March 31, 2021 Gross Amount Recognized in the Statement of Financial Position 1 Gross Amounts Offset in the Statement of Financial Position Net of Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position (Dollars in Thousands) Commodity Contracts Cash Collateral Received/Posted Net Amount Assets: Energy derivative contracts $ 52,146 $ — $ 52,146 $ (21,105) $ — $ 31,041 Liabilities: Energy derivative contracts $ 44,171 $ — $ 44,171 $ (21,105) $ (143) $ 22,923 Puget Energy and At December 31, 2020 Gross Amount Recognized in the Statement of Financial Position 1 Gross Amounts Offset in the Statement of Financial Position Net of Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position (Dollars in Thousands) Commodity Contracts Cash Collateral Received/Posted Net Amount Assets: Energy derivative contracts $ 41,820 $ — $ 41,820 $ (21,696) $ — $ 20,124 Liabilities: Energy derivative contracts $ 61,274 $ — $ 61,274 $ (21,696) $ (9,343) $ 30,235 _______________ 1 All derivative contract deals are executed under ISDA, NAESB and WSPP master netting agreements with right of set-off. |
Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance | The following table presents the effect and classification of the realized and unrealized gains (losses) of the Company's derivatives recorded on the statements of income: Puget Energy and Three Months Ended (Dollars in Thousands) Classification 2021 2020 Gas for Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net $ 1,628 $ (9,755) Realized Electric generation fuel 8,313 1,296 Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net 21,374 (38,786) Realized Purchased electricity (13,303) (5,935) Total gain (loss) recognized in income on derivatives $ 18,012 $ (53,180) |
Schedule of Credit Risk Related Contingent Features | The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral the Company could be required to post: Puget Energy and (Dollars in Thousands) At March 31, 2021 At December 31, 2020 Fair Value 1 Posted Contingent Fair Value 1 Posted Contingent Contingent Feature Liability Collateral Collateral Liability Collateral Collateral Credit rating 2 $ 21,991 $ — $ 21,991 $ 26,966 $ — $ 26,966 Requested credit for adequate assurance 7,330 — — 6,576 — — Forward value of contract 3 143 11,990 N/A 9,343 20,903 N/A Total $ 29,464 $ 11,990 $ 21,991 $ 42,885 $ 20,903 $ 26,966 _______________ 1 Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes NPNS, accounts payable and accounts receivable. 2 Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to demand collateral. 3 . Collateral requirements may vary, based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds. |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 3 Months Ended |
Mar. 31, 2021 | |
Fair Value Disclosures [Abstract] | |
Fair Value Inputs, Liabilities, Quantitative Information | The fair value of the long-term notes was estimated using the discounted cash flow method with the U.S. Treasury yields and the Company's credit spreads as inputs, interpolating to the maturity date of each issue. The carrying values and estimated fair values were as follows: Puget Energy March 31, 2021 December 31, 2020 (Dollars in Thousands) Level Carrying Fair Carrying Fair Liabilities: Long-term debt (fixed-rate), net of discount 1 2 $ 5,670,834 $ 7,063,347 $ 5,667,740 $ 7,755,946 Long-term debt (variable-rate) 2 233,500 233,500 224,700 224,700 Total liabilities $ 5,904,334 $ 7,296,847 $ 5,892,440 $ 7,980,646 Puget Sound Energy March 31, 2021 December 31, 2020 (Dollars in Thousands) Level Carrying Fair Carrying Fair Liabilities: Long-term debt (fixed-rate), net of discount 2 2 $ 4,338,523 $ 5,446,409 $ 4,338,044 $ 6,086,358 Total liabilities $ 4,338,523 $ 5,446,409 $ 4,338,044 $ 6,086,358 _______________ 1 The carrying value includes debt issuances costs of $21.9 million and $22.7 million for March 31, 2021 and December 31, 2020, respectively, which are not included in fair value. 2 The carrying value includes debt issuances costs of $22.6 million and $22.9 million for March 31, 2021 and December 31, 2020, respectively, which are not included in fair value. |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis | The following table presents the Company's financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis: Puget Energy and Fair Value Fair Value (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Assets: Electric derivative instruments $ 31,980 $ 386 $ 32,366 $ 21,947 $ 597 $ 22,544 Natural gas derivative instruments 19,677 103 19,780 19,139 137 19,276 Total assets $ 51,657 $ 489 $ 52,146 $ 41,086 $ 734 $ 41,820 Liabilities: Electric derivative instruments $ 12,187 $ 21,556 $ 33,743 $ 22,607 $ 24,315 $ 46,922 Natural gas derivative instruments 8,491 1,937 10,428 13,080 1,272 14,352 Total liabilities $ 20,678 $ 23,493 $ 44,171 $ 35,687 $ 25,587 $ 61,274 |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation | The following table presents the Company's reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy: Puget Energy and Three Months Ended (Dollars in Thousands) 2021 2020 Level 3 Roll-Forward Net Asset/(Liability) Electric Natural Gas Total Electric Natural Gas Total Balance at beginning of period $ (23,718) $ (1,135) $ (24,853) $ (3,379) $ 1,282 $ (2,097) Changes during period: Realized and unrealized energy derivatives: Included in earnings 1 820 — 820 (24,552) — (24,552) Included in regulatory assets / liabilities — (888) (888) — 323 323 Settlements 1,728 189 1,917 1,626 (513) 1,113 Transferred into Level 3 — — — — — — Transferred out of Level 3 — — — — — — Balance at end of period $ (21,170) $ (1,834) $ (23,004) $ (26,305) $ 1,092 $ (25,213) _______________ 1 Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $0.8 million and zero for three months ended March 31, 2021 and 2020, respectively. |
Fair Value Inputs, Assets and Liabilities, Quantitative Information | The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of March 31, 2021 Puget Energy and Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Average Electric $ 386 $ 21,556 Discounted cash flow Power prices (per MWh) $ 22.87 $ 44.21 $ 32.56 Natural gas $ 103 $ 1,937 Discounted cash flow Natural gas prices (per MMBtu) $ 2.10 $ 3.57 $ 2.70 _______________ 1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions. The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of December 31, 2020: Puget Energy and Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Average Electric $ 597 $ 24,315 Discounted cash flow Power prices (per MWh) $ 22.82 $ 41.66 $ 31.54 Natural gas $ 137 $ 1,272 Discounted cash flow Natural gas prices (per MMBtu) $ 1.89 $ 3.42 $ 2.47 ___________ 1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions. |
Schedule of Effect of Significant Unobservable Inputs, Changes in Plan Assets | The following table presents the significant unobservable inputs used in estimating the impaired long-term power purchase contracts' fair value: Puget Energy Valuation Date Unobservable Input Low High Average March 31, 2020 Power prices (per MWh) $10.23 $29.05 $20.88 Power contract costs per quarter (in thousands) $6,308 $7,085 $6,468 |
Retirement Benefits (Tables)
Retirement Benefits (Tables) | 3 Months Ended |
Mar. 31, 2021 | |
Retirement Benefits [Abstract] | |
Schedule of Net Benefit Costs | The following tables summarize the Company’s net periodic benefit cost for the three months ended March 31, 2021 and 2020: Puget Energy Qualified SERP Other Three Months Ended March 31, (Dollars in Thousands) 2021 2020 2021 2020 2021 2020 Components of net periodic benefit cost: Service cost $ 6,711 $ 5,997 $ 115 $ 228 $ 41 $ 49 Interest cost 5,578 6,298 293 378 77 91 Expected return on plan assets (12,081) (12,502) — — (91) (97) Amortization of prior service cost (476) (495) 87 87 2 — Amortization of net loss (gain) 2,830 1,981 587 586 (10) (22) Net periodic benefit cost $ 2,562 $ 1,279 $ 1,082 $ 1,279 $ 19 $ 21 Puget Sound Energy Qualified SERP Other Three Months Ended March 31, (Dollars in Thousands) 2021 2020 2021 2020 2021 2020 Components of net periodic benefit cost: Service cost $ 6,711 $ 5,997 $ 115 $ 228 $ 41 $ 49 Interest cost 5,578 6,298 293 378 77 91 Expected return on plan assets (12,081) (12,504) — — (91) (97) Amortization of prior service cost (378) (393) 87 87 2 — Amortization of net loss (gain) 5,311 4,656 635 659 (15) (36) Net periodic benefit cost $ 5,141 $ 4,054 $ 1,130 $ 1,352 $ 14 $ 7 |
Schedule of Changes in Projected Benefit Obligations | The following table summarizes the Company’s change in benefit obligation for the periods ended March 31, 2021 and December 31, 2020: Puget Energy and Qualified SERP Other Three Months Ended Year Ended Three Months Ended Year Ended Three Months Ended Year Ended (Dollars in Thousands) March 31, December 31, March 31, December 31, March 31, December 31, Change in benefit obligation: Benefit obligation at beginning of period $ 849,383 $ 774,305 $ 46,742 $ 63,000 $ 12,114 $ 11,627 Amendments — — — — — 44 Service cost 6,711 24,337 115 756 41 190 Interest cost 5,578 25,180 293 1,464 77 368 Curtailment Loss / (Gain) — — — — — — Actuarial loss (gain) — 69,413 — 3,663 — 604 Benefits paid (11,625) (42,775) (496) (22,141) (237) (906) Medicare part D subsidy received — — — — 196 187 Administrative Expense — (1,077) — — — — Benefit obligation at end of period $ 850,047 $ 849,383 $ 46,654 $ 46,742 $ 12,191 $ 12,114 |
Regulation and Rates Public Uti
Regulation and Rates Public Utilities, Regulatory Proceeding (Tables) - Subsidiaries [Member] | 3 Months Ended |
Mar. 31, 2021 | |
Purchased Gas Adjustment [Member] | Natural Gas | |
Regulation and Rates [Line Items] | |
Schedule of PGA Receivable Payable | The following table presents the PGA mechanism balances and activity at March 31, 2021 and December 31, 2020: (Dollars in Thousands) At March 31, At December 31, PGA receivable balance and activity 2021 2020 PGA receivable beginning balance $ 87,655 $ 132,766 Actual natural gas costs 113,175 314,792 Allowed PGA recovery (154,592) (363,886) Interest 549 3,983 PGA receivable ending balance $ 46,787 $ 87,655 |
PCA Mechanism [Member] | Electricity | |
Regulation and Rates [Line Items] | |
Schedule of Graduated Scale of Rate Adjustment Mechanism | Effective January 1, 2017, the following graduated scale is used in the PCA mechanism: Company’s Share Customers' Share Annual Power Cost Variability Over Under Over Under Over or Under Collected by up to $17 million 100 % 100 % — % — % Over or Under Collected by between $17 million - $40 million 35 50 65 50 Over or Under Collected beyond $40 + million 10 10 90 90 |
Summary of Consolidation and _2
Summary of Consolidation and Significant Accounting Policy (Details) $ in Thousands | 3 Months Ended | |||
Mar. 31, 2021USD ($)mi² | Mar. 31, 2020USD ($) | Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($) | |
Summary of Consolidation Policy | ||||
Allowance for Credit Losses, Beginning Balance | $ 20,080 | $ 8,294 | ||
Provision for Credit Loss | $ 12,452 | $ 4,894 | ||
Receivables Charged-Off | (2,140) | (3,374) | ||
Allowance for Credit Loss, Ending Balance | $ 30,392 | 9,814 | ||
Subsidiaries [Member] | ||||
Summary of Consolidation Policy | ||||
Area of Service Territory (in sqmi) | mi² | 6,000 | |||
Variable Interest Entity [Line Items] | ||||
Contract Length, PPA | 20 years | |||
Variable Interest Entity, Measure of Activity, Expense | $ 5,700 | |||
Variable Interest Entity, Payable | $ 3,600 | |||
Subsidiaries [Member] | Tacoma LNG [Member] | ||||
Summary of Consolidation Policy | ||||
Jointly Owned Non-Utility Plant Share | 43.00% | |||
Construction in Progress, Gross | $ 216,500 | 207,700 | ||
Puget LNG [Member] | ||||
Summary of Consolidation Policy | ||||
Jointly Owned Non-Utility Plant Share | 57.00% | |||
Construction in Progress, Gross | $ 239,400 | $ 231,600 | ||
Puget LNG [Member] | ||||
Summary of Consolidation Policy | ||||
Operating Costs and Expenses | $ 200 | $ 300 |
Revenue (Details)
Revenue (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2021 | Mar. 31, 2020 | Dec. 31, 2020 | |
Disaggregation of Revenue [Line Items] | |||
Revenue from Contract with Customer, Including Assessed Tax | $ 1,108,094 | $ 1,017,104 | |
Regulated Operating Revenue, Other | 8,588 | 6,009 | |
Revenues | 1,160,086 | 1,046,130 | |
Electricity, US Regulated [Member] | |||
Disaggregation of Revenue [Line Items] | |||
Revenue from Contract with Customer, Including Assessed Tax | 664,102 | 607,693 | |
Natural Gas, US Regulated [Member] | |||
Disaggregation of Revenue [Line Items] | |||
Revenue from Contract with Customer, Including Assessed Tax | 387,863 | 365,637 | |
Other Revenue From Contracts with Customers [Member] | |||
Disaggregation of Revenue [Line Items] | |||
Revenue from Contract with Customer, Including Assessed Tax | 56,129 | 43,774 | |
Decoupling over-collection [Domain] | |||
Disaggregation of Revenue [Line Items] | |||
Regulated Operating Revenue, Other | (1,928) | 1,150 | |
Other Non-606 Revenue [Member] | |||
Disaggregation of Revenue [Line Items] | |||
Regulated Operating Revenue, Other | 53,920 | 27,876 | |
Subsidiaries [Member] | |||
Disaggregation of Revenue [Line Items] | |||
Regulated Operating Revenue, Other | 8,588 | 6,009 | |
Revenues | $ 1,160,086 | $ 1,046,130 | |
Puget LNG [Member] | |||
Disaggregation of Revenue [Line Items] | |||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, 2026 | $ 19,454 | ||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | 19,454 | ||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | 19,454 | ||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | 102,135 | ||
Revenue, Remaining Performance Obligation, Amount | 195,566 | ||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, 2025 | 19,710 | ||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, 2025 | $ 15,359 | ||
Remaining Contract Term, PLNG | 10 years |
Accounting for Derivative Ins_3
Accounting for Derivative Instruments and Hedging Activities Narrative (Details) $ in Millions | 3 Months Ended |
Mar. 31, 2021USD ($) | |
Subsidiaries [Member] | |
Derivative [Line Items] | |
Hedging strategy number of years extended | 3 years |
Natural Gas Portfolio [Member] | |
Derivative [Line Items] | |
Posted Collateral | $ 12 |
External Credit Rating, Investment Grade [Member] | |
Derivative [Line Items] | |
Derivative, Credit Risk Exposure, Percentage | 99.20% |
External Credit Rating, Non Investment Grade [Member] | |
Derivative [Line Items] | |
Derivative, Credit Risk Exposure, Percentage | 0.80% |
Credit Rating [Member] | |
Derivative [Line Items] | |
Posted Collateral | $ 3.2 |
Credit Rating [Member] | Natural Gas Portfolio [Member] | |
Derivative [Line Items] | |
Posted Collateral | $ 1 |
Accounting for Derivative Ins_4
Accounting for Derivative Instruments and Hedging Activities Derivative Assets and Liabilities (Details) $ in Thousands, MMBTU in Millions | Mar. 31, 2021USD ($)MMBTU | Dec. 31, 2020USD ($)MMBTU | |
Derivative [Line Items] | |||
Current, Assets | $ 47,221 | $ 33,015 | |
Long-term, Assets | 4,925 | 8,805 | |
Current, Liabilities | 19,839 | 31,441 | |
Long-term, Liabilities | 24,332 | 29,833 | |
Not Designated as Hedging Instrument [Member] | |||
Derivative [Line Items] | |||
Current, Assets | 47,221 | 33,015 | |
Long-term, Assets | 4,925 | 8,805 | |
Assets | [1] | 52,146 | 41,820 |
Current, Liabilities | 19,839 | 31,441 | |
Long-term, Liabilities | 24,332 | 29,833 | |
Derivative Liability | [2] | $ 44,171 | $ 61,274 |
Not Designated as Hedging Instrument [Member] | Natural Gas Derivatives [Member] | |||
Derivative [Line Items] | |||
Derivative, Nonmonetary Notional Amount | MMBTU | 331 | 320 | |
Not Designated as Hedging Instrument [Member] | Electric Portfolio [Member] | |||
Derivative [Line Items] | |||
Assets | $ 32,366 | $ 22,544 | |
Derivative Liability | 33,743 | 46,922 | |
Not Designated as Hedging Instrument [Member] | Natural Gas Portfolio [Member] | |||
Derivative [Line Items] | |||
Assets | 19,780 | 19,276 | |
Derivative Liability | $ 10,428 | $ 14,352 | |
Not Designated as Hedging Instrument [Member] | Electric Generation Fuel [Member] | |||
Derivative [Line Items] | |||
Derivative, Nonmonetary Notional Amount | MMBTU | 221.4 | 212.2 | |
Not Designated as Hedging Instrument [Member] | Purchased Electricity [Member] | |||
Derivative [Line Items] | |||
Derivative, Nonmonetary Notional Amount | MMBTU | 4.4 | 6.6 | |
[1] | _______________ 1 Balance sheet classification: Current and Long-term Unrealized gain on derivative instruments. | ||
[2] | 2 Balance sheet classification: Current and Long-term Unrealized loss on derivative instruments. |
Accounting for Derivative Ins_5
Accounting for Derivative Instruments and Hedging Activities Net Amount of Derivatives Reported in the Statement of Financial Position (Details) - Commodity Contract [Member] - USD ($) $ in Thousands | Mar. 31, 2021 | Dec. 31, 2020 |
Assets: | ||
Gross Amount Recognized in the Statement of Financial Position | $ 52,146 | $ 41,820 |
Gross Amounts Offset in the Statement of Financial Position | 0 | 0 |
Assets | 52,146 | 41,820 |
Commodity Contracts | (21,105) | (21,696) |
Cash Collateral Received | 0 | 0 |
Net Amount | 31,041 | 20,124 |
Liabilities: | ||
Gross Amount Recognized in the Statement of Financial Position | 44,171 | 61,274 |
Gross Amounts Offset in the Statement of Financial Position | 0 | 0 |
Derivative Liability | 44,171 | 61,274 |
Commodity Contracts | (21,105) | (21,696) |
Cash Collateral Posted | (143) | (9,343) |
Net Amount | $ 22,923 | $ 30,235 |
Accounting for Derivative Ins_6
Accounting for Derivative Instruments and Hedging Activities Recognized in Statement of Income (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2021 | Mar. 31, 2020 | |
Derivative Instruments, (Loss) Gain [Line Items] | ||
Unrealized (gain) loss on derivative instruments | $ 23,002 | $ (48,541) |
Not Designated as Hedging Instrument [Member] | ||
Derivative Instruments, (Loss) Gain [Line Items] | ||
Unrealized (gain) loss on derivative instruments | 18,012 | (53,180) |
Not Designated as Hedging Instrument [Member] | Electric Generation Fuel [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net [Member] | ||
Derivative Instruments, (Loss) Gain [Line Items] | ||
Unrealized (gain) loss on derivative instruments | 1,628 | (9,755) |
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Electric Generation Fuel [Member] | ||
Derivative Instruments, (Loss) Gain [Line Items] | ||
Unrealized (gain) loss on derivative instruments | 8,313 | 1,296 |
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Purchased Electricity [Member] | ||
Derivative Instruments, (Loss) Gain [Line Items] | ||
Unrealized (gain) loss on derivative instruments | (13,303) | (5,935) |
Not Designated as Hedging Instrument [Member] | Electricity, US Regulated [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net [Member] | ||
Derivative Instruments, (Loss) Gain [Line Items] | ||
Unrealized (gain) loss on derivative instruments | $ 21,374 | $ (38,786) |
Accounting for Derivative Ins_7
Accounting for Derivative Instruments and Hedging Activities Contractual Contingent Liability (Details) - USD ($) $ in Thousands | Mar. 31, 2021 | Dec. 31, 2020 |
Electric Portfolio [Member] | ||
Derivative [Line Items] | ||
Fair Value Liability | $ 29,464 | $ 42,885 |
Posted Collateral | 11,990 | 20,903 |
Additional Collateral, Aggregate Fair Value | 21,991 | 26,966 |
Natural Gas Portfolio [Member] | ||
Derivative [Line Items] | ||
Posted Collateral | 12,000 | |
Credit Rating [Member] | ||
Derivative [Line Items] | ||
Posted Collateral | 3,200 | |
Credit Rating [Member] | Electric Portfolio [Member] | ||
Derivative [Line Items] | ||
Fair Value Liability | 21,991 | 26,966 |
Posted Collateral | 0 | 0 |
Additional Collateral, Aggregate Fair Value | 21,991 | 26,966 |
Credit Rating [Member] | Natural Gas Portfolio [Member] | ||
Derivative [Line Items] | ||
Posted Collateral | 1,000 | |
Requested Credit for Adequate Assurance [Member] | Electric Portfolio [Member] | ||
Derivative [Line Items] | ||
Fair Value Liability | 7,330 | 6,576 |
Posted Collateral | 0 | 0 |
Additional Collateral, Aggregate Fair Value | 0 | 0 |
Forward Value of Contract [Member] | Electric Portfolio [Member] | ||
Derivative [Line Items] | ||
Fair Value Liability | 143 | 9,343 |
Posted Collateral | $ 11,990 | $ 20,903 |
Fair Value Measurements Debt at
Fair Value Measurements Debt at at Carrying and Fair Value (Details) - USD ($) | Mar. 31, 2021 | Dec. 31, 2020 |
Liabilities: | ||
Total long-term debt | $ 5,904,334,000 | $ 5,892,440,000 |
Carrying Value [Member] | Level 2 [Member] | ||
Liabilities: | ||
Notes Receivable, Fair Value Disclosure | 52,000,000 | 52,700,000 |
Subsidiaries [Member] | ||
Liabilities: | ||
Total long-term debt | 4,338,523,000 | 4,338,044,000 |
Discounted cash flow [Member] | Fair Value [Member] | ||
Liabilities: | ||
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure | 7,296,847,000 | 7,980,646,000 |
Discounted cash flow [Member] | Fair Value [Member] | Level 2 [Member] | ||
Liabilities: | ||
Long-term debt (fixed-rate), net of discount | 7,063,347,000 | 7,755,946,000 |
Long-term debt (variable-rate) | 233,500,000 | 224,700,000 |
Discounted cash flow [Member] | Carrying Value [Member] | ||
Liabilities: | ||
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure | 5,904,334,000 | 5,892,440,000 |
Discounted cash flow [Member] | Carrying Value [Member] | Level 2 [Member] | ||
Liabilities: | ||
Long-term debt (fixed-rate), net of discount | 5,670,834,000 | 5,667,740,000 |
Long-term debt (variable-rate) | 233,500,000 | 224,700,000 |
Debt issuance costs | 21,900,000 | 22,700,000 |
Discounted cash flow [Member] | Subsidiaries [Member] | Fair Value [Member] | ||
Liabilities: | ||
Total long-term debt | 5,446,409,000 | 6,086,358,000 |
Discounted cash flow [Member] | Subsidiaries [Member] | Fair Value [Member] | Level 2 [Member] | ||
Liabilities: | ||
Long-term debt (fixed-rate), net of discount | 5,446,409,000 | 6,086,358,000 |
Discounted cash flow [Member] | Subsidiaries [Member] | Carrying Value [Member] | ||
Liabilities: | ||
Total long-term debt | 4,338,523,000 | 4,338,044,000 |
Discounted cash flow [Member] | Subsidiaries [Member] | Carrying Value [Member] | Level 2 [Member] | ||
Liabilities: | ||
Long-term debt (fixed-rate), net of discount | 4,338,523,000 | 4,338,044,000 |
Debt issuance costs | $ 22,600,000 | $ 22,900,000 |
Fair Value Measurements Assets
Fair Value Measurements Assets and Liabilities (Details) - USD ($) $ in Thousands | 3 Months Ended | |||
Mar. 31, 2021 | Mar. 31, 2020 | Dec. 31, 2020 | Dec. 31, 2019 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs | $ (23,004) | $ (25,213) | $ (24,853) | $ (2,097) |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings | 820 | (24,552) | ||
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Regulatory Assets (Liabilities) | (888) | 323 | ||
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Settlements | 1,917 | 1,113 | ||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers into Level 3 | 0 | 0 | ||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers out of Level 3 | 0 | 0 | ||
Electric Portfolio [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs | (21,170) | (26,305) | (23,718) | (3,379) |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings | 820 | (24,552) | ||
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Regulatory Assets (Liabilities) | 0 | 0 | ||
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Settlements | 1,728 | 1,626 | ||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers into Level 3 | 0 | 0 | ||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers out of Level 3 | 0 | 0 | ||
Gain (loss) on derivatives | 800 | 0 | ||
Natural Gas Portfolio [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs | (1,834) | 1,092 | (1,135) | $ 1,282 |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings | 0 | 0 | ||
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Regulatory Assets (Liabilities) | (888) | 323 | ||
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Settlements | 189 | (513) | ||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers into Level 3 | 0 | 0 | ||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers out of Level 3 | 0 | $ 0 | ||
Fair Value, Recurring [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative Assets | 52,146 | 41,820 | ||
Derivative Liability | 44,171 | 61,274 | ||
Fair Value, Recurring [Member] | Electric Portfolio [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative Assets | 32,366 | 22,544 | ||
Derivative Liability | 33,743 | 46,922 | ||
Fair Value, Recurring [Member] | Natural Gas Portfolio [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative Assets | 19,780 | 19,276 | ||
Derivative Liability | 10,428 | 14,352 | ||
Fair Value, Recurring [Member] | Level 2 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative Assets | 51,657 | 41,086 | ||
Derivative Liability | 20,678 | 35,687 | ||
Fair Value, Recurring [Member] | Level 2 [Member] | Electric Portfolio [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative Assets | 31,980 | 21,947 | ||
Derivative Liability | 12,187 | 22,607 | ||
Fair Value, Recurring [Member] | Level 2 [Member] | Natural Gas Portfolio [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative Assets | 19,677 | 19,139 | ||
Derivative Liability | 8,491 | 13,080 | ||
Fair Value, Recurring [Member] | Level 3 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative Assets | 489 | 734 | ||
Derivative Liability | 23,493 | 25,587 | ||
Fair Value, Recurring [Member] | Level 3 [Member] | Electric Portfolio [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative Assets | 386 | 597 | ||
Derivative Liability | 21,556 | 24,315 | ||
Fair Value, Recurring [Member] | Level 3 [Member] | Natural Gas Portfolio [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative Assets | 103 | 137 | ||
Derivative Liability | $ 1,937 | $ 1,272 |
Fair Value Measurements Valuati
Fair Value Measurements Valuation Techniques for Measurement with Unobservable Inputs (Details) | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2021USD ($)$ / MWh$ / MMBTU | Mar. 31, 2020USD ($)$ / MWh | Dec. 31, 2020USD ($)$ / MWh$ / MMBTU | |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Fair Value measurement, sensitivity analysis, hypothetical increase or decrease of market prices, result on fair value | 0.10% | ||
Fair Value Measurements, Sensitivity Analysis, Hypothetical Increase or Decrease of Market Prices, Result on Fair Value | $ 4,900,000 | $ 5,500,000 | |
Wells Project | |||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Finite-Lived Intangible Assets, Net | $ 147,168,000 | ||
Impairment of Intangible Assets (Excluding Goodwill) | 52,565,000 | ||
Wells Project | Carrying Value [Member] | |||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Finite-lived Intangible Assets, Fair Value Disclosure | $ 94,603,000 | ||
Discounted cash flow [Member] | Low [Member] | Rocky Reach | |||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Price (per MWh) | $ / MWh | 10.23 | ||
Fair Value Inputs, Power Contract Costs | $ 6,308 | ||
Discounted cash flow [Member] | High [Member] | Wells Project | |||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Price (per MWh) | $ / MWh | 29.05 | ||
Discounted cash flow [Member] | High [Member] | Rocky Reach | |||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Fair Value Inputs, Power Contract Costs | $ 7,085 | ||
Discounted cash flow [Member] | Weighted Average [Member] | Wells Project | |||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Price (per MWh) | $ / MWh | 20.88 | ||
Discounted cash flow [Member] | Weighted Average [Member] | Rocky Reach | |||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Fair Value Inputs, Power Contract Costs | $ 6,468 | ||
Fair Value, Recurring [Member] | |||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Derivative Assets | 52,146,000 | 41,820,000 | |
Derivative Liability | 44,171,000 | 61,274,000 | |
Fair Value, Recurring [Member] | Level 3 [Member] | |||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Derivative Assets | 489,000 | 734,000 | |
Derivative Liability | $ 23,493,000 | $ 25,587,000 | |
Electric Portfolio [Member] | Discounted cash flow [Member] | Low [Member] | |||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Price (per MWh) | $ / MWh | 22.87 | 22.82 | |
Electric Portfolio [Member] | Discounted cash flow [Member] | High [Member] | |||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Price (per MWh) | $ / MWh | 44.21 | 41.66 | |
Electric Portfolio [Member] | Discounted cash flow [Member] | Weighted Average [Member] | |||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Price (per MWh) | $ / MWh | 32.56 | 31.54 | |
Electric Portfolio [Member] | Fair Value, Recurring [Member] | |||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Derivative Assets | $ 32,366,000 | $ 22,544,000 | |
Derivative Liability | 33,743,000 | 46,922,000 | |
Electric Portfolio [Member] | Fair Value, Recurring [Member] | Level 3 [Member] | |||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Derivative Assets | 386,000 | 597,000 | |
Derivative Liability | 21,556,000 | 24,315,000 | |
Electric Portfolio [Member] | Fair Value, Recurring [Member] | Parent Company [Member] | Level 3 [Member] | |||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Derivative Assets | 386,000 | 597,000 | |
Derivative Liability | $ 21,556,000 | $ 24,315,000 | |
Natural Gas Portfolio [Member] | Discounted cash flow [Member] | Low [Member] | |||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Fair Value Inputs, Price Per Millions of BTU | $ / MMBTU | 2.10 | 1.89 | |
Natural Gas Portfolio [Member] | Discounted cash flow [Member] | High [Member] | |||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Fair Value Inputs, Price Per Millions of BTU | $ / MMBTU | 3.57 | 3.42 | |
Natural Gas Portfolio [Member] | Discounted cash flow [Member] | Weighted Average [Member] | |||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Fair Value Inputs, Price Per Millions of BTU | $ / MMBTU | 2.70 | 2.47 | |
Natural Gas Portfolio [Member] | Fair Value, Recurring [Member] | |||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Derivative Assets | $ 19,780,000 | $ 19,276,000 | |
Derivative Liability | 10,428,000 | 14,352,000 | |
Natural Gas Portfolio [Member] | Fair Value, Recurring [Member] | Level 3 [Member] | |||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Derivative Assets | 103,000 | 137,000 | |
Derivative Liability | 1,937,000 | 1,272,000 | |
Natural Gas Portfolio [Member] | Fair Value, Recurring [Member] | Parent Company [Member] | Level 3 [Member] | |||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Derivative Assets | 103,000 | 137,000 | |
Derivative Liability | $ 1,937,000 | $ 1,272,000 |
Retirement Benefits - Benefit O
Retirement Benefits - Benefit Obligations (Details) - Subsidiaries [Member] | 3 Months Ended |
Mar. 31, 2021 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Defined Contribution Plan, Interest Credit | 1.00% |
employer contribution [Member] | Collective Bargaining Arrangement [Member] | UA represented [Member] | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay | 4.00% |
Retirement Benefits Net Periodi
Retirement Benefits Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2021 | Mar. 31, 2020 | Dec. 31, 2020 | |
Qualified Pension Benefits [Member] | |||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract] | |||
Defined Benefit Plan, Service Cost | $ 6,711 | $ 24,337 | |
Defined Benefit Plan, Interest Cost | 5,578 | 25,180 | |
Qualified Pension Benefits [Member] | Parent Company [Member] | |||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract] | |||
Defined Benefit Plan, Service Cost | 6,711 | $ 5,997 | |
Defined Benefit Plan, Interest Cost | 5,578 | 6,298 | |
Defined Benefit Plan, Expected Return (Loss) on Plan Assets | (12,081) | (12,502) | |
Defined Benefit Plan, Amortization of Prior Service Cost (Credit) | (476) | (495) | |
Defined Benefit Plan, Amortization of Gain (Loss) | 2,830 | 1,981 | |
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total | 2,562 | 1,279 | |
Qualified Pension Benefits [Member] | Subsidiaries [Member] | |||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract] | |||
Defined Benefit Plan, Service Cost | 6,711 | 5,997 | |
Defined Benefit Plan, Interest Cost | 5,578 | 6,298 | |
Defined Benefit Plan, Expected Return (Loss) on Plan Assets | (12,081) | (12,504) | |
Defined Benefit Plan, Amortization of Prior Service Cost (Credit) | (378) | (393) | |
Defined Benefit Plan, Amortization of Gain (Loss) | 5,311 | 4,656 | |
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total | 5,141 | 4,054 | |
Supplemental Employee Retirement Plan [Member] | |||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract] | |||
Defined Benefit Plan, Service Cost | 115 | 756 | |
Defined Benefit Plan, Interest Cost | 293 | 1,464 | |
Supplemental Employee Retirement Plan [Member] | Parent Company [Member] | |||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract] | |||
Defined Benefit Plan, Service Cost | 115 | 228 | |
Defined Benefit Plan, Interest Cost | 293 | 378 | |
Defined Benefit Plan, Expected Return (Loss) on Plan Assets | 0 | 0 | |
Defined Benefit Plan, Amortization of Prior Service Cost (Credit) | 87 | 87 | |
Defined Benefit Plan, Amortization of Gain (Loss) | 587 | 586 | |
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total | 1,082 | 1,279 | |
Supplemental Employee Retirement Plan [Member] | Subsidiaries [Member] | |||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract] | |||
Defined Benefit Plan, Service Cost | 115 | 228 | |
Defined Benefit Plan, Interest Cost | 293 | 378 | |
Defined Benefit Plan, Expected Return (Loss) on Plan Assets | 0 | 0 | |
Defined Benefit Plan, Amortization of Prior Service Cost (Credit) | 87 | 87 | |
Defined Benefit Plan, Amortization of Gain (Loss) | 635 | 659 | |
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total | 1,130 | 1,352 | |
Other Benefit [Member] | |||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract] | |||
Defined Benefit Plan, Service Cost | 41 | 190 | |
Defined Benefit Plan, Interest Cost | 77 | $ 368 | |
Other Benefit [Member] | Parent Company [Member] | |||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract] | |||
Defined Benefit Plan, Service Cost | 41 | 49 | |
Defined Benefit Plan, Interest Cost | 77 | 91 | |
Defined Benefit Plan, Expected Return (Loss) on Plan Assets | (91) | (97) | |
Defined Benefit Plan, Amortization of Prior Service Cost (Credit) | 2 | 0 | |
Defined Benefit Plan, Amortization of Gain (Loss) | (10) | (22) | |
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total | 19 | 21 | |
Other Benefit [Member] | Subsidiaries [Member] | |||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract] | |||
Defined Benefit Plan, Service Cost | 41 | 49 | |
Defined Benefit Plan, Interest Cost | 77 | 91 | |
Defined Benefit Plan, Expected Return (Loss) on Plan Assets | (91) | (97) | |
Defined Benefit Plan, Amortization of Prior Service Cost (Credit) | 2 | 0 | |
Defined Benefit Plan, Amortization of Gain (Loss) | (15) | (36) | |
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total | $ 14 | $ 7 |
Retirement Benefits Change in N
Retirement Benefits Change in Net Benefit Obligation (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended |
Mar. 31, 2021 | Dec. 31, 2020 | |
Qualified Pension Benefits [Member] | ||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | ||
Defined Benefit Plan, Benefit Obligation, Beginning Balance | $ 849,383 | $ 774,305 |
Defined Benefit Plan, Service Cost | 6,711 | 24,337 |
Defined Benefit Plan, Interest Cost | 5,578 | 25,180 |
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss) | 0 | 69,413 |
Defined Benefit Plan, Benefit Obligation, Benefits Paid | (11,625) | (42,775) |
Defined Benefit Plan, Benefit Obligation, Prescription Drug Subsidy Receipt | 0 | 0 |
defined benefit plan expected administration expense | 0 | 1,077 |
Defined Benefit Plan, Benefit Obligation, Ending Balance | 850,047 | 849,383 |
Supplemental Employee Retirement Plan [Member] | ||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | ||
Defined Benefit Plan, Benefit Obligation, Beginning Balance | 46,742 | 63,000 |
Defined Benefit Plan, Service Cost | 115 | 756 |
Defined Benefit Plan, Interest Cost | 293 | 1,464 |
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss) | 0 | 3,663 |
Defined Benefit Plan, Benefit Obligation, Benefits Paid | (496) | (22,141) |
Defined Benefit Plan, Benefit Obligation, Prescription Drug Subsidy Receipt | 0 | 0 |
defined benefit plan expected administration expense | 0 | 0 |
Defined Benefit Plan, Benefit Obligation, Ending Balance | 46,654 | 46,742 |
Other Benefit [Member] | ||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | ||
Defined Benefit Plan, Benefit Obligation, Beginning Balance | 12,114 | 11,627 |
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment | 0 | (44) |
Defined Benefit Plan, Service Cost | 41 | 190 |
Defined Benefit Plan, Interest Cost | 77 | 368 |
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss) | 0 | 604 |
Defined Benefit Plan, Benefit Obligation, Benefits Paid | (237) | (906) |
Defined Benefit Plan, Benefit Obligation, Prescription Drug Subsidy Receipt | 196 | 187 |
defined benefit plan expected administration expense | 0 | 0 |
Defined Benefit Plan, Benefit Obligation, Ending Balance | 12,191 | 12,114 |
Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Curtailment | 0 | 0 |
Qualified Plan [Member] | Qualified Pension Benefits [Member] | ||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | ||
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment | 0 | 0 |
Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Curtailment | 0 | 0 |
Nonqualified Plan [Member] | Qualified Pension Benefits [Member] | ||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | ||
Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Curtailment | 0 | 0 |
Nonqualified Plan [Member] | Supplemental Employee Retirement Plan [Member] | ||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | ||
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment | $ 0 | $ 0 |
Retirement Benefits Activity (D
Retirement Benefits Activity (Details) - USD ($) $ in Millions | 3 Months Ended | ||
Mar. 31, 2021 | Mar. 31, 2020 | Dec. 31, 2021 | |
Supplemental Employee Retirement Plan [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Employer contributions | $ 0.5 | $ 13.6 | |
Forecast [Member] | Qualified Pension Benefits [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Aggregate expected contributions | $ 18 | ||
Forecast [Member] | Supplemental Employee Retirement Plan [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Aggregate expected contributions | 6.8 | ||
Forecast [Member] | Other Benefit [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Aggregate expected contributions | $ 0.3 |
Regulation and Rates (Details)
Regulation and Rates (Details) - USD ($) | Apr. 12, 2021 | Apr. 02, 2021 | Feb. 02, 2021 | Dec. 09, 2020 | Nov. 01, 2020 | Sep. 30, 2020 | Aug. 31, 2020 | Aug. 30, 2020 | Jul. 31, 2020 | Jul. 08, 2020 | Apr. 06, 2020 | Jan. 15, 2020 | Nov. 01, 2019 | Oct. 31, 2019 | Jun. 20, 2019 | Apr. 10, 2019 | Mar. 01, 2019 | Jan. 30, 2019 | Nov. 07, 2018 | Dec. 19, 2017 | Dec. 18, 2017 | Mar. 31, 2021 | Mar. 31, 2020 | Apr. 30, 2018 | Jul. 19, 2021 | Dec. 31, 2020 | May 01, 2020 | Apr. 30, 2019 | Jul. 19, 2023 | Aug. 27, 2020 | Jul. 21, 2020 | Apr. 30, 2020 | Dec. 31, 2019 | Jan. 01, 2018 | Dec. 31, 2017 |
Regulatory Assets [Line Items] | |||||||||||||||||||||||||||||||||||
Income tax (benefit) expense | $ 2,153,000 | $ 3,984,000 | |||||||||||||||||||||||||||||||||
Depreciation & Amortization | 208,431,000 | 164,816,000 | |||||||||||||||||||||||||||||||||
Other Regulatory Assets | 737,377,000 | $ 747,651,000 | |||||||||||||||||||||||||||||||||
Subsidiaries [Member] | |||||||||||||||||||||||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||||||||||||||||||||||
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities | 7.49% | ||||||||||||||||||||||||||||||||||
Income tax (benefit) expense | 16,626,000 | 13,265,000 | $ 34,600,000 | ||||||||||||||||||||||||||||||||
Annual Power Cost Variability, Interest | 300,000 | 500,000 | |||||||||||||||||||||||||||||||||
PGA payable | 46,787,000 | 87,655,000 | $ 132,766,000 | ||||||||||||||||||||||||||||||||
Depreciation & Amortization | 208,362,000 | 164,771,000 | |||||||||||||||||||||||||||||||||
Liabilities, Other than Long-term Debt, Noncurrent | $ 11,000,000 | $ 4,500,000 | |||||||||||||||||||||||||||||||||
Customer Bill Assistance | $ 1,000 | ||||||||||||||||||||||||||||||||||
Other Regulatory Assets | 737,377,000 | 747,651,000 | |||||||||||||||||||||||||||||||||
Subsidiaries [Member] | Subsequent Event [Member] | |||||||||||||||||||||||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||||||||||||||||||||||
Customer Bill Assistance | $ 2,500 | ||||||||||||||||||||||||||||||||||
Subsidiaries [Member] | Electricity, US Regulated [Member] | |||||||||||||||||||||||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||||||||||||||||||||||
Storm Damage Costs Incurred During Period | 23,300,000 | 9,900,000 | |||||||||||||||||||||||||||||||||
Public Utilities, Rate Case, Deferred Storm Costs Threshold | $ 10,000,000 | $ 8,000,000 | |||||||||||||||||||||||||||||||||
Public Utilities, Rate Case, Deferred Storm Qualifying Costs | $ 500,000 | ||||||||||||||||||||||||||||||||||
Subsidiaries [Member] | Electricity | Subsequent Event [Member] | |||||||||||||||||||||||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||||||||||||||||||||||
Liabilities, Other than Long-term Debt, Noncurrent | 20,000,000 | ||||||||||||||||||||||||||||||||||
Subsidiaries [Member] | Natural Gas | Subsequent Event [Member] | |||||||||||||||||||||||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||||||||||||||||||||||
Liabilities, Other than Long-term Debt, Noncurrent | $ 7,700,000 | ||||||||||||||||||||||||||||||||||
General Rate Case [Member] | Subsidiaries [Member] | |||||||||||||||||||||||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||||||||||||||||||||||
Public Utilities, Requested Return on Equity, Percentage | 9.50% | 7.62% | |||||||||||||||||||||||||||||||||
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities | 7.48% | 7.49% | 7.60% | ||||||||||||||||||||||||||||||||
Annual Revenue Requirement | $ 25,600,000 | ||||||||||||||||||||||||||||||||||
Protected Excess Deferred Income Tax | $ 70,800,000 | ||||||||||||||||||||||||||||||||||
Fiscal Period Duration | 4 years | ||||||||||||||||||||||||||||||||||
Unprotected Excess Deferred Income Tax | $ 38,900,000 | ||||||||||||||||||||||||||||||||||
General Rate Case [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member] | |||||||||||||||||||||||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||||||||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 6.90% | ||||||||||||||||||||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 1,500,000 | ||||||||||||||||||||||||||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 27,700,000 | $ 900,000 | |||||||||||||||||||||||||||||||||
Public Utilities, Approved Rate Increase (Decrease), Percentage | 1.30% | 0.05% | |||||||||||||||||||||||||||||||||
Public Utilities, Approved Debt Capital Structure, Percentage | 7.39% | ||||||||||||||||||||||||||||||||||
Public Utilities, Interim Rate Increase (Decrease), Amount | $ 59,600,000 | $ 29,500,000 | |||||||||||||||||||||||||||||||||
Public Utilities, Interim Rate Increase (Decrease), Percentage | 2.90% | 1.60% | |||||||||||||||||||||||||||||||||
Public Utilities Attrition Adjustment Increase Decrease Amount | $ 23,900,000 | ||||||||||||||||||||||||||||||||||
PublicUtilitiesIncremenalRateIncreaseDecreaseAmount | $ 30,100,000 | ||||||||||||||||||||||||||||||||||
General Rate Case [Member] | Subsidiaries [Member] | Natural Gas, US Regulated [Member] | |||||||||||||||||||||||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||||||||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 7.90% | ||||||||||||||||||||||||||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 200,000 | $ 1,300,000 | |||||||||||||||||||||||||||||||||
Public Utilities, Approved Rate Increase (Decrease), Percentage | 0.02% | 0.15% | |||||||||||||||||||||||||||||||||
Public Utilities, Interim Rate Increase (Decrease), Amount | $ 42,900,000 | $ 36,500,000 | |||||||||||||||||||||||||||||||||
Public Utilities, Interim Rate Increase (Decrease), Percentage | 5.60% | 4.00% | |||||||||||||||||||||||||||||||||
Public Utilities Attrition Adjustment Increase Decrease Amount | $ 16,200,000 | ||||||||||||||||||||||||||||||||||
PublicUtilitiesIncremenalRateIncreaseDecreaseAmount | $ 6,400,000 | ||||||||||||||||||||||||||||||||||
General Rate Case [Member] | Maximum [Member] | Subsidiaries [Member] | |||||||||||||||||||||||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||||||||||||||||||||||
Public Utilities, Requested Return on Equity, Percentage | 9.80% | ||||||||||||||||||||||||||||||||||
Public Utilities, Approved Debt Capital Structure, Net of Tax, Percentage | 6.80% | ||||||||||||||||||||||||||||||||||
Public Utilities, Approved Equity Capital Structure, Percentage | 48.50% | ||||||||||||||||||||||||||||||||||
Public Utilities, Approved Return on Equity, Percentage | 9.40% | ||||||||||||||||||||||||||||||||||
Expedited Rate Filing (ERF) [Member] | Subsidiaries [Member] | |||||||||||||||||||||||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||||||||||||||||||||||
Fiscal Period Duration | 1 year | ||||||||||||||||||||||||||||||||||
Expedited Rate Filing (ERF) [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member] | |||||||||||||||||||||||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||||||||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 0.90% | ||||||||||||||||||||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 18,900,000 | ||||||||||||||||||||||||||||||||||
Expedited Rate Filing (ERF) [Member] | Subsidiaries [Member] | Natural Gas, US Regulated [Member] | |||||||||||||||||||||||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||||||||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 2.70% | ||||||||||||||||||||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 6,100,000 | $ 21,700,000 | |||||||||||||||||||||||||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 25,900,000 | $ 21,500,000 | |||||||||||||||||||||||||||||||||
Tax Cuts and Jobs Act [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member] | |||||||||||||||||||||||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||||||||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount | $ (72,900,000) | ||||||||||||||||||||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage | (3.40%) | ||||||||||||||||||||||||||||||||||
Contract with Customer, Refund Liability | $ 100,000 | ||||||||||||||||||||||||||||||||||
Tax Cuts and Jobs Act [Member] | Subsidiaries [Member] | Natural Gas, US Regulated [Member] | |||||||||||||||||||||||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||||||||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount | $ (23,600,000) | ||||||||||||||||||||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage | (2.70%) | ||||||||||||||||||||||||||||||||||
Decoupling Mechanism [Member] | |||||||||||||||||||||||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||||||||||||||||||||||
Deferred Revenue, Revenue Recognized | 0 | ||||||||||||||||||||||||||||||||||
Decoupling Mechanism [Member] | Subsidiaries [Member] | |||||||||||||||||||||||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||||||||||||||||||||||
Fiscal Period Duration | 2 years | 1 year | |||||||||||||||||||||||||||||||||
Amortization | $ 16,000,000 | ||||||||||||||||||||||||||||||||||
Decoupling Mechanism [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member] | |||||||||||||||||||||||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||||||||||||||||||||||
Contract with Customer, Liability, Revenue Recognized | 900,000 | ||||||||||||||||||||||||||||||||||
Decoupling Mechanism [Member] | Maximum [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member] | |||||||||||||||||||||||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||||||||||||||||||||||
Public Utilities, Approved Rate Increase (Decrease), Percentage | 3.00% | ||||||||||||||||||||||||||||||||||
Decoupling Mechanism [Member] | Maximum [Member] | Subsidiaries [Member] | Natural Gas, US Regulated [Member] | |||||||||||||||||||||||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||||||||||||||||||||||
Public Utilities, Approved Rate Increase (Decrease), Percentage | 5.00% | 3.00% | |||||||||||||||||||||||||||||||||
Purchased Gas Adjustment [Member] | Subsidiaries [Member] | |||||||||||||||||||||||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||||||||||||||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 32,600,000 | $ 17,800,000 | |||||||||||||||||||||||||||||||||
Purchased natural gas costs | 113,175,000 | 314,792,000 | |||||||||||||||||||||||||||||||||
Purchased natural gas costs, recoverable | (154,592,000) | (363,886,000) | |||||||||||||||||||||||||||||||||
Purchased natural gas adjustment, interest | 549,000 | 3,983,000 | |||||||||||||||||||||||||||||||||
Annual revenue | 37,400,000 | 100,600,000 | |||||||||||||||||||||||||||||||||
Out of Cycle PGA | $ 69,400,000 | 54,000,000 | |||||||||||||||||||||||||||||||||
Under collected commodity balances | 114,400,000 | ||||||||||||||||||||||||||||||||||
Commodity Costs | 10,800,000 | ||||||||||||||||||||||||||||||||||
Refund to Customers, remaining balance | 4,100,000 | ||||||||||||||||||||||||||||||||||
Refund to Customers | $ 54,700,000 | ||||||||||||||||||||||||||||||||||
Fiscal Period Duration | 3 years | 2 years | 1 year | ||||||||||||||||||||||||||||||||
Other Regulatory Assets | $ 4,900,000 | ||||||||||||||||||||||||||||||||||
Get to Zero Deferral Filing [Member] | Subsidiaries [Member] | |||||||||||||||||||||||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||||||||||||||||||||||
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities | 6.89% | ||||||||||||||||||||||||||||||||||
Depreciation & Amortization | 4,600,000 | $ 2,800,000 | |||||||||||||||||||||||||||||||||
Public Utilities, Property, Plant and Equipment, Equipment, Useful Life | 10 years | ||||||||||||||||||||||||||||||||||
Power Cost Only Rate Case | Subsidiaries [Member] | Electricity, US Regulated [Member] | |||||||||||||||||||||||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||||||||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 4.10% | 3.70% | |||||||||||||||||||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 88,000,000 | $ 78,500,000 | |||||||||||||||||||||||||||||||||
Power Cost Only Rate Case | Subsidiaries [Member] | Electricity, US Regulated [Member] | Subsequent Event [Member] | |||||||||||||||||||||||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||||||||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 3.10% | ||||||||||||||||||||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 65,300,000 | ||||||||||||||||||||||||||||||||||
Storm That Occurred In 2018 [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member] | |||||||||||||||||||||||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||||||||||||||||||||||
Storm Damage Costs Deferred During Period | $ 0 | ||||||||||||||||||||||||||||||||||
Storm That Occurred In 2019 [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member] | |||||||||||||||||||||||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||||||||||||||||||||||
Storm Damage Costs Deferred During Period | 200,000 | ||||||||||||||||||||||||||||||||||
storm that occurred in 2020 [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member] | |||||||||||||||||||||||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||||||||||||||||||||||
Storm Damage Costs Deferred During Period | $ 12,900,000 | ||||||||||||||||||||||||||||||||||
Forecast [Member] | General Rate Case [Member] | Subsidiaries [Member] | |||||||||||||||||||||||||||||||||||
Regulatory Assets [Line Items] | |||||||||||||||||||||||||||||||||||
Fiscal Period Duration | 12 months | 36 months |
Schedule of Power Cost Adjustme
Schedule of Power Cost Adjustment Mechanism (Details) - Subsidiaries [Member] $ in Millions | Dec. 31, 2019USD ($) | Mar. 31, 2021USD ($) | Mar. 31, 2020USD ($) | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) |
Regulatory Assets and Liabiliaties [Line Items] | |||||
Annual Power Cost Variability, Interest | $ 0.3 | $ 0.5 | |||
Under-collection [Member] | |||||
Regulatory Assets and Liabiliaties [Line Items] | |||||
Annual Power Cost Variability, Amount | 11.4 | 25.1 | $ 67.2 | ||
Customer's share [Member] | Under-collection [Member] | |||||
Regulatory Assets and Liabiliaties [Line Items] | |||||
Annual Power Cost Variability, Amount | $ 0 | $ 4 | 36 | ||
Customer's share [Member] | Range 1 [Member] | Under-collection [Member] | |||||
Regulatory Assets and Liabiliaties [Line Items] | |||||
Annual Power Cost Variability | 0 | ||||
Customer's share [Member] | Range 1 [Member] | Over-collection [Member] | |||||
Regulatory Assets and Liabiliaties [Line Items] | |||||
Annual Power Cost Variability | 0 | ||||
Customer's share [Member] | Range 2 [Member] | Under-collection [Member] | |||||
Regulatory Assets and Liabiliaties [Line Items] | |||||
Annual Power Cost Variability | 0.50 | ||||
Customer's share [Member] | Range 2 [Member] | Over-collection [Member] | |||||
Regulatory Assets and Liabiliaties [Line Items] | |||||
Annual Power Cost Variability | 0.65 | ||||
Customer's share [Member] | Range 3 [Member] | Under-collection [Member] | |||||
Regulatory Assets and Liabiliaties [Line Items] | |||||
Annual Power Cost Variability | 0.90 | ||||
Customer's share [Member] | Range 3 [Member] | Over-collection [Member] | |||||
Regulatory Assets and Liabiliaties [Line Items] | |||||
Annual Power Cost Variability | 0.90 | ||||
Companys share [Member] | Under-collection [Member] | |||||
Regulatory Assets and Liabiliaties [Line Items] | |||||
Annual Power Cost Variability, Amount | 31.2 | ||||
Companys share [Member] | Range 1 [Member] | Under-collection [Member] | |||||
Regulatory Assets and Liabiliaties [Line Items] | |||||
Annual Power Cost Variability | 1 | ||||
Companys share [Member] | Range 1 [Member] | Over-collection [Member] | |||||
Regulatory Assets and Liabiliaties [Line Items] | |||||
Annual Power Cost Variability | 1 | ||||
Companys share [Member] | Range 2 [Member] | Under-collection [Member] | |||||
Regulatory Assets and Liabiliaties [Line Items] | |||||
Annual Power Cost Variability | 0.50 | ||||
Companys share [Member] | Range 2 [Member] | Over-collection [Member] | |||||
Regulatory Assets and Liabiliaties [Line Items] | |||||
Annual Power Cost Variability | 0.35 | ||||
Companys share [Member] | Range 3 [Member] | Under-collection [Member] | |||||
Regulatory Assets and Liabiliaties [Line Items] | |||||
Annual Power Cost Variability | 0.10 | ||||
Companys share [Member] | Range 3 [Member] | Over-collection [Member] | |||||
Regulatory Assets and Liabiliaties [Line Items] | |||||
Annual Power Cost Variability | 0.10 | ||||
Customer's share plus interest | Under-collection [Member] | |||||
Regulatory Assets and Liabiliaties [Line Items] | |||||
Annual Power Cost Variability, Amount | $ 41.7 | 37 | $ 4.7 | ||
Customer's share plus interest | Maximum Power | |||||
Regulatory Assets and Liabiliaties [Line Items] | |||||
Annual Power Cost Variability, Amount | $ 20 |
Commitments and Contingencies (
Commitments and Contingencies (Details) | 3 Months Ended | |
Mar. 31, 2021USD ($) | Dec. 10, 2019USD ($)MW | |
Loss Contingencies [Line Items] | ||
Purchase Obligation | $ 777,400,000 | |
Subsidiaries [Member] | Electricity | ||
Loss Contingencies [Line Items] | ||
Change in Load, Percentage | 0.10% | |
Subsidiaries [Member] | Natural Gas | ||
Loss Contingencies [Line Items] | ||
Change in Load, Percentage | (3.70%) | |
Colstrip Units 1 and 2 [Member] | ||
Loss Contingencies [Line Items] | ||
Ownership interest (percent) | 50.00% | |
Jointly owned utility plant | 2 | |
Colstrip Units 3 and 4 [Member] | ||
Loss Contingencies [Line Items] | ||
Ownership interest (percent) | 25.00% | |
Colstrip Unit 4 | Subsidiaries [Member] | ||
Loss Contingencies [Line Items] | ||
Colstrip 4 Sale Amount | $ 1 | |
Colstrip PPA | MW | 90 |
Leases (Details)
Leases (Details) $ in Millions | 3 Months Ended |
Mar. 31, 2021USD ($) | |
Leases [Abstract] | |
ROU Asset, Modification, Operating | $ 26.3 |
Leases - Supplemental balance s
Leases - Supplemental balance sheet information related to leases (Details) - USD ($) $ in Thousands | Mar. 31, 2021 | Dec. 31, 2020 |
Lessee, Operating Lease, Description [Abstract] | ||
Operating Lease, Right-of-Use Asset | $ 194,245 | $ 172,167 |
Operating Lease, Liability, Current | 19,238 | 19,204 |
Operating Lease, Liability, Noncurrent | $ 182,288 | $ 160,980 |
Other (Details)
Other (Details) - USD ($) | Mar. 31, 2020 | Mar. 31, 2021 |
Short-term Debt [Line Items] | ||
Line of Credit Facility, Maximum Amount Outstanding During Period | $ 23,500,000 | |
Line of Credit Facility, Maximum Borrowing Capacity | 800,000,000 | |
Subsidiaries [Member] | ||
Short-term Debt [Line Items] | ||
Commercial Paper | $ 191,000,000 | |
Subsidiaries [Member] | Working Capital Needs [Member] | ||
Short-term Debt [Line Items] | ||
Line of Credit Facility, Maximum Amount Outstanding During Period | $ 0 |