Document And Entity Information
Document And Entity Information | 12 Months Ended | |
Dec. 31, 2016shares | Jun. 30, 2016USD ($) | |
Entity Information [Line Items] | ||
EBITDA to Interest Expense Denominator | 1 | |
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio at Period End | 1 | |
Entity Registrant Name | PUGET ENERGY INC /WA | |
Entity Central Index Key | 1,085,392 | |
Current Fiscal Year End Date | --12-31 | |
Entity Well-known Seasoned Issuer | No | |
Entity Voluntary Filers | No | |
Entity Current Reporting Status | Yes | |
Entity Filer Category | Non-accelerated Filer | |
Entity Public Float | $ | $ 0 | |
Entity Common Stock, Shares Outstanding | shares | 200 | |
Document Fiscal Year Focus | 2,016 | |
Document Fiscal Period Focus | FY | |
Document Type | 10-K | |
Amendment Flag | false | |
Document Period End Date | Dec. 31, 2016 | |
PUGET SOUND ENERGY, INC. | ||
Entity Information [Line Items] | ||
EBITDA to Interest Expense Denominator | 1 | |
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio at Period End | 1 | |
Entity Registrant Name | PUGET SOUND ENERGY INC | |
Entity Central Index Key | 81,100 | |
Current Fiscal Year End Date | --12-31 | |
Entity Well-known Seasoned Issuer | No | |
Entity Voluntary Filers | No | |
Entity Current Reporting Status | Yes | |
Entity Filer Category | Non-accelerated Filer | |
Entity Public Float | $ | $ 0 | |
Entity Common Stock, Shares Outstanding | shares | 85,903,791 | |
Document Fiscal Year Focus | 2,016 | |
Document Fiscal Period Focus | FY | |
Document Type | 10-K | |
Amendment Flag | false | |
Document Period End Date | Dec. 31, 2016 |
CONSOLIDATED STATEMENTS OF INCO
CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Operating revenue: | |||
Electric | $ 2,238,492 | $ 2,128,468 | $ 2,083,797 |
Natural gas | 890,510 | 947,549 | 1,012,859 |
Other | 35,299 | 16,683 | 16,515 |
Total operating revenue | 3,164,301 | 3,092,700 | 3,113,171 |
Energy costs: | |||
Purchased electricity | 531,596 | 499,522 | 514,087 |
Electric generation fuel | 215,331 | 249,907 | 263,493 |
Residential exchange | (69,824) | (112,473) | (129,036) |
Purchased natural gas | 313,954 | 403,310 | 458,691 |
Unrealized (gain) loss on derivative instruments, net | (83,795) | (13,233) | 84,146 |
Utility operations and maintenance | 568,492 | 530,720 | 550,146 |
Non-utility expense and other | 27,151 | 10,818 | 13,109 |
Depreciation and amortization | 439,579 | 420,807 | 365,606 |
Conservation amortization | 107,784 | 110,866 | 104,096 |
Taxes other than income taxes | 328,649 | 320,531 | 310,982 |
Total operating expenses | 2,378,917 | 2,420,775 | 2,535,320 |
Operating income (loss) | 785,384 | 671,925 | 577,851 |
Other income (deductions): | |||
Other income | 25,539 | 20,711 | 24,038 |
Other expense | (10,923) | (6,764) | (7,457) |
Non-hedged interest rate swap expense | (1,062) | (3,796) | (3,915) |
Interest charges: | |||
AFUDC | 9,304 | 7,575 | 5,611 |
Interest expense | (355,139) | (356,696) | (367,308) |
Income (loss) before income taxes | 453,103 | 332,955 | 228,820 |
Income tax (benefit) expense | 140,204 | 91,776 | 56,985 |
Net income (loss) | 312,899 | 241,179 | 171,835 |
PUGET SOUND ENERGY, INC. | |||
Operating revenue: | |||
Electric | 2,238,492 | 2,128,468 | 2,083,797 |
Natural gas | 890,510 | 947,549 | 1,012,859 |
Other | 35,616 | 17,241 | 19,467 |
Total operating revenue | 3,164,618 | 3,093,258 | 3,116,123 |
Energy costs: | |||
Purchased electricity | 531,596 | 499,522 | 514,087 |
Electric generation fuel | 215,331 | 249,907 | 263,493 |
Residential exchange | (69,824) | (112,473) | (129,036) |
Purchased natural gas | 313,954 | 403,310 | 458,691 |
Unrealized (gain) loss on derivative instruments, net | (83,795) | (12,688) | 85,636 |
Utility operations and maintenance | 568,492 | 530,720 | 550,146 |
Non-utility expense and other | 37,859 | 26,618 | 23,729 |
Depreciation and amortization | 439,579 | 420,807 | 365,606 |
Conservation amortization | 107,784 | 110,866 | 104,096 |
Taxes other than income taxes | 328,649 | 320,531 | 310,982 |
Total operating expenses | 2,389,625 | 2,437,120 | 2,547,430 |
Operating income (loss) | 774,993 | 656,138 | 568,693 |
Other income (deductions): | |||
Other income | 25,537 | 20,711 | 24,036 |
Other expense | (10,923) | (6,764) | (7,457) |
Interest charges: | |||
AFUDC | 9,304 | 7,575 | 5,611 |
Interest expense | (242,983) | (247,571) | (264,927) |
Income (loss) before income taxes | 555,928 | 430,089 | 325,956 |
Income tax (benefit) expense | 175,347 | 125,900 | 89,342 |
Net income (loss) | $ 380,581 | $ 304,189 | $ 236,614 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Parent [Line Items] | |||
Net income (loss) | $ 312,899 | $ 241,179 | $ 171,835 |
Other comprehensive income (loss): | |||
Other Comprehensive Income Reclassification Of Net Unrealized Gain Loss On Interest Rate Swaps During Period Net Of Tax | 0 | 0 | 94 |
Net unrealized gain (loss) from pension and postretirement plans, net of tax | (6,446) | 9,444 | (85,224) |
Reclassification of net unrealized loss on energy derivative instruments settled during the period, net of tax | 0 | 333 | 372 |
Other comprehensive income (loss) | (6,446) | 9,777 | (84,758) |
Comprehensive income (loss) | 306,453 | 250,956 | 87,077 |
PUGET SOUND ENERGY, INC. | |||
Parent [Line Items] | |||
Net income (loss) | 380,581 | 304,189 | 236,614 |
Other comprehensive income (loss): | |||
Net unrealized gain (loss) from pension and postretirement plans, net of tax | 3,722 | 20,404 | (76,876) |
Reclassification of net unrealized loss on energy derivative instruments settled during the period, net of tax | 0 | 686 | 1,341 |
Amortization of treasury interest rate swaps to earnings, net of tax | 317 | 317 | 317 |
Other comprehensive income (loss) | 4,039 | 21,407 | (75,218) |
Comprehensive income (loss) | $ 384,620 | $ 325,596 | $ 161,396 |
CONSOLIDATED STATEMENTS OF COM4
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Other comprehensive income (loss): | |||
Net tax on reclassification of net unrealized loss on interest rate swaps during the period, tax | $ 0 | $ 0 | $ 50 |
Net unrealized gain (loss) from pension and postretirement plans, tax | (3,471) | 5,087 | (45,890) |
Reclassification of net unrealized loss on energy derivative instruments during the period, tax | 0 | 179 | 200 |
PUGET SOUND ENERGY, INC. | |||
Other comprehensive income (loss): | |||
Net unrealized gain (loss) from pension and postretirement plans, tax | 2,004 | 10,987 | (41,395) |
Reclassification of net unrealized loss on energy derivative instruments during the period, tax | 0 | 369 | 722 |
Amortization of treasury interest rate swaps to earnings, tax | $ 171 | $ 171 | $ 171 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Utility Plant [Abstract] | ||
Electric plant | $ 7,673,772 | $ 7,432,490 |
Natural gas plant | 3,051,586 | 2,850,290 |
Common plant | 594,994 | 508,750 |
Less: Accumulated depreciation and amortization | (2,161,796) | (1,878,868) |
Net utility plant | 9,158,556 | 8,912,662 |
Other property and investments: | ||
Goodwill | 1,656,513 | 1,656,513 |
Other property and investments | 106,418 | 86,731 |
Total other property and investments | 1,762,931 | 1,743,244 |
Current assets: | ||
Cash and cash equivalents | 28,878 | 42,494 |
Restricted cash | 12,418 | 7,949 |
Accounts receivable, net of allowance for doubtful accounts | 329,375 | 324,391 |
Unbilled revenue | 234,053 | 217,274 |
Purchased gas adjustment receivable | 2,785 | 0 |
Materials and supplies, at average cost | 106,378 | 78,244 |
Fuel and natural gas inventory, at average cost | 58,181 | 58,658 |
Unrealized gain on derivative instruments | 54,341 | 24,418 |
Prepaid expense and other | 43,046 | 17,120 |
Power contract acquisition adjustment gain | 33,413 | 37,031 |
Total current assets | 902,868 | 807,579 |
Other long-term and regulatory assets: | ||
Regulatory asset for deferred income taxes | 72,038 | 73,231 |
Power cost adjustment mechanism | 4,531 | 4,749 |
Regulatory assets related to power contracts | 22,613 | 26,223 |
Other regulatory assets | 1,034,348 | 894,071 |
Unrealized gain on derivative instruments | 8,738 | 5,225 |
Power contract acquisition adjustment gain | 241,648 | 288,757 |
Other | 58,109 | 58,513 |
Total other long-term and regulatory assets | 1,442,025 | 1,350,769 |
Total assets | 13,266,380 | 12,814,254 |
Common shareholder’s equity: | ||
Common stock | 0 | 0 |
Additional paid-in capital | 3,308,957 | 3,308,957 |
Retained earnings | 413,468 | 249,534 |
Accumulated other comprehensive income (loss), net of tax | (33,712) | (27,266) |
Total common shareholder’s equity | 3,688,713 | 3,531,225 |
Long-term debt: | ||
First mortgage bonds and senior notes | 3,362,000 | 3,364,412 |
Pollution control bonds | 161,860 | 161,860 |
Junior subordinated notes | 250,000 | 250,000 |
Long-term debt | 1,812,480 | 1,800,000 |
Debt discount, issuance costs and other | (234,679) | (248,754) |
Total long-term debt | 5,351,661 | 5,327,518 |
Total capitalization | 9,040,374 | 8,858,743 |
Current liabilities: | ||
Accounts payable | 317,043 | 259,353 |
Short-term debt | 245,763 | 159,004 |
Current maturities of long-term debt | 2,412 | 0 |
Purchased gas adjustment liability | 0 | 12,589 |
Accrued expenses: | ||
Taxes | 111,428 | 114,854 |
Salaries and wages | 49,749 | 38,457 |
Interest | 73,610 | 73,378 |
Unrealized loss on derivative instruments | 44,310 | 136,173 |
Power Contract Acquisition Adjustment Loss Current | 3,159 | 3,611 |
Other | 71,996 | 53,867 |
Total current liabilities | 919,470 | 851,286 |
Other Long-term and regulatory liabilities: | ||
Deferred income taxes | 1,570,931 | 1,435,955 |
Unrealized loss on derivative instruments | 16,261 | 48,073 |
Regulatory liabilities | 654,622 | 652,441 |
Regulatory Liabilities Related To Power Contracts | 275,061 | 325,788 |
Power Contract Acquisition Adjustment Loss Non Current | 19,454 | 22,613 |
Other deferred credits | 770,207 | 619,355 |
Total other long-term and regulatory liabilities | 3,306,536 | 3,104,225 |
Commitments and contingencies (Note 15) | ||
Total capitalization and liabilities | 13,266,380 | 12,814,254 |
PUGET SOUND ENERGY, INC. | ||
Utility Plant [Abstract] | ||
Electric plant | 9,813,169 | 9,601,091 |
Natural gas plant | 3,640,271 | 3,444,744 |
Common plant | 632,718 | 548,657 |
Less: Accumulated depreciation and amortization | (4,927,602) | (4,681,830) |
Net utility plant | 9,158,556 | 8,912,662 |
Other property and investments: | ||
Other property and investments | 77,960 | 83,069 |
Total other property and investments | 77,960 | 83,069 |
Current assets: | ||
Cash and cash equivalents | 28,481 | 41,856 |
Restricted cash | 12,418 | 7,949 |
Accounts receivable, net of allowance for doubtful accounts | 344,964 | 324,358 |
Unbilled revenue | 234,053 | 217,274 |
Purchased gas adjustment receivable | 2,785 | 0 |
Materials and supplies, at average cost | 106,378 | 78,244 |
Fuel and natural gas inventory, at average cost | 56,851 | 57,324 |
Unrealized gain on derivative instruments | 54,341 | 24,418 |
Prepaid expense and other | 43,046 | 17,119 |
Total current assets | 883,317 | 768,542 |
Other long-term and regulatory assets: | ||
Regulatory asset for deferred income taxes | 71,517 | 72,694 |
Power cost adjustment mechanism | 4,531 | 4,749 |
Other regulatory assets | 1,034,352 | 894,059 |
Unrealized gain on derivative instruments | 8,738 | 5,225 |
Other | 58,109 | 58,513 |
Total other long-term and regulatory assets | 1,177,247 | 1,035,240 |
Total assets | 11,297,080 | 10,799,513 |
Common shareholder’s equity: | ||
Common stock | 859 | 859 |
Additional paid-in capital | 3,275,105 | 3,275,105 |
Retained earnings | 359,795 | 236,578 |
Accumulated other comprehensive income (loss), net of tax | (145,511) | (149,550) |
Total common shareholder’s equity | 3,490,248 | 3,362,992 |
Long-term debt: | ||
First mortgage bonds and senior notes | 3,362,000 | 3,364,412 |
Pollution control bonds | 161,860 | 161,860 |
Junior subordinated notes | 250,000 | 250,000 |
Debt discount, issuance costs and other | (28,974) | (31,910) |
Total long-term debt | 3,744,886 | 3,744,362 |
Total capitalization | 7,235,134 | 7,107,354 |
Current liabilities: | ||
Accounts payable | 317,043 | 259,353 |
Short-term debt | 245,763 | 159,004 |
Current maturities of long-term debt | 2,412 | 0 |
Purchased gas adjustment liability | 0 | 12,589 |
Accrued expenses: | ||
Taxes | 111,428 | 114,854 |
Salaries and wages | 49,749 | 38,457 |
Interest | 48,087 | 47,772 |
Unrealized loss on derivative instruments | 44,170 | 131,420 |
Other | 71,996 | 53,868 |
Total current liabilities | 890,648 | 817,317 |
Other Long-term and regulatory liabilities: | ||
Deferred income taxes | 1,732,390 | 1,556,616 |
Unrealized loss on derivative instruments | 16,261 | 47,776 |
Regulatory liabilities | 653,296 | 651,094 |
Other deferred credits | 769,351 | 619,356 |
Total other long-term and regulatory liabilities | 3,171,298 | 2,874,842 |
Commitments and contingencies (Note 15) | ||
Total capitalization and liabilities | $ 11,297,080 | $ 10,799,513 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Assets: | ||
Construction work in progress | $ 420,278 | $ 408,795 |
Current assets: | ||
Allowance for doubtful accounts | $ 9,798 | $ 9,756 |
Common shareholder’s equity: | ||
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized (in shares) | 1,000 | 1,000 |
Common stock, shares outstanding (in shares) | 200 | 200 |
PUGET SOUND ENERGY, INC. | ||
Assets: | ||
Construction work in progress | $ 420,278 | $ 408,795 |
Current assets: | ||
Allowance for doubtful accounts | $ 9,798 | $ 9,756 |
Common shareholder’s equity: | ||
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 (in shares) | 85,903,791 | 85,903,791 |
CONSOLIDATED STATEMENTS OF COMM
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY - USD ($) $ in Thousands | Total | Common Stock | Additional Paid-in Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | PUGET SOUND ENERGY, INC. | PUGET SOUND ENERGY, INC.Common Stock | PUGET SOUND ENERGY, INC.Additional Paid-in Capital | PUGET SOUND ENERGY, INC.Retained Earnings | PUGET SOUND ENERGY, INC.Accumulated Other Comprehensive Income (Loss) | PUGET SOUND ENERGY, INC.Financial Support, Capital Contributions [Member] |
Balance at Dec. 31, 2013 | $ 3,679,679 | $ 3,308,957 | $ 323,007 | $ 47,715 | $ 3,440,757 | $ 859 | $ 3,246,205 | $ 289,432 | $ (95,739) | ||
Balance (in shares) at Dec. 31, 2013 | 200 | 85,903,791 | |||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||
Net income (loss) | 171,835 | 171,835 | 236,614 | 236,614 | |||||||
Common stock dividend | (223,428) | (223,428) | (323,424) | (323,424) | |||||||
Other comprehensive income (loss) | (84,758) | (84,758) | (75,218) | (75,218) | |||||||
Balance at Dec. 31, 2014 | 3,543,328 | 3,308,957 | 271,414 | (37,043) | 3,278,729 | $ 859 | 3,246,205 | 202,622 | (170,957) | ||
Balance (in shares) at Dec. 31, 2014 | 200 | 85,903,791 | |||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||
Net income (loss) | 241,179 | 241,179 | 304,189 | 304,189 | |||||||
Common stock dividend | (263,059) | (263,059) | (270,233) | (270,233) | |||||||
Proceeds from Contributed Capital | 28,900 | $ 28,900 | |||||||||
Other comprehensive income (loss) | 9,777 | 9,777 | 21,407 | 21,407 | |||||||
Balance at Dec. 31, 2015 | $ 3,531,225 | 3,308,957 | 249,534 | (27,266) | $ 3,362,992 | $ 859 | 3,275,105 | 236,578 | (149,550) | ||
Balance (in shares) at Dec. 31, 2015 | 200 | 200 | 85,903,791 | 85,903,791 | |||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||
Net income (loss) | $ 312,899 | 312,899 | $ 380,581 | 380,581 | |||||||
Common stock dividend | (148,965) | (148,965) | (257,364) | (257,364) | |||||||
Other comprehensive income (loss) | (6,446) | (6,446) | 4,039 | 4,039 | |||||||
Balance at Dec. 31, 2016 | $ 3,688,713 | $ 3,308,957 | $ 413,468 | $ (33,712) | $ 3,490,248 | $ 859 | $ 3,275,105 | $ 359,795 | $ (145,511) | ||
Balance (in shares) at Dec. 31, 2016 | 200 | 200 | 85,903,791 | 85,903,791 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Operating activities: | |||
Net income (loss) | $ 312,899 | $ 241,179 | $ 171,835 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Depreciation | 439,579 | 420,807 | 365,606 |
Conservation amortization | 107,784 | 110,866 | 104,096 |
Deferred income taxes and tax credits, net | 139,640 | 91,978 | 56,984 |
Net unrealized (gain) loss on derivative instruments | (88,704) | (17,255) | 80,139 |
Derivative contracts classified as financing activities due to merger | 0 | (8,045) | (16,349) |
AFUDC - equity | (12,576) | (9,325) | (7,002) |
Funding of pension liability | (24,000) | (18,000) | (18,000) |
Regulatory assets and liabilities | (150,855) | (153,877) | (228,334) |
Other long-term assets and liabilities | 30,459 | 35,270 | 19,691 |
Change in certain current assets and liabilities: | |||
Accounts receivable and unbilled revenue | (21,763) | (66,703) | 153,434 |
Materials and supplies | (28,134) | 4,945 | 4,951 |
Fuel and natural gas inventory | 473 | 9,332 | (2,742) |
Prepayments and other | (25,927) | 4,086 | (2,140) |
Purchased gas adjustment | (15,374) | 33,662 | (27,011) |
Accounts payable | 32,465 | (48,037) | 9,098 |
Taxes payable | (3,426) | 7,072 | (1,777) |
Other | 36,750 | (5,323) | 6,605 |
Net cash provided by (used in) operating activities | 729,290 | 648,722 | 701,782 |
Investing activities: | |||
Construction expenditures - excluding equity AFUDC | (706,444) | (587,225) | (493,130) |
Treasury grant payment received | 0 | 0 | 107,876 |
Proceeds from disposition of assets | 0 | 0 | 20,296 |
Restricted cash | (4,469) | 24,914 | (25,692) |
Other | (1,921) | 754 | (4,512) |
Net cash provided by (used in) investing activities | (712,834) | (561,557) | (395,162) |
Financing activities: | |||
Change in short-term debt, net | 86,759 | 74,004 | (77,000) |
Dividends paid | (148,965) | (263,059) | (223,428) |
Proceeds from long-term debt and bonds issued | 12,481 | 825,000 | 299,000 |
Redemption of bonds and notes | 0 | (711,000) | (299,000) |
Derivative contracts classified as financing activities due to merger | 0 | (8,045) | (16,349) |
Other | 19,653 | 902 | 3,382 |
Net cash provided by (used in) financing activities | (30,072) | (82,198) | (313,395) |
Net increase (decrease) in cash and cash equivalents | (13,616) | 4,967 | (6,775) |
Cash and cash equivalents at beginning of period | 42,494 | 37,527 | 44,302 |
Cash and cash equivalents at end of period | 28,878 | 42,494 | 37,527 |
Supplemental cash flow information: | |||
Cash payments for interest (net of capitalized interest) | 329,603 | 339,866 | 349,402 |
Income Taxes Paid, Net | 0 | 2 | 0 |
Capital Expenditures Incurred but Not yet Paid | 76,813 | 51,588 | 51,776 |
Increase (Decrease) in Regulatory Assets and Liabilities | 176,804 | 0 | 0 |
PUGET SOUND ENERGY, INC. | |||
Operating activities: | |||
Net income (loss) | 380,581 | 304,189 | 236,614 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Depreciation | 439,579 | 420,807 | 365,606 |
Conservation amortization | 107,784 | 110,866 | 104,096 |
Deferred income taxes and tax credits, net | 174,776 | 125,900 | 89,342 |
Net unrealized (gain) loss on derivative instruments | (83,795) | (12,688) | 85,636 |
AFUDC - equity | (12,576) | (9,325) | (7,002) |
Funding of pension liability | (24,000) | (18,000) | (18,000) |
Regulatory assets and liabilities | (149,998) | (153,877) | (228,334) |
Other long-term assets and liabilities | 33,119 | 39,379 | 16,518 |
Change in certain current assets and liabilities: | |||
Accounts receivable and unbilled revenue | (37,385) | (66,547) | 153,626 |
Materials and supplies | (28,134) | 4,945 | 4,951 |
Fuel and natural gas inventory | 473 | 9,332 | (2,742) |
Prepayments and other | (25,927) | 4,089 | (2,140) |
Purchased gas adjustment | (15,374) | 33,662 | (27,011) |
Accounts payable | 32,465 | (48,031) | 9,098 |
Taxes payable | (3,426) | 7,072 | (1,777) |
Other | 30,754 | (12,992) | 4,246 |
Net cash provided by (used in) operating activities | 818,916 | 738,781 | 782,727 |
Investing activities: | |||
Construction expenditures - excluding equity AFUDC | (681,112) | (587,225) | (493,130) |
Treasury grant payment received | 0 | 0 | 107,876 |
Proceeds from disposition of assets | 0 | 0 | 20,296 |
Restricted cash | (4,469) | 24,914 | (25,692) |
Other | 4,156 | 6,386 | (1,683) |
Net cash provided by (used in) investing activities | (681,425) | (555,925) | (392,333) |
Financing activities: | |||
Change in short-term debt, net | 86,759 | 74,004 | (77,000) |
Dividends paid | (257,364) | (270,233) | (323,424) |
Loan from (payment to) parent | 0 | (28,933) | (665) |
Proceeds from Contributions from Parent | 0 | 28,900 | 0 |
Proceeds from long-term debt and bonds issued | 0 | 425,000 | 0 |
Redemption of bonds and notes | 0 | (412,000) | 0 |
Other | 19,739 | 4,796 | 4,050 |
Net cash provided by (used in) financing activities | (150,866) | (178,466) | (397,039) |
Net increase (decrease) in cash and cash equivalents | (13,375) | 4,390 | (6,645) |
Cash and cash equivalents at beginning of period | 41,856 | 37,466 | 44,111 |
Cash and cash equivalents at end of period | 28,481 | 41,856 | 37,466 |
Supplemental cash flow information: | |||
Cash payments for interest (net of capitalized interest) | 227,668 | 242,774 | 253,803 |
Income Taxes Paid, Net | 0 | 2 | 0 |
Capital Expenditures Incurred but Not yet Paid | 76,813 | 51,588 | 51,776 |
Increase (Decrease) in Regulatory Assets and Liabilities | $ 176,804 | $ 0 | $ 0 |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | Summary of Significant Accounting Policies Basis of Presentation Puget Energy, Inc. (Puget Energy) is an energy services holding company that owns Puget Sound Energy, Inc. (PSE). PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering 6,000 square miles, primarily in the Puget Sound region. 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 Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805), 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 PSE’s financial statements do not include any ASC 805 purchase accounting adjustments. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (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. Change in Accounting Principle On January 1, 2016, the Company changed its method of presenting unamortized debt issuance costs in the balance sheet. The new method of presenting debt issuance costs was adopted to comply with Accounting Standards Update (ASU) 2015-03, "Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs" . ASU 2015-03 requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability, consistent with the presentation of a debt discount. The prior year comparative balance sheet has been adjusted to apply the new method retrospectively. Due to the change in accounting principle, the December 31, 2015 financial statement line item “Other long-term assets” decreased and “Debt discount, issuance costs and other” increased 38.4 million and 30.0 million at Puget Energy and PSE, respectively. Utility Plant Puget Energy and PSE capitalize, at original cost, additions to utility plant, including renewals and betterments. Costs include indirect costs such as engineering, supervision, certain taxes, pension and other employee benefits and an allowance for funds used during construction (AFUDC). Replacements of minor items of property are included in maintenance expense. When the utility plant is retired and removed from service, the original cost of the property is charged to accumulated depreciation and costs associated with removal of the property, less salvage, are charged to the cost of removal regulatory liability. Planned Major Maintenance Planned major maintenance is an activity that typically occurs when PSE overhauls or substantially upgrades various systems and equipment on its natural gas fired combustion turbines on a scheduled basis. Costs related to planned major maintenance are deferred and amortized to the next scheduled major maintenance. This accounting method also follows the Washington Utilities and Transportation Commission (Washington Commission) regulatory treatment related to these generating facilities. Non-Utility Property, Plant and Equipment For PSE, the costs of other property, plant and equipment are stated at historical cost. Expenditures for refurbishment and improvements that significantly add to productive capacity or extend useful life of an asset are capitalized. Replacements of minor items are expensed on a current basis. Gains and losses on assets sold or retired, which were previously recorded in utility plant, are apportioned between regulatory assets/liabilities and earnings. However, gains and losses on assets sold or retired, not previously recorded in utility plant, are reflected in earnings. Depreciation and Amortization For financial statement purposes, the Company provides for depreciation and amortization on a straight-line basis. Amortization is recorded for intangibles such as regulatory assets and liabilities, computer software and franchises. The depreciation of vehicles and equipment is allocated to the asset and expense accounts based on usage. The annual depreciation provision stated as a percent of a depreciable electric utility plant was 2.8% , for each of 2016 , 2015 and 2014 ; depreciable natural gas utility plant was 3.4% , for each of 2016 , 2015 and 2014 ; and depreciable common utility plant was 9.7% , 8.5% and 8.5% in 2016 , 2015 and 2014 , respectively. Depreciation on other property, plant and equipment is calculated primarily on a straight-line basis over the useful lives of the assets. The cost of removal is collected from PSE’s customers through depreciation expense and any excess is recorded as a regulatory liability. Goodwill In 2009, Puget Holdings completed its merger with Puget Energy. Puget Energy remeasured the carrying amount of all its assets and liabilities to fair value, which resulted in recognition of approximately $1.7 billion in goodwill. ASC 350, “Intangibles - Goodwill and Other” (ASC 350), requires that goodwill be tested for impairment at the reporting unit level on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. These events or circumstances could include a significant change in the Company’s business or regulatory outlook, legal factors, a sale or disposition of a significant portion of a reporting unit or significant changes in the financial markets which could influence the Company’s access to capital and interest rates. Application of the goodwill impairment test requires judgment, including the identification of reporting units, assignment of assets and liabilities to reporting units, assignment of goodwill to reporting units and the determination of the fair value of the reporting units. Management has determined Puget Energy has only one reporting unit. The goodwill recorded by Puget Energy represents the potential long-term return to the Company’s investors. Goodwill is tested for impairment annually using a two-step process. The first step compares the carrying amount of the reporting unit with its fair value, with a carrying value higher than fair value indicating potential impairment. If the first step test fails, the second step is performed. This would entail a full valuation of Puget Energy’s assets and liabilities and comparing the valuation to its carrying amounts, with the aggregate difference indicating the amount of impairment. Goodwill of a reporting unit is required to be tested for impairment on an interim basis if an event occurs or circumstances change that would cause the fair value of a reporting unit to fall below its carrying amount. Puget Energy conducted its annual impairment test in 2016 using an October 1, 2016 measurement date. The fair value of Puget Energy’s reporting unit was estimated using both discounted cash flow and market approach. Such approaches are considered methodologies that market participants would use. This analysis requires significant judgments, including estimation of future cash flows, which is dependent on internal forecasts, estimation of long-term rate of growth for Puget Energy business, estimation of the useful life over which cash flows will occur, the selection of utility holding companies determined to be comparable to Puget Energy and determination of an appropriate weighted-average cost of capital or discount rate. The market approach estimates the fair value of the business based on market prices of stocks of comparable companies engaged in the same or similar lines of business. In addition, indications of market value are estimated by deriving multiples of equity or invested capital to various measures of revenue, earnings or cash flow. Changes in these estimates and/or assumptions could materially affect the determination of fair value and goodwill impairment of the reporting unit. Based on the test performed, management has determined that there was no indication of impairment of Puget Energy’s goodwill as of October 1, 2016 . There were no known events or circumstances from the date of the assessment through December 31, 2016 that would impact management’s conclusion. Cash and Cash Equivalents Cash and cash equivalents consist of demand bank deposits and short-term highly liquid investments with original maturities of three months or less at the time of purchase. The carrying amounts of cash and cash equivalents are reported at cost and approximate fair value, due to the short-term maturity. Materials and Supplies Materials and supplies are used primarily in the operation and maintenance of electric and natural gas distribution and transmission systems as well as spare parts for combustion turbines used for the generation of electricity. Puget Energy and PSE record these items at weighted-average cost. Fuel and Natural Gas Inventory Fuel and natural gas inventory is used in the generation of electricity and for future sales to the Company’s natural gas customers. Fuel inventory consists of coal, diesel and natural gas used for generation. Natural gas inventory consists of natural gas and liquefied natural gas (LNG) held in storage for future sales. Puget Energy and PSE record these items at the lower of cost or market value using the weighted-average cost method. Regulatory Assets and Liabilities PSE accounts for its regulated operations in accordance with ASC 980, “Regulated Operations” (ASC 980). ASC 980 requires PSE to defer certain costs that would otherwise be charged to expense, if it is probable that future rates will permit recovery of such costs. It similarly requires deferral of revenues or gains and losses that are expected to be returned to customers in the future. Accounting under ASC 980 is appropriate as long as rates are established by or subject to approval by independent third-party regulators; rates are designed to recover the specific enterprise’s cost of service; and in view of demand for service, it is reasonable to assume that rates set at levels that will recover costs can be charged to and collected from customers. In most cases, PSE classifies regulatory assets and liabilities as long-term due to the length of the amortization. For further details regarding regulatory assets and liabilities, see Note 3, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report. Puget Energy recorded regulatory assets and liabilities at the time of the merger related to power purchase contracts. Allowance for Funds Used During Construction AFUDC represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period. The amount of AFUDC recorded in each accounting period varies depending primarily upon the level of construction work in progress and the AFUDC rate used. AFUDC is capitalized as a part of the cost of utility plant; the AFUDC debt portion is credited to interest expense, while the AFUDC equity portion is credited to other income. Cash inflow related to AFUDC does not occur until these charges are reflected in rates. The current AFUDC rate authorized by the Washington Commission for natural gas and electric utility plant additions as of July 1, 2013 is 7.77% . The Washington Commission authorized the Company to calculate AFUDC using its allowed rate of return. To the extent amounts calculated using this rate exceed the AFUDC calculated rate using the Federal Energy Regulatory Commission (FERC) formula, PSE capitalizes the excess as a deferred asset, crediting other income. The deferred asset is being amortized over the average useful life of PSE’s non-project electric utility plant which is approximately 30 years . Revenue Recognition Operating utility revenue is recognized when the basis of services is rendered, which includes estimated unbilled revenue, in accordance with ASC 605, “Revenue Recognition” (ASC 605). PSE's estimate of unbilled revenue is based on a calculation using meter readings from its automated meter reading (AMR) system. The estimate calculates unbilled usage at the end of each month as the difference between the customer meter readings on the last day of the month and the last customer meter readings billed. The unbilled usage is then priced at published rates for each schedule to estimate the unbilled revenues by customer. PSE collected Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes totaling $235.3 million , $234.2 million and $231.7 million for 2016 , 2015 and 2014 , respectively. The Company reports the collection of such taxes on a gross basis in operation revenue and as expense in taxes other than income taxes in the accompanying consolidated statements of income. The non-utility subsidiary recognizes revenue when services are performed or upon the sale of assets. Revenue from retail sales is billed based on tariff rates approved by the Washington Commission. PSE's electric and natural gas operations contain a revenue decoupling mechanism under which PSE's actual energy delivery revenues related to electric transmission and distribution, natural gas operations and general administrative costs are compared with authorized revenues allowed under the mechanism. The mechanism mitigates volatility in revenue due to weather and gross margin erosion related to energy efficiency. Any differences in revenue are deferred to a regulatory asset for under recovery or regulatory liability for over recovery under alternative revenue recognition standard. To record revenues under this program, the Company must be able to collect the revenue within 24 months based on alternative revenue recognition guidance. Decoupled rate increases are effective May 1 of each year subject to a 3.0% cap of total revenue for decoupled rate schedules. Any excess revenue above 3.0% will be included in the following year's decoupled rate. The Company will be able to recognize revenue below the 3.0% cap of total revenue for decoupled rate schedules. For revenue deferrals exceeding the annual 3.0% rate cap of total revenue for decoupled rate schedules, the Company will assess the excess amount to determine its ability to be collected within 24 months. For GAAP purposes only, the Company will not record any decoupling revenue that is expected to take longer than 24 months to collect following the end of the annual period in which the revenues would have otherwise been recognized. Once determined to be collectible within 24 months, any previously non-recorded amounts will be recorded. Revenues associated with energy costs under the power cost adjustment (PCA) mechanism and purchased gas adjustment (PGA) mechanism are excluded from the decoupling mechanism. Allowance for Doubtful Accounts Allowance for doubtful accounts are provided for electric and natural gas customer accounts based upon a historical experience rate of write-offs of energy accounts receivable along with information on future economic outlook. The allowance account is adjusted monthly for this experience rate. The allowance account is maintained until either receipt of payment or the likelihood of collection is considered remote at which time the allowance account and corresponding receivable balance are written off. The Company’s balance for allowance for doubtful accounts at December 31, 2016 and 2015 was $9.8 million each year. Self-Insurance PSE is self-insured for storm damage and environmental contamination occurring on PSE-owned property. In addition, PSE is required to meet a deductible for a portion of the risk associated with comprehensive liability, workers’ compensation claims and catastrophic property losses other than those which are storm related. The Washington Commission has approved the deferral of certain uninsured qualifying storm damage costs that exceed $8.0 million which will be requested for collection in future rates. Additionally, costs may only be deferred if the outage meets the Institute of Electrical and Electronics Engineers (IEEE) outage criteria for system average interruption duration index. Federal Income Taxes For presentation in Puget Energy's and PSE’s separate financial statements, income taxes are allocated to the subsidiaries on the basis of separate company computations of tax, modified by allocating certain consolidated group limitations which are attributed to the separate company. Taxes payable or receivable are settled with Puget Holdings, who is the ultimate tax payer. Natural Gas Off-System Sales and Capacity Release PSE contracts for firm natural gas supplies and holds firm transportation and storage capacity sufficient to meet the expected peak winter demand for natural gas by its firm customers. Due to the variability in weather, winter peaking consumption of natural gas by most of its customers and other factors, PSE holds contractual rights to natural gas supplies and transportation and storage capacity in excess of its average annual requirements to serve firm customers on its distribution system. For much of the year, there is excess capacity available for third-party natural gas sales, exchanges and capacity releases. PSE sells excess natural gas supplies, enters into natural gas supply exchanges with third parties outside of its distribution area and releases to third parties excess interstate natural gas pipeline capacity and natural gas storage rights on a short-term basis to mitigate the costs of firm transportation and storage capacity for its core natural gas customers. The proceeds from such activities, net of transactional costs, are accounted for as reductions in the cost of purchased natural gas and passed on to customers through the PGA mechanism, with no direct impact on net income. As a result, PSE nets the sales revenue and associated cost of sales for these transactions in purchased natural gas. Non-Core Natural Gas Sales As part of the Company’s electric operations, PSE purchases natural gas for its gas-fired generation facilities. The projected volume of natural gas for power is relative to the price of natural gas. Based on the market prices for natural gas, PSE may use the natural gas it has already purchased to generate power or PSE may sell the already purchased natural gas. The net proceeds from selling natural gas, previously purchased for power generation, are accounted for in electric operating revenue and are included in the PCA mechanism. Production Tax Credit Production Tax Credits (PTCs) represent federal income tax incentives available to taxpayers that generate energy from qualifying renewable sources. PSE records the benefit of the PTCs as a deferred credit until such time as PSE utilizes the tax credit on its tax return. Once utilized, PSE will reclassify the credits to a regulatory liability and pass the benefit to customers. Accounting for Derivatives ASC 815 requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair value unless the contracts qualify for an exception. PSE enters into derivative contracts to manage its energy resource portfolio and interest rate exposure including forward physical and financial contracts and swaps. Some of PSE’s physical electric supply contracts qualify for the normal purchase normal sale (NPNS) exception to derivative accounting rules. PSE may enter into financial fixed price contracts to economically hedge the variability of certain index-based contracts. Those contracts that do not meet the NPNS exception are marked-to-market to current earnings in the statements of income, subject to deferral under ASC 980, for natural gas related derivatives due to the PGA mechanism. Puget Energy and PSE elected to de-designate all energy related derivative contracts previously recorded as cash flow hedges for the purpose of simplifying its financial reporting. The contracts that were de-designated related to physical electric supply contracts and natural gas swap contracts used to fix the price of natural gas for electric generation. For these contracts and for contracts initiated after such date, all mark-to-market adjustments are recognized through earnings. The amount previously recorded in accumulated other comprehensive income (AOCI) is transferred to earnings in the same period or periods during which the hedged transaction affects earnings or sooner if management determines that the forecasted transaction is probable of not occurring. When these contracts are settled, the contract price becomes part of purchased electricity or electric generation fuel which becomes part of PSE’s PCA mechanism and the unrealized gain or loss is listed separately under energy costs, as it represents the non-rate treatment of energy costs. The Company may enter into swap instruments or other financial derivative instruments to manage the interest rate risk associated with its long-term debt financing and debt instruments. As of December 31, 2016 , Puget Energy has interest rate swap contracts outstanding originally related to its long-term debt. For additional information, see Note 9 , "Accounting for Derivative Instruments and Hedging Activities" to the consolidated financial statements included in Item 8 of this report. Fair Value Measurements of Derivatives ASC 820, “Fair Value Measurements and Disclosures” (ASC 820), defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). As permitted under ASC 820, the Company utilizes a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing the majority of its assets and liabilities measured and reported at fair value. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company primarily applies the market approach for recurring fair value measurements as it believes that the approach is used by market participants for these types of assets and liabilities. Accordingly, the Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company values derivative instruments based on daily quoted prices from an independent external pricing service. When external quoted market prices are not available for derivative contracts, the Company uses a valuation model that uses volatility assumptions relating to future energy prices based on specific energy markets and utilizes externally available forward market price curves. All derivative instruments are sensitive to market price fluctuations that can occur on a daily basis. For additional information, see Note 10 , "Fair Value Measurements" to the consolidated financial statements included in Item 8 of this report. Debt Related Costs Debt premiums, discounts, expenses and amounts received or incurred to settle hedges are amortized over the life of the related debt for the Company. The premiums and costs associated with reacquired debt are deferred and amortized over the life of the related new issuance, in accordance with ratemaking treatment for PSE. |
New Accounting Pronouncements
New Accounting Pronouncements | 12 Months Ended |
Dec. 31, 2016 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
New Accounting Pronouncements | New Accounting Pronouncements Revenue Recognition In May 2014, the FASB issued ASU No. 2014-09, "Revenue from Contracts with Customers (Topic 606)". ASU 2014-09 and the related amendments outline a single comprehensive model for use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The ASU is based on the principle that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The ASU also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to fulfill a contract. In August 2015, the FASB issued ASU 2015-14, "Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date," deferring the effective date for ASU 2014-09 to fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. In addition to the FASB's deferral decision, FASB provided reporting entities with an option to adopt ASU 2014-09 for the fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, the original effective date. The Company plans to adopt ASU 2014-09 during the first quarter of fiscal year 2018. Reporting entities have the option of using either a full retrospective or a modified retrospective approach for the adoption of the new standard. At this time, the Company has not yet selected a transition method; however, it is in the process of completing its analysis and expects to decide in early 2017. Additionally, the Company initiated a steering committee and project team to evaluate the impact of this standard, update any policies and procedures that may be affected, and implement the new revenue recognition guidance. After a substantial evaluation of this standard, the Company does not anticipate significant impacts to its results of operations or on its consolidated financial statements. The Company is still waiting on the resolution of certain industry implementation issues, including contributions in aid of construction (CIAC), to determine the full impact. The Company is anticipating additional disclosures related to the implementation of the new standard. Lease Accounting In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)". ASU 2016-02 requires lessees to recognize the following for all leases (with the exception of short-term leases) at the commencement date: (i) a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and (ii) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Under the new guidance, lessor accounting is largely unchanged. This amendment is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Earlier adoption is permitted for all entities upon issuance. Reporting entities must apply a modified retrospective approach for the adoption of the new standard. The Company plans to adopt ASU 2016-02 during the first quarter of fiscal year 2019. At this time, the Company plans to initiate a steering committee and project team to evaluate the impact this standard will have on its results of operations and consolidated financial statements. Derivatives and Hedging In March 2016, the FASB issued ASU 2016-06, "Derivatives and Hedging (Topic 815): Contingent Put and Call Options in Debt Instruments". Topic 815 requires that embedded derivatives be separated from the host contract and accounted for separately as derivatives if certain criteria are met, including the “clearly and closely related” criterion. ASU 2016-06 clarifies the requirements for assessing whether contingent call or put options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. An entity performing the assessment under the amendment is required to assess the embedded call or put options solely in accordance with the four-step decision sequence. This amendment is effective for financial statements issued for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. Earlier adoption is permitted for all entities upon issuance. Reporting entities must apply a modified retrospective approach for the adoption of the new standard. The Company plans to adopt ASU 2016-06 during the first quarter of fiscal year 2017. The Company anticipates the new guidance will not have a significant impact on its financial statements. Statement of Cash Flows In August 2016, the FASB issued ASU 2016-15, "Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments". The amendments in ASU 2016-15 provide guidance for eight specific cash flow issues that include (i) debt prepayment or debt extinguishment costs, (ii) settlement of zero-coupon debt instruments, (iii) contingent consideration payments made after a business combination, (iv) proceeds from the settlement of insurance claims, (v) proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, (vi) distribution received from equity method investees, (vii) beneficial interest in securitization transactions, and (viii) separately identifiable cash flows and application of the predominance principle. Current GAAP is unclear or does not include specific guidance on the eight cash flow classification issues included in the amendments. This update is effective for financial statements issued for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted for all entities upon issuance. The amendments in this update should be applied using a retrospective transition method to each period presented. The Company plans to adopt ASU 2016-15 during the first quarter of fiscal year 2018 and is in the process of evaluating the impact this standard will have on its consolidated statement of cash flows. In November 2016, the FASB issued ASU 2016-18, "Statement of Cash Flows (Topic 230): Restricted Cash". The amendments in this update require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. The new standard is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years beginning after December 15, 2018. The Company plans to adopt ASU 2016-18 during the first quarter of fiscal year 2018 and does not anticipate the new guidance will have a significant impact on its consolidated statement of cash flows. |
Regulation and Rates
Regulation and Rates | 12 Months Ended |
Dec. 31, 2016 | |
Regulated Operations [Abstract] | |
Regulation and Rates | Regulation and Rates Regulatory Assets and Liabilities Regulatory accounting allows PSE to defer certain costs that would otherwise be charged to expense, if it is probable that future rates will permit recovery of such costs. It similarly requires deferral of revenues or gains that are expected to be returned to customers in the future. The net regulatory assets and liabilities at December 31, 2016 and 2015 included the following: Puget Sound Energy Remaining Amortization Period December 31, (Dollars in Thousands) 2016 2015 Colstrip Regulatory Asset (a) $ 176,804 $ — Storm damage costs electric 1 to 2 years 122,709 125,777 Chelan PUD contract initiation 14.8 years 105,140 112,228 Decoupling deferrals and interest 156,408 104,150 Decoupling 24-month revenue reserve (20,847 ) (9,980 ) Total decoupling asset Less than 2 years 135,561 94,170 Lower Snake River 1 to 20.3 years 74,862 79,599 Deferred income taxes (a) 71,517 72,694 Environmental remediation (a) 74,557 66,887 Baker Dam licensing operating and maintenance costs 42 years 61,453 63,394 PGA deferral of unrealized losses on derivative instruments (a) — 60,889 Deferred Washington Commission AFUDC 35 years 51,404 52,197 Unamortized loss on reacquired debt 1 to 30 years 42,196 44,984 Property tax tracker Less than 2 years 41,949 40,353 Energy conservation costs 1 to 2 years 41,027 36,646 White River relicensing and other costs 15.9 years 21,627 23,054 Mint Farm ownership and operating costs 8.3 years 16,319 18,320 Ferndale 2.8 years 11,274 15,253 Electron unrecovered loss 2 years 7,178 10,569 Snoqualmie licensing operating and maintenance costs 28 years 8,018 7,980 Colstrip common property (a) 5,334 6,049 Colstrip major maintenance 2 years 6,589 5,897 Investment in Bonneville Exchange power contract 1 year 1,763 5,290 Snoqualmie 1.8 years 3,251 5,024 PCA mechanism (a) 4,531 — PGA receivable 1 year 2,785 — Various other regulatory assets Varies 25,337 24,248 Total PSE regulatory assets 1,113,185 971,502 Cost of removal (b) (369,300 ) (347,472 ) Treasury grants 3 to 42 years (133,709 ) (157,102 ) Production tax credits (c) (93,616 ) (93,616 ) Decoupling ROR excess earnings (13,300 ) (25,483 ) Decoupling deferrals and interest (16,448 ) — Total decoupling liability Less than 2 years (29,748 ) (25,483 ) PGA payable 1 year — (12,589 ) Summit purchase option buy-out 3.8 years (6,038 ) (7,612 ) Deferral of treasury grant amortization Less than 3 years (3,920 ) (6,058 ) PGA deferral of unrealized gains on derivative instruments (a) (7,517 ) — Lower Snake River interest due Less than 2 years (4,189 ) — Various other regulatory liabilities Up to 4 years (5,259 ) (13,751 ) Total PSE regulatory liabilities (653,296 ) (663,683 ) PSE net regulatory assets (liabilities) $ 459,889 $ 307,819 _______________ (a) Amortization periods vary depending on timing of underlying transactions or awaiting regulatory approval in a future Washington Commission rate proceeding. (b) The balance is dependent upon the cost of removal of underlying assets and the life of utility plant. (c) Amortization will begin once PTCs are utilized by PSE on its tax return. Puget Energy Remaining Amortization Period December 31, (Dollars in Thousands) 2016 2015 Total PSE regulatory assets (a) $ 1,113,185 $ 971,502 Puget Energy acquisition adjustments: Regulatory assets related to power contracts 1 to 21 years 22,613 26,223 Various other regulatory assets Varies 517 549 Total Puget Energy regulatory assets 1,136,315 998,274 Total PSE regulatory liabilities (a) (653,296 ) (663,683 ) Puget Energy acquisition adjustments: Regulatory liabilities related to power contracts 1 to 36 years (275,061 ) (325,788 ) Various other regulatory liabilities Varies (1,326 ) (1,347 ) Total Puget Energy regulatory liabilities (929,683 ) (990,818 ) Puget Energy net regulatory asset (liabilities) $ 206,632 $ 7,456 _______________ (a) Puget Energy’s regulatory assets and liabilities include purchase accounting adjustments under ASC 805. If the Company determines that it no longer meets the criteria for continued application of ASC 980, the Company would be required to write-off its regulatory assets and liabilities related to those operations not meeting ASC 980 requirements. Discontinuation of ASC 980 could have a material impact on the Company’s financial statements. In accordance with guidance provided by ASC 410, “Asset Retirement and Environmental Obligations (ARO),” PSE reclassified from accumulated depreciation to a regulatory liability $369.3 million and $347.5 million in 2016 and 2015 , respectively, for the cost of removal of utility plant. These amounts are collected from PSE’s customers through depreciation rates. 2013 Expedited Rate Filing, Decoupling and Centralia Decision PSE filed a settlement agreement with the Washington Commission on March 22, 2013. The agreement was intended to settle all issues regarding decoupling, a power purchase agreement with TransAlta Centralia and the Expedited Rate Filing (ERF) which is limited in scope and rate impact, includes the property tax tracker, and is intended to establish baseline rates on which the decoupling mechanisms are to operate. The Washington Commission placed the ERF and decoupling filings under a common procedural schedule. On June 25, 2013, the Washington Commission issued final orders resolving the amended decoupling petition, the ERF filing and the Petition for Reconsideration (related to the TransAlta Centralia power purchase agreement). Order No. 7 in the ERF/decoupling proceeding approved PSE's ERF filing with a small change to its cost of capital from 7.80% to 7.77% to update long term debt costs and a capital structure that included 48.0% common equity with a return on equity (ROE) of 9.8% . This order also approved the property tax tracker discussed below and approved the amended decoupling and rate plan filing with the further condition that PSE and the customers will share 50.0% each in earnings in excess of the 7.77% authorized rate of return. In addition, the rate plan (K-Factor) increase allowed decoupling revenue per customer for the recovery of delivery system costs to subsequently increase by 3.0% for the electric customers and 2.2% for the natural gas customers on January 1 of each year, until the conclusion of PSE's next General Rate Case (GRC), which was filed on January 13, 2017. In the rate plan, increases are subject to a cap of 3.0% of the total revenue for customers. General Rate Case Filing On March 17, 2016, the Washington Commission approved a joint petition postponing the filing of PSE’s GRC until no later than January 17, 2017. As part of the petition, PSE agreed to update power costs on December 1, 2016 in conjunction with the Centralia PPA compliance filing. Additionally, PSE agreed to include in its GRC filing a plan for closure of coal fired steam electric generation facility in Colstrip, Montana (Colstrip) Units 1 and 2, of which PSE owns a 50% interest. Monthly allowed revenue per customer includes an automatic annual increase and will continue through December 2017 when new rates go into effect from PSE's 2017 GRC. On January 13, 2017, PSE filed its GRC with the Washington Commission which proposed a weighted cost of capital of 7.74% , or 6.69% after-tax, and a capital structure of 48.5% in common equity with a return on equity of 9.8% . The requested combined electric tariff changes would result in a net increase of $86.3 million or 4.1% . The requested combined natural gas tariff changes would result in a net decrease of $22.3 million , or 2.4% . The filing was subsequently suspended, which means that the final rates granted in the proceeding will go into effect no later than December 13, 2017. PSE’s GRC filing included the required plan for Colstrip Units 1 and 2 closures, see Item 3, "Legal Proceedings" to the consolidated financial statements included in Item 8 of this report. Additionally, PSE’s filing contains requests for two new mechanisms to address regulatory lag. PSE has requested procedures for an ERF that can be used to update PSE’s delivery revenues on an expedited basis following a GRC proceeding. PSE also requested approval to establish an electric CRM similar to its existing natural gas CRM which would allow PSE to obtain accelerated cost recovery on specified electric reliability projects. 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 are expected to mitigate the impact of weather on operating revenue and net income. 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 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 will be recovered on a per customer basis regardless of actual consumption levels. The 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 or refund the difference between allowed decoupling revenue and the corresponding actual revenue to affected customers over a 12-month period beginning the following May. The decoupling mechanism will end on December 31, 2017 unless the continuation of the requested mechanism is approved in PSE's 2017 GRC which PSE filed on January 13, 2017. Decoupling over and under collections will still be collectible or refundable after December 31, 2017, even if the decoupling mechanism is not extended. The Washington Commission approved the following PSE requests to change rates under its electric and natural gas decoupling mechanisms: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) Electric: May 1, 2016 1.0% $20.8 May 1, 2015 2.6 53.8 May 1, 2014 0.5 10.6 Natural Gas: May 1, 2016 2.8% $25.4 May 1, 2015 2.1 22.0 May 1, 2014 (0.1) (1.0) As part of the April 22, 2015 filing, PSE requested to change the methodology of how decoupling deferrals are calculated going forward and adjust deferrals calculated in 2014. The change was done to ensure that the amortization of prior years’ accumulated decoupling deferrals were not included in the calculation of the current year decoupling deferrals. The effect of the methodology change was a reduction of approximately $12.0 million of previously recognized revenue from May through December of 2014. In addition, PSE exceeded the earnings test threshold in 2016, 2015 and 2014. The amount of the reduction to the 2016 decoupling deferral will not be known until the final earnings test result is filed in PSE's decoupling mechanism filing that will be made on March 31, 2017. PSE recorded the following reductions in decoupling deferrals to the electric and natural gas rate increases above: Effective Date Reduction in Rate Increases due to Excess Earnings (Dollars in Millions) Electric: 2016 (estimated) $11.2 2015 16.3 2014 3.4 Natural Gas: 2016 (estimated) $2.1 2015 9.2 2014 — As noted earlier, the Company is also limited to a 3.0% annual decoupling related cap on increases in total revenue. This limitation has been triggered as follows: Effective Date Accrued Through Deferrals not Included in Annual Rate Increases (Dollars in Millions) Electric: 2015 $— 2014 1.9 Natural Gas: 2015 $28.7 2014 8.2 Existing deferrals may be included in customer rates beginning in May 2018, subject to subsequent application of the earnings test and the 3.0% cap on decoupling related rate increases. Electric Regulation and Rates Storm Damage Deferral Accounting The Washington Commission issued a GRC order that defined deferrable catastrophic/extraordinary losses and provided that costs in excess of $8.0 million annually may be deferred for qualifying storm damage costs that meet the modified IEEE outage criteria for system average interruption duration index. In 2016 and 2015 , PSE incurred $22.0 million and $33.6 million , respectively, in storm-related electric transmission and distribution system restoration costs, of which $12.4 million was deferred in 2016 and $22.4 million was deferred in 2015 . 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. The graduated scale that was applicable through December 31, 2016 was as follows: Annual Power Cost Variability Company’s Share Customers' Share +/- $20 million 100% —% +/- $20 million - $40 million 50 50 +/- $40 million - $120 million 10 90 +/- $120 + million 5 95 On August 7, 2015, the Washington Commission issued an order approving the settlement proposing changes to the PCA mechanism. The settlement agreement took effect January 1, 2017 and will apply the following graduated scale: Annual Power Cost Variability Company's Share Customers' Share Over or Under Collection: 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 The settlement also resulted in the following changes to the PCA mechanism: • Reduction to the cumulative deferral trigger for surcharge or refund from $30.0 million to $20.0 million ; • Removal of fixed production costs from the PCA mechanism and placing them in the decoupling mechanism, assuming the decoupling mechanism continues after its review in the 2017 GRC. If decoupling was not to continue, those fixed production costs would be treated the same as other non-PCA costs unless permission to treat them in another manner is obtained from the Washington Commission. These fixed production costs include: (i) return and depreciation/amortization on fixed production assets and regulatory assets and liabilities; (ii) return on depreciation, transmission expense and revenues on specific transmission assets; and (iii) hydro, other production and other power related expenses and O&M costs; • Suspension of the requirement that a GRC must be filed within three months after rates are approved in a Power Cost Only Rate Case (PCORC); • Agreement, for a five-year period, that PSE will not file a GRC or PCORC within six months of the date rates go into effect for a PCORC filing; and • Establishment of a five-year moratorium on changes to the PCA. PSE had an annual PCA receivable during the year ended December 31, 2016 , due to under recovering $1.0 million of power costs of which no amounts were apportioned to customers. This compares to an annual PCA receivable of $8.7 million for the year ended December 31, 2015 of which no amounts were apportioned to customers. The change was driven by a decrease in actual costs. Federal Incentive Tracker Tariff The following table sets forth Federal Incentive Tracker Tariff rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates from prior year Total credit to be passed back to eligible customers (Dollars in Millions) January 1, 2017, proposed 0.3% $(51.7) January 1, 2016 (0.2) (57.3) January 1, 2015 (0.2) (55.2) January 1, 2014 (0.3) (58.5) Power Cost Only Rate Case and Update Compliance Filing The following table sets forth PCORC and update compliance filing rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) December 1, 2016 (1.7)% $(37.3) December 1, 2014 (0.9) (19.4) Electric Property Tax Tracker Mechanism The following table sets forth property tax tracker mechanism rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) May 1, 2016 0.3% $5.7 May 1, 2015 0.3 6.5 May 1, 2014 0.5 11.0 Electric Conservation Rider The following table sets forth conservation rider rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) May 1, 2017, proposed 0.7% $16.5 May 1, 2016 (0.5) (11.7) May 1, 2015 0.2 4.2 May 1, 2014 0.6 12.2 Accounting Orders and Petitions PSE completed the sale of its electric infrastructure assets located in Jefferson County and the transition of electrical services in the county to Jefferson County Public Utility District (JPUD) on March 31, 2013. The proceeds from the sale exceeded the transferred assets' net carrying value of $46.7 million resulting in a pre-tax gain of approximately $60.0 million . A final order was rendered on September 11, 2014 which authorized PSE to retain $7.5 million of the gain and return $52.7 million to customers. The customer portion was booked to a regulatory liability account in other current liabilities and accrued interest at PSE's after-tax rate of return. PSE paid this amount to customers through a bill credit in the month of December 2014. Natural Gas Regulation and Rates Natural Gas General Rate Cases and Other Filings Affecting Rates Purchased Gas Adjustment The following table sets forth PGA rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) November 1, 2016 (0.4)% $(4.1) November 1, 2015 (17.4) (185.9) November 1, 2014 2.5 23.3 Cost Recovery Mechanism The following table sets forth CRM rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) November 1, 2016 0.6% $5.6 November 1, 2015 0.5 5.3 November 1, 2014 0.2 2.3 Natural Gas Property Tax Tracker Mechanism The following table sets forth property tax tracker mechanism rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) May 1, 2016 0.4% $3.5 June 1, 2015 (0.2) (2.3) May 1, 2014 0.6 5.6 Natural Gas Conservation Rider The following table sets forth conservation rider rate adjustments approved by the Washington Commission and the corresponding annual impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) May 1, 2017, proposed (0.1)% (1.0) May 1, 2016 0.3 2.9 May 1, 2015 0.2 2.3 Environmental Remediation The Company is subject to environmental laws and regulations by the federal, state and local authorities and is required to undertake certain environmental investigative and remedial efforts as a result of these laws and regulations. The Company has been named by the environmental protection agency (EPA), the Washington State Department of Ecology and/or other third parties as potentially responsible at several contaminated sites and manufactured gas plant sites. PSE has implemented an ongoing program to test, replace and remediate certain underground storage tanks (UST) as required by federal and state laws. The UST replacement component of this effort is finished, but PSE continues its work remediating and/or monitoring relevant sites. During 1992, the Washington Commission issued orders regarding the treatment of costs incurred by the Company for certain sites under its environmental remediation program. The orders authorize the Company to accumulate and defer prudently incurred cleanup costs paid to third parties for recovery in rates established in future rate proceedings, subject to Washington Commission review. The Washington Commission consolidated the natural gas and electric methodological approaches to remediation and deferred accounting in an order issued October 8, 2008. In accordance with the guidance of ASC 450, “Contingencies,” the Company reviews its estimated future obligations and will record adjustments, if any, on a quarterly basis. Management believes it is probable and reasonably estimable that the impact of the potential outcomes of disputes with certain property owners and other potentially responsible parties will result in environmental remediation costs of $38.0 million for natural gas and $6.2 million for electric. The Company believes a significant portion of its past and future environmental remediation costs are recoverable from insurance companies, from third parties or from customers under a Washington Commission order. The Company is also subject to cost-sharing agreements with third parties regarding environmental remediation projects in Seattle, Washington and Bellingham, Washington. The Company has taken the lead for both projects, and as of December 31, 2016 , the Company’s share of future remediation costs is estimated to be approximately $24.9 million . The Company's deferred electric environmental costs are $13.8 million , $14.0 million and $13.4 million at December 31, 2016 , 2015 and 2014 , respectively, net of insurance proceeds. The Company's deferred natural gas environmental costs are $60.7 million , $52.9 million , and $52.6 million at December 31, 2016 , 2015 and 2014 , respectively, net of insurance proceeds. In the pending GRC, the Company has requested to ratebase remediation costs incurred, net of insurance, and third party recoveries. |
Dividend Payment Restrictions
Dividend Payment Restrictions | 12 Months Ended |
Dec. 31, 2016 | |
Dividend Payment Restrictions [Abstract] | |
Dividend Payment Restrictions | Dividend Payment Restrictions The payment of dividends by PSE to Puget Energy is restricted by provisions of certain covenants applicable to long-term debt contained in PSE’s electric and natural gas mortgage indentures. At December 31, 2016 , approximately $532.9 million of unrestricted retained earnings was available for the payment of dividends under the most restrictive mortgage indenture covenant. Pursuant to the terms of the Washington Commission merger order, PSE may not declare or pay dividends if PSE’s common equity ratio, calculated on a regulatory basis, is 44.0% or below except to the extent a lower equity ratio is ordered by the Washington Commission. Also, pursuant to the merger order, PSE may not declare or make any distribution unless on the date of distribution PSE’s corporate credit/issuer rating is investment grade, or, if its credit ratings are below investment grade, PSE’s ratio of earnings before interest, tax, depreciation and amortization (EBITDA) to interest expense for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than 3.0 to 1.0 . The common equity ratio, calculated on a regulatory basis, was 47.9% at December 31, 2016 , and the EBITDA to interest expense was 5.2 to 1.0 for the twelve months ended December 31, 2016 . PSE’s ability to pay dividends is also limited by the terms of its credit facilities, pursuant to which PSE is not permitted to pay dividends during any Event of Default (as defined in the facilities), or if the payment of dividends would result in an Event of Default, such as failure to comply with certain financial covenants. Puget Energy’s ability to pay dividends is also limited by the merger order issued by the Washington Commission. Pursuant to the merger order, Puget Energy may not declare or make a distribution unless on such date Puget Energy’s ratio of consolidated EBITDA to consolidated interest expense for the four most recently ended fiscal quarters prior to such date is equal to or greater than 2.0 to 1.0 . Puget Energy's EBITDA to interest expense was 3.5 to 1.0 for the twelve months ended December 31, 2016 . At December 31, 2016 , the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends. |
Utility Plant
Utility Plant | 12 Months Ended |
Dec. 31, 2016 | |
Utility Plant [Abstract] | |
Utility Plant | Utility Plant The following table presents electric, natural gas and common utility plant classified by account: Puget Energy Puget Sound Energy Utility Plant Estimated Useful Life At December 31, At December 31, (Dollars in Thousands) (Years) 2016 2015 2016 2015 Distribution plant 10-50 $ 5,287,542 $ 5,007,077 $ 6,922,176 $ 6,657,597 Production plant 25-125 3,007,546 3,028,481 3,910,129 3,950,231 Transmission plant 45-65 1,307,687 1,236,823 1,420,334 1,351,216 General plant 5-35 541,424 491,845 611,237 563,850 Intangible plant (including capitalized software) 3-50 347,697 305,705 338,327 294,380 Plant acquisition adjustment 2-22 242,826 242,826 282,792 282,792 Underground storage 25-60 30,695 28,914 44,206 42,545 Liquefied natural gas storage 25-45 12,628 12,628 14,498 14,498 Plant held for future use NA 52,484 55,890 52,636 56,042 Recoverable Cushion Gas NA 8,655 8,655 8,655 8,655 Plant not classified 1-125 159,345 65,892 159,345 65,892 Grant NA (99,100 ) (102,379 ) (99,100 ) (102,379 ) Capital leases, net of accumulated amortization 1 2 645 378 645 378 Less: accumulated provision for depreciation (2,161,796 ) (1,878,868 ) (4,927,602 ) (4,681,830 ) Subtotal $ 8,738,278 $ 8,503,867 $ 8,738,278 $ 8,503,867 Construction work in progress NA 420,278 408,795 420,278 408,795 Net utility plant $ 9,158,556 $ 8,912,662 $ 9,158,556 $ 8,912,662 _______________ 1 Accumulated amortization of capital leases at Puget Energy and PSE was $0.6 million in 2016 and $32.3 million in 2015 . Jointly owned generating plant service costs are included in utility plant service cost at the Company's ownership share. The following table indicates the Company’s percentage ownership and the extent of the Company’s investment in jointly owned generating plants in service at December 31, 2016 . These amounts are also included in the Utility Plant table above. Puget Energy’s Share Puget Sound Energy’s Share Jointly Owned Generating Plants (Dollars in Thousands) Energy Source (Fuel) Company’s Ownership Share Plant in Service at Cost Accumulated Depreciation Plant in Service at Cost Accumulated Depreciation Colstrip Units 1 & 2 Coal 50% $ 70,717 $ (22,284 ) $ 204,334 $ (155,902 ) Colstrip Units 3 & 4 Coal 25% 307,383 (40,343 ) 575,902 (308,861 ) Colstrip Units 1 – 4 Common Facilities Coal various 83 (27 ) 252 (196 ) Frederickson 1 Natural Gas 49.85% 61,780 (9,779 ) 70,729 (18,728 ) Jackson Prairie Natural Gas Storage 33.34% 30,021 (5,544 ) 44,206 (19,730 ) Asset Retirement Obligation The Company has recorded liabilities for steam generation sites, combustion turbine generation sites, wind generation sites, distribution and transmission poles, gas mains, and leased facilities where disposal is governed by ASC 410 “ARO”. On April 17, 2015, the United States EPA published a final rule, effective October 19, 2015, that regulates Coal Combustion Residuals (CCR) under the Resource Conservation and Recovery Act, Subtitle D. The CCR ruling requires the Company to perform an extensive study on the effects of coal ash on the environment and public health. The rule addresses the risks from coal ash disposal, such as leaking of contaminants into ground water, blowing of contaminants into the air as dust, and the catastrophic failure of coal ash surface impoundments. The CCR rule and two new legal agreements which include a consent decree with the Sierra Club and a settlement agreement with the Sierra Club and the National Wildlife Federation in 2016 make significant changes to the Company’s Colstrip operations and those changes were reviewed by the Company and the plant operator in the second quarter of 2015 and the third quarter of 2016. PSE had previously recognized a legal obligation in 2003 under EPA rules to dispose of coal ash material at Colstrip. Due to the updated Colstrip information, additional disposal costs were added to the ARO. During the third quarter 2016, PSE entered into two new legal agreements requiring the Company to close the Colstrip 1 and 2 plants on or before July 1, 2022 and to incur additional monitoring costs, water treatment costs, forced evaporation cost, and post closure care costs for all Colstrip Units. As a result, the Company adjusted the Colstrip ARO ending liability to increase by $45.7 million for Colstrip 1 and 2 and $37.0 million for Colstrip 3 and 4. The actual ARO costs related to the CCR rule requirements may vary substantially from the estimates used to record the increased obligation due to uncertainty about the compliance strategies that will be used and the preliminary nature of available data used to estimate costs. We will continue to gather additional data and coordinate with the plant operator to make decisions about compliance strategies and the timing of closure activities. As additional information becomes available, the Company will update the ARO obligation for these changes, which could be material. During the first quarter 2016, the Company updated its estimated decommissioning costs due to the timing of its ARO for Lower Snake River and Hopkins Ridge wind generation sites and increased the ARO liability of $19.7 million . The following table describes the changes to the Company’s ARO liability as of December 31, 2016 and 2015 : At December 31, (Dollars in Thousands) 2016 2015 Asset retirement obligation at beginning of period $ 85,028 $ 48,909 New asset retirement obligation recognized in the period — 34,534 Liability adjustment in the period (411 ) (3,628 ) Revisions in estimated cash flows 113,081 3,403 Accretion expense 2,647 1,810 Asset retirement obligation at end of period $ 200,345 $ 85,028 The Company has identified the following obligations, as defined by ASC 410, “ARO,” which were not recognized because the liability for these assets cannot be reasonably estimated at December 31, 2016 due to: • A legal obligation under Federal Dangerous Waste Regulations to dispose of asbestos-containing material in facilities that are not scheduled for remodeling, demolition or sales. The disposal cost related to these facilities could not be measured since the retirement date is indeterminable; therefore, the liability cannot be reasonably estimated; • An obligation under Washington state law to decommission the wells at the Jackson Prairie natural gas storage facility upon termination of the project. Since the project is expected to continue as long as the Northwest pipeline continues to operate, the liability cannot be reasonably estimated; • An obligation to pay its share of decommissioning costs at the end of the functional life of the major transmission lines. The major transmission lines are expected to be used indefinitely; therefore, the liability cannot be reasonably estimated; • A legal obligation under Washington state environmental laws to remove and properly dispose of certain under and above ground fuel storage tanks. The disposal costs related to under and above ground storage tanks could not be measured since the retirement date is indeterminable; therefore, the liability cannot be reasonably estimated; • An obligation to pay decommissioning costs at the end of utility service franchise agreements to restore the surface of the franchise area. The decommissioning costs related to facilities at the franchise area could not be measured since the decommissioning date is indeterminable; therefore, the liability cannot be reasonably estimated; and • A potential legal obligation may arise upon the expiration of an existing FERC hydropower license if FERC orders the project to be decommissioned, although PSE contends that FERC does not have such authority. Given the value of ongoing generation, flood control and other benefits provided by these projects, PSE believes that the potential for decommissioning is remote and cannot be reasonably estimated. |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2016 | |
Long-term Debt, Unclassified [Abstract] | |
Long-term Debt | Long-Term Debt The following table presents outstanding long-term debt principal amounts and due dates as of December 31, 2016 and 2015 : (Dollars in Thousands) At December 31, Series Type Due 2016 2015 Puget Sound Energy: 5.500% Promissory Note 2017 $ 2,412 $ 2,412 6.740% Senior Secured Note 2018 200,000 200,000 7.150% First Mortgage Bond 2025 15,000 15,000 7.200% First Mortgage Bond 2025 2,000 2,000 7.020% Senior Secured Note 2027 300,000 300,000 7.000% Senior Secured Note 2029 100,000 100,000 3.900% Pollution Control Bond 2031 138,460 138,460 4.000% Pollution Control Bond 2031 23,400 23,400 5.483% Senior Secured Note 2035 250,000 250,000 6.724% Senior Secured Note 2036 250,000 250,000 6.274% Senior Secured Note 2037 300,000 300,000 5.757% Senior Secured Note 2039 350,000 350,000 5.795% Senior Secured Note 2040 325,000 325,000 5.764% Senior Secured Note 2040 250,000 250,000 4.434% Senior Secured Note 2041 250,000 250,000 5.638% Senior Secured Note 2041 300,000 300,000 4.300% Senior Secured Note 2045 425,000 425,000 4.700% Senior Secured Note 2051 45,000 45,000 6.974% Junior Subordinated Note 2067 250,000 250,000 * Debt discount, issuance cost and other * (28,974 ) (31,910 ) Total PSE long-term debt 3,747,298 3,744,362 Puget Energy: * Fair value adjustment of PSE long-term debt * (199,436 ) (207,977 ) * Revolving Credit Agreement 2018 12,480 — 6.500% Senior Secured Note 2020 450,000 450,000 6.000% Senior Secured Note 2021 500,000 500,000 5.625% Senior Secured Note 2022 450,000 450,000 3.650% Senior Secured Note 2025 400,000 400,000 * Debt discount, issuance cost and other * (6,269 ) (8,867 ) Total Puget Energy long-term debt $ 5,354,073 $ 5,327,518 _______________ * Not Applicable. PSE's senior secured notes will cease to be secured by the pledged first mortgage bonds on the date that all of the first mortgage bonds issued and outstanding under the electric or natural gas utility mortgage indenture have been retired. As of December 31, 2016 , the latest maturity date of the first mortgage bonds, other than pledged first mortgage bonds, is December 22, 2025. Puget Sound Energy Long-Term Debt PSE has in effect a shelf registration statement ("the existing shelf") under which it may issue, as of the date of this report, up to $800.0 million aggregate principal amount of senior notes secured by first mortgage bonds. The existing shelf will expire in November 2019. Substantially all utility properties owned by PSE are subject to the lien of the Company’s electric and natural gas mortgage indentures. To issue additional first mortgage bonds under these indentures, PSE’s earnings available for interest must exceed certain minimums as defined in the indentures. At December 31, 2016 , the earnings available for interest exceeded the required amount. On May 26, 2015, PSE issued $425.0 million of senior notes secured by first mortgage bonds. The notes mature in May 2045 and have an interest rate of 4.30% , which is payable semi-annually in May and November. Net proceeds of the issuance were used to fund the early retirement, including accrued interest and make-whole call premiums, of the Company's $150.0 million 5.197% senior notes maturing in October 2015 and the Company's $250.0 million 6.75% senior notes maturing in January 2016. Puget Energy Long-Term Debt In May 2015, Puget Energy issued $400.0 million of senior secured notes in a private placement. The notes mature in May 2025 and have an interest rate of 3.65% , which is payable semi-annually in May and November. Net proceeds of the issuance were used to repay outstanding Puget Energy indebtedness and to fund a special dividend to shareholders. In November 2015, Puget Energy exchanged $400.0 million of its 3.65% senior secured notes that were originally issued in the May 2015 private placement for registered notes of the same amount. Long-Term Debt Maturities The principal amounts of long-term debt maturities for the next five years and thereafter are as follows: (Dollars in Thousands) 2017 2018 2019 2020 2021 Thereafter Total Maturities of: PSE long-term debt $ 2,412 $ 200,000 $ — $ — $ — $ 3,573,860 $ 3,776,272 Puget Energy long-term debt — 12,480 — 450,000 500,000 850,000 1,812,480 Puget Energy long-term debt $ 2,412 $ 212,480 $ — $ 450,000 $ 500,000 $ 4,423,860 $ 5,588,752 |
Liquidity Facilities and Other
Liquidity Facilities and Other Financing Arrangements | 12 Months Ended |
Dec. 31, 2016 | |
Liquidity Facilities and Other Financing Arrangements [Abstract] | |
Liquidity Facilities and Other Financing Arrangements | Liquidity Facilities and Other Financing Arrangements As of December 31, 2016 and 2015 , PSE had $245.8 million and $159.0 million in short-term debt outstanding, respectively, exclusive of the demand promissory note with Puget Energy. Outside of the consolidation of PSE’s short-term debt, Puget Energy had no short-term debt outstanding in either year as borrowings under its credit facilities are classified as long-term. PSE’s weighted-average interest rate on short-term debt, including borrowing rate, commitment fees and the amortization of debt issuance costs, during 2016 and 2015 was 3.21% and 4.24% , respectively. As of December 31, 2016 , PSE and Puget Energy had several committed credit facilities that are described below. Puget Sound Energy Credit Facilities PSE has two unsecured revolving credit facilities which provide, in aggregate, $1.0 billion of short-term liquidity needs. These facilities consist of a $650.0 million revolving liquidity facility (which includes a liquidity letter of credit facility and a swingline facility) to be used for general corporate purposes, including a backstop to the Company's commercial paper program and a $350.0 million revolving energy hedging facility (which includes an energy hedging letter of credit facility). The $650.0 million liquidity facility includes a swingline feature allowing same day availability on borrowings up to $75.0 million . The credit facilities also have an accordion feature which, upon the banks' approval, would increase the total size of these facilities to $1.5 billion . In April 2014, the Company completed a one-year extension on both of the liquidity and hedging facilities, extending the maturity from February 2018 to April 2019, and updating or clarifying the definitions of other terms and conditions of the facilities from when they were committed in 2013. The credit agreements are syndicated among numerous lenders and contain usual and customary affirmative and negative covenants that, among other things, place limitations on PSE's ability to transact with affiliates, make asset dispositions and investments or permit liens to exist. The credit agreements also contain a financial covenant of total debt to total capitalization of 65% or less. PSE certifies its compliance with such covenants to participating banks each quarter. As of December 31, 2016 , PSE was in compliance with all applicable covenant ratios. The credit agreements provide PSE with the ability to borrow at different interest rate options. The credit agreements allow PSE to borrow at the bank's prime rate or to make floating rate advances at the London Interbank Offered Rate (LIBOR) plus a spread that is based upon PSE's credit rating. PSE must pay a commitment fee on the unused portion of the credit facilities. The spreads and the commitment fee depend on PSE's credit ratings. As of the date of this report, the spread to the LIBOR is 1.75% and the commitment fee is 0.275% . As of December 31, 2016 , no amounts were drawn under either PSE's $650.0 million facility or PSE's $350.0 million energy hedging facility. No letters of credit were outstanding under either facility, and $245.8 million was outstanding under the commercial paper program. Outside of the credit agreements, PSE had a $3.5 million letter of credit in support of a long-term transmission contract and a $1.0 million letter of credit in support of natural gas purchases in Canada. Demand Promissory Note PSE entered into a revolving credit facility with Puget Energy, in the form of a credit agreement and a demand promissory note (Note) pursuant to which PSE may borrow up to $30.0 million from Puget Energy subject to approval by Puget Energy. Under the terms of the Note, PSE pays interest on the outstanding borrowings based on the lower of the weighted-average interest rates of PSE’s outstanding commercial paper interest rate or PSE’s senior unsecured revolving credit facility. Absent such borrowings, interest is charged at one-month LIBOR plus 0.25% . As of December 31, 2016 , there was no outstanding balance under the Note. Puget Energy Credit Facility At December 31, 2016 , Puget Energy maintained an $800.0 million revolving senior secured credit facility. In April, 2014, the Company completed an amendment to the senior secured credit facility, extending the maturity from February 2017 to April 2018, updating the fee structure, eliminating a financial covenant and updating or clarifying the definitions of other terms and conditions of the facility. The Puget Energy revolving senior secured credit facility also has an accordion feature which, upon the banks' approval, would increase the size of the facility to $1.3 billion . The revolving senior secured credit facility provides Puget Energy the ability to borrow at different interest rate options and includes variable fee levels. Interest rates may be based on the bank's prime rate or LIBOR plus a spread based on Puget Energy's credit ratings. Puget Energy must pay a commitment fee on the unused portion of the facility. As of December 31, 2016 , there was $12.5 million outstanding under the facility. As a result of Puget Energy's credit rating upgrade in 2014, the spread over LIBOR was 1.75% and the commitment fee was 0.275% as of the date of this report. Puget Energy entered into interest rate swap contracts to manage the interest rate risk associated with the credit facility or similar variable rate debt. For additional information, see Note 9, "Accounting for Derivative Instruments and Hedging Activities" to the consolidated financial statements included in Item 8 of this report. The revolving senior secured credit facility contains usual and customary affirmative and negative covenants. The agreement also contains a maximum leverage ratio financial covenant as defined in the agreement governing the senior secured credit facility. As of December 31, 2016 , Puget Energy was in compliance with all applicable covenants. |
Leases
Leases | 12 Months Ended |
Dec. 31, 2016 | |
Leases [Abstract] | |
Leases | Leases PSE leases buildings and assets under operating leases. Certain leases contain purchase options, renewal options and escalation provisions. Operating lease expenses net of sublease receipts were: (Dollars in Thousands) At December 31, Years Operating Lease Expense 2016 $ 31,786 2015 27,843 2014 30,737 Payments received for the subleases of properties were immaterial for each of the years ended 2016 , 2015 and 2014 . Future minimum lease payments for non-cancelable leases net of sublease receipts are: (Dollars in Thousands) At December 31, Future Minimum Lease Payments Years Operating Capital 2017 $ 22,212 $ 296 2018 19,834 296 2019 18,078 74 2020 16,507 — 2021 8,137 — Thereafter 102,393 — Total minimum lease payments $ 187,161 $ 666 |
Accounting for Derivative Instr
Accounting for Derivative Instruments and Hedging Activities | 12 Months Ended |
Dec. 31, 2016 | |
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 PCA. Therefore, wholesale market transactions and PSE's related hedging strategies are focused on reducing costs and risks where feasible, thus reducing volatility in 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 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. As of December 31, 2016 , Puget Energy had two interest rate swap contracts outstanding which matured January 2017 . Currently, these swap instruments do not hedge any variable interest rate debt. PSE did not have any outstanding interest rate swap instruments. The following table presents the volumes, fair values and locations of the Company's derivative instruments recorded on the balance sheets: Puget Energy and Puget Sound Energy At Year Ended December 31, (Dollars in Thousands) Volumes (millions) Assets 1 Liabilities 2 2016 2015 2016 2015 2016 2015 Interest rate swap derivatives 3 $450.0 $450.0 $ — $ — $ 141 $ 5,050 Electric portfolio derivatives * * 36,460 23,443 41,329 112,106 Natural gas derivatives (MMBtus) 4 336.4 369.5 26,619 6,200 19,101 67,090 Total derivative contracts ** ** $ 63,079 $ 29,643 $ 60,571 $ 184,246 Current ** ** $ 54,341 $ 24,418 $ 44,310 $ 136,173 Long-term ** ** 8,738 5,225 16,261 48,073 Total derivative contracts ** ** $ 63,079 $ 29,643 $ 60,571 $ 184,246 _______________ 1 Balance sheet location: Current and Long-term Unrealized gain on derivative instruments. 2 Balance sheet location: Current and Long-term Unrealized loss on derivative instruments. 3 Interest rate swap contracts are only held at Puget Energy. 4 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 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 186.8 million One Million British Thermal Units (MMBtus) and purchased electricity of 3.6 million megawatt hours (MWhs) at December 31, 2016 and 202.1 million MMBtus and 0.1 million MWhs at December 31, 2015 . ** Not meaningful and/or applicable. 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 gas and electric contracts; and North American Energy Standards Board (NAESB) agreements, which standardize physical 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 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 10, "Fair Value Measurements," to the consolidated financial statements included in Item 8 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 Puget Sound Energy At December 31, 2016 (Dollars in Thousands) Gross Amounts 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 Commodity Contracts Cash Collateral Received/Posted Net Amount Assets: Energy derivative contracts $ 63,079 $ — $ 63,079 $ (42,858 ) $ — $ 20,221 Liabilities: Energy derivative contracts 60,430 — 60,430 (42,858 ) — 17,572 Interest rate swaps 2 141 — 141 — — 141 Puget Energy and Puget Sound Energy At December 31, 2015 (Dollars in Thousands) Gross Amounts 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 Commodity Contracts Cash Collateral Received/Posted Net Amount Assets: Energy derivative contracts $ 29,643 $ — $ 29,643 $ (23,998 ) $ — $ 5,645 Liabilities: Energy derivative contracts 179,196 — 179,196 (23,998 ) — 155,198 Interest rate swaps 2 5,050 — 5,050 — — 5,050 _______________ 1 All Derivative Contract deals are executed under ISDA, NAESB and WSPP Master Netting Agreements with Right of set-off. 2 Interest Rate Swap Contracts are only held at Puget Energy. The following tables present the effect and locations of the realized and unrealized gains (losses) of the Company's derivatives recorded on the statements of income: Puget Energy Year Ended December 31, (Dollars in Thousands) Location 2016 2015 2014 Interest rate contracts: Non-hedged interest rate swap (expense) income $ (1,062 ) $ (3,796 ) $ (3,915 ) Interest expense — 560 500 Gas for Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net 62,318 (9,315 ) (42,334 ) Realized Electric generation fuel (39,656 ) (44,648 ) 6,511 Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net 1 21,477 22,548 (41,812 ) Realized Purchased electricity (21,998 ) (39,137 ) (4,212 ) Total gain (loss) recognized in income on derivatives $ 21,079 $ (73,788 ) $ (85,262 ) Puget Sound Energy Year Ended December 31, (Dollars in Thousands) Location 2016 2015 2014 Gas for Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net $ 62,318 $ (9,315 ) $ (42,334 ) Realized Electric generation fuel (39,656 ) (44,648 ) 6,511 Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net 1 21,477 22,003 (43,302 ) Realized Purchased electricity (21,998 ) (39,137 ) (4,212 ) Total gain (loss) recognized in income on derivatives $ 22,141 $ (71,097 ) $ (83,337 ) _______________ 1 Differences between Puget Energy and PSE for the twelve months ended December 31, 2015 and 2014 are due to certain derivative contracts recorded at fair value in 2009 and subsequently designated as NPNS or cash flow hedges. These differences occurred through February 2015. 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, exposure monitoring and exposure mitigation. The Company monitors counterparties that have significant swings in credit default swap rates, have credit rating changes by external rating agencies, have changes in ownership or are experiencing 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 December 31, 2016 , approximately 93.1% of the Company's energy portfolio exposure, excluding NPNS transactions, is with counterparties that are rated investment grade by rating agencies and 6.9% 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, such as credit default swaps and bond spreads, in the determination of reserves. 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 unrealized gain (loss) positions. As of December 31, 2016 , the Company was in a net asset position with the majority of counterparties, however, the default factors of counterparties did not have a significant impact on reserves for the period. The majority of the Company's derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. As of December 31, 2016 , PSE has posted a $1.0 million letter of credit as a condition of transacting on a physical energy exchange and clearinghouse in Canada. PSE did not trigger any collateral requirements with any of its counterparties during the twelve months ended December 31, 2016 , nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades. The table below presents the fair value of the overall contractual contingent liability positions for the Company's derivative activity: Puget Energy and Puget Sound Energy At December 31, (Dollars in Thousands) 2016 2015 Contingent Feature Fair Value 1 Liability Posted Collateral Contingent Collateral Fair Value 1 Liability Posted Collateral Contingent Collateral Credit rating 2 $ 4,894 $ — $ 4,894 $ 24,187 $ — $ 24,187 Requested credit for adequate assurance 7,427 — — 67,003 — — Forward value of contract 3 507 — — — — — Total $ 12,828 $ — $ 4,894 $ 91,190 $ — $ 24,187 _______________ 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 | 12 Months Ended |
Dec. 31, 2016 | |
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 because 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. For interest rate swaps, the Company obtains monthly mark-to-market values from an independent external pricing service for LIBOR forward rates, which is a significant input. Some of the inputs of the interest rate swap valuations, which are less significant, include the credit standing of the counterparties, assumptions for time value and the impact of the Company's nonperformance risk of its liabilities. The Company classifies cash and cash equivalents, and restricted cash as Level 1 financial instruments due to cash being at stated value, and cash equivalents at quoted market prices. The Company considers its electric, natural gas and interest rate swap contracts as Level 2 derivative instruments as such contracts are commonly traded as over-the-counter forwards with indirectly observable price quotes. Management's assessment was 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 (e.g., Level 2 in the fair value hierarchy) used to value commodity contracts with the actual prices of commodity contracts entered into during the most recent quarter. 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. 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 $49.1 million and $52.8 million at December 31, 2016 and 2015 , 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 junior subordinated and long-term notes were estimated using the discounted cash flow method with U.S. Treasury yields and Company credit spreads as inputs, interpolating to the maturity date of each issue. Carrying values and estimated fair values were as follows: Puget Energy At December 31, 2016 At December 31, 2015 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Liabilities: Junior subordinated notes 2 $ 250,000 $ 210,261 $ 250,000 $ 211,173 Long-term debt (fixed-rate), net of discount 1 2 5,091,593 6,337,287 5,077,518 6,308,831 Long-term debt (variable-rate) 2 12,480 12,480 — — Total $ 5,354,073 $ 6,560,028 $ 5,327,518 $ 6,520,004 Puget Sound Energy At December 31, 2016 At December 31, 2015 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Liabilities: Junior subordinated notes 2 $ 250,000 $ 210,261 $ 250,000 $ 211,173 Long-term debt (fixed-rate), net of discount 2 2 3,497,298 4,360,783 3,494,362 4,329,444 Total $ 3,747,298 $ 4,571,044 $ 3,744,362 $ 4,540,617 _______________ 1 The carrying value includes debt issuances costs of $33.0 million and $38.4 million for December 31, 2016 and 2015 , respectively, which are not included in fair value. 2 The carrying value includes debt issuances costs of $27.2 million and $30.0 million for December 31, 2016 and 2015 , respectively, which are not included in fair value. Assets and Liabilities Measured at Fair Value on a Recurring Basis The following tables present 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 and the reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy: Puget Energy Fair Value Fair Value At December 31, 2016 At December 31, 2015 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Liabilities: Interest rate derivative instruments $ 141 $ — $ 141 $ 5,050 $ — $ 5,050 Total derivative liabilities $ 141 $ — $ 141 $ 5,050 $ — $ 5,050 Puget Energy and Fair Value Fair Value At December 31, 2016 At December 31, 2015 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Assets: Electric derivative instruments $ 30,666 $ 5,794 $ 36,460 $ 10,709 $ 12,734 $ 23,443 Natural gas derivative instruments 23,316 3,303 26,619 4,538 1,662 6,200 Total derivative assets $ 53,982 $ 9,097 $ 63,079 $ 15,247 $ 14,396 $ 29,643 Liabilities: Electric derivative instruments $ 36,507 $ 4,822 $ 41,329 $ 92,027 $ 20,079 $ 112,106 Natural gas derivative instruments 16,423 2,678 19,101 63,045 4,045 67,090 Total derivative liabilities $ 52,930 $ 7,500 $ 60,430 $ 155,072 $ 24,124 $ 179,196 Puget Energy and Puget Sound Energy Year Ended December 31, Level 3 Roll-Forward Net (Liability) 2016 2015 2014 (Dollars in Thousands) Electric Gas Total Electric Gas Total Electric Gas Total Balance at beginning of period $ (7,345 ) $ (2,383 ) $ (9,728 ) $ (12,062 ) $ (2,040 ) $ (14,102 ) $ (15,421 ) $ (361 ) $ (15,782 ) Changes during period Realized and unrealized energy derivatives: Included in earnings 1 4,007 — 4,007 (6,432 ) — (6,432 ) (5,537 ) — (5,537 ) Included in regulatory assets / liabilities — 4,312 4,312 — 3,695 3,695 — 1,630 1,630 Settlements 2 (1,129 ) (2,679 ) (3,808 ) 902 (3,885 ) (2,983 ) 1,036 (1,534 ) (498 ) Transferred into Level 3 (3,021 ) — (3,021 ) (787 ) — (787 ) 5,155 (585 ) 4,570 Transferred out of Level 3 8,460 1,375 9,835 11,034 (153 ) 10,881 2,705 (1,190 ) 1,515 Balance at end of period $ 972 $ 625 $ 1,597 $ (7,345 ) $ (2,383 ) $ (9,728 ) $ (12,062 ) $ (2,040 ) $ (14,102 ) _______________ 1 Income Statement location: Unrealized (gain) loss on derivative instruments, net. Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $2.0 million , $(7.4) million and $(9.6) million for the years ended December 31, 2016 , 2015 and 2014 , respectively. 2 The Company had no purchases, sales or issuances during the reported periods. 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. In order to determine which assets and liabilities are classified as Level 3, the Company receives market data from its independent external pricing service defining the tenor of observable market quotes. To the extent any of the Company's commodity contracts extend beyond what is considered observable as defined by its independent pricing service, the contracts are classified as Level 3. The actual tenor of what the independent pricing service defines as observable is subject to change depending on market conditions. Therefore, as the market changes, the same contract may be designated Level 3 one month and Level 2 the next, and vice versa. The changes of fair value classification into or out of Level 3 are recognized each month, and reported in the Level 3 Roll-forward table above. The Company did not have any transfers between Level 2 and Level 1 during the years ended December 31, 2016 and 2015 . The Company does periodically transact at locations, or market price points, that are illiquid or for which no prices are available from the independent pricing service. In such circumstances the Company uses a more liquid price point and performs a 15-month regression against the illiquid locations to serve as a proxy for market prices. Such transactions are classified as Level 3. 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. Below are the forward price ranges for the Company's commodity contracts, as of December 31, 2016 : Puget Energy and Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Average Electric $5,794 $4,822 Discounted cash flow Power Prices $11.86 per MWh $33.52 per MWh $27.61 per MWh Natural gas $3,303 $2,678 Discounted cash flow Natural Gas Prices $2.00 per MMBtu $3.24 per MMBtu $2.42 per MMBtu _______________ 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. At December 31, 2016 , 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 $0.2 million . 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 impairment on an annual basis, and upon the occurrence of any events or circumstances that would be more likely than not to reduce the fair value of the long-lived assets below their carrying value. One such triggering event is a significant decrease in the forward market prices of power. During 2016 and 2015 , Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets. In 2016 and 2015 , due to decreases in forecasted revenue and cost estimates and continued significant decreases in forward power prices, the following impairments were recorded to the Company's intangible asset contracts, with corresponding reductions to the regulatory liability as follows: Puget Energy (Dollars in Thousands) Valuation Date Contract Name Carrying Value Fair Value Write Down September 30, 2016 Priest Rapids $ 18,969 $ 6,191 $ 12,778 March 31, 2016 Wells Hydro 25,193 19,855 5,338 December 31, 2015 Wells Hydro 32,988 27,628 5,360 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 which are classified as Level 3 within the fair value hierarchy. A less significant input is the discount rate reflective of PSE's cost of capital used in the valuation. Below are significant unobservable inputs used in estimating the impaired long term power purchase contracts' fair value in 2016 and 2015 : Puget Energy Valuation Date Unobservable Input Low High Average September 30, 2016 Power prices $24.24 per MWh $58.96 per MWh $39.31 per MWh Power contract costs (in thousands) $618 per year $4,633 per year $2,472 per year March 31, 2016 Power prices $9.46 per MWh $25.96 per MWh $21.38 per MWh Power contract costs (in thousands) $4,100 per qtr. $4,659 per qtr. $4,452 per qtr. December 31, 2015 Power prices $15.16 per MWh $27.25 per MWh $23.23 per MWh Power contract costs (in thousands) $4,100 per qtr. $4,659 per qtr. $4,417 per qtr. |
Employee Investment Plans
Employee Investment Plans | 12 Months Ended |
Dec. 31, 2016 | |
Employee Investment Plans [Abstract] | |
Employee Investment Plans | Employee Investment Plans The Company's Investment Plan is a qualified employee 401(k) plan, under which employee salary deferrals and after-tax contributions are used to purchase several different investment fund options. PSE’s contributions to the employee Investment Plan were $17.2 million , $16.1 million and $14.9 million for the years 2016 , 2015 and 2014 , respectively. The employee Investment Plan eligibility requirements are set forth in the plan documents. Non-represented employees and United Association of Journeymen and Apprentices of the Plumbing and Pipefitting Industry (UA) represented employees hired before January 1, 2014, and International Brotherhood of Electrical Workers Local Union 77 (IBEW) represented employees hired before December 12, 2014, have the following company contributions: • For employees under the Cash Balance retirement plan formula, PSE will match 100% of an employee's contribution up to 6% of plan compensation each paycheck, and will make an additional year-end contribution equal to 1% of base pay. • For employees grandfathered under the Final Average Earning retirement plan formula, PSE will match 55% of an employee’s contribution up to 6% of plan compensation each paycheck. Non-represented and UA-represented employees hired on or after January 1, 2014 along with IBEW-represented employees hired on or after December 12, 2014, will have access to the 401(k) plan. The two contribution sources from PSE are below: • 401(k) Company Matching: New non-represented, UA-represented and IBEW-represented employees will receive company match each paycheck based on a new schedule- 100% match on the first 3% of pay contributed and 50% match on the next 3% of pay contributed. An employee who contributes 6% of pay will receive 4.5% of pay in company match. Company matching will be immediately vested. • Company Contribution: New UA-represented employees will receive an annual company contribution of 4% of eligible pay placed in the Cash Balance retirement plan. New non-represented and IBEW-represented employees will receive an annual company contribution of 4% of eligible pay, placed either in the Investment Plan 401(k) plan or in PSE’s Cash Balance retirement plan. New non-represented and IBEW-represented employees will make a one-time election within 30 days of hire and direct that PSE put the 4% contribution either into the 401(k) plan or into an account in the Cash Balance retirement plan. The Company’s 4% contribution will vest after three years of service. |
Retirement Benefits
Retirement Benefits | 12 Months Ended |
Dec. 31, 2016 | |
Compensation and Retirement Disclosure [Abstract] | |
Retirement Benefits | Retirement Benefits PSE has a defined benefit pension plan (Qualified Pension Benefits) covering the largest portion 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 with January 1, 2014, all non-represented and UA-represented employees, along with IBEW-represented employees hired on or after December 12, 2014 who elect to accumulate the Company contribution in the cash balance formula portion of the pension plan, will receive annual pay credits of 4% each year. They will also receive interest credits like other participants in the cash balance pension formula of the pension plan, which are at least 1% per quarter. When an employee with a vested cash balance formula benefit leaves PSE, he or she will have annuity and lump sum options for distribution. Those who select the lump sum option will receive their current cash balance amount. PSE also maintains a non-qualified Supplemental Executive Retirement Plan (SERP) for its key senior management employees. In addition to providing pension benefits, PSE provides legacy group health care and life insurance benefits (Other Benefits) 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. Puget Energy records purchase accounting adjustments associated with the re-measurement of the retirement plans. The following tables summarize the Company’s change in benefit obligation, change in plan assets and amounts recognized in the Statements of Financial Position for the years ended December 31, 2016 and 2015 : Puget Energy and Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Change in benefit obligation: Benefit obligation at beginning of period $ 643,088 $ 690,194 $ 51,279 $ 55,855 $ 13,946 $ 15,688 Service cost 18,913 21,287 1,085 1,108 93 112 Interest cost 28,689 28,088 2,325 2,281 533 621 Actuarial loss (gain) 1,545 (55,665 ) 106 (4,430 ) (2,262 ) (1,416 ) Benefits paid (38,730 ) (39,963 ) (3,061 ) (3,535 ) (1,264 ) (1,354 ) Medicare part D subsidy received — — — — 148 295 Administrative expense (898 ) (853 ) — — — — Benefit obligation at end of period $ 652,607 $ 643,088 $ 51,734 $ 51,279 $ 11,194 $ 13,946 Puget Energy and Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Change in plan assets: Fair value of plan assets at beginning of period $ 598,865 $ 626,173 $ — $ — $ 7,203 $ 8,360 Actual return on plan assets 37,022 (4,489 ) — — 926 (378 ) Employer contribution 24,000 18,000 3,061 3,535 335 575 Benefits paid (38,730 ) (39,963 ) (3,061 ) (3,535 ) (1,264 ) (1,354 ) Administrative expense (897 ) (856 ) — — — — Fair value of plan assets at end of period $ 620,260 $ 598,865 $ — $ — $ 7,200 $ 7,203 Funded status at end of period $ (32,347 ) $ (44,223 ) $ (51,734 ) $ (51,279 ) $ (3,994 ) $ (6,743 ) Puget Energy and Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Amounts recognized in Statement of Financial Position consist of: Noncurrent assets $ — $ — $ — $ — $ — $ — Current liabilities — — (1,911 ) (2,545 ) (325 ) (353 ) Noncurrent liabilities (32,347 ) (44,223 ) (49,823 ) (48,734 ) (3,669 ) (6,390 ) Net assets (liabilities) $ (32,347 ) $ (44,223 ) $ (51,734 ) $ (51,279 ) $ (3,994 ) $ (6,743 ) Puget Energy and Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Pension Plans with an Accumulated Benefit Obligation in excess of Plan Assets: Projected benefit obligation $ 652,607 $ 643,088 $ 51,734 $ 51,279 $ 11,194 $ 13,946 Accumulated benefit obligation 641,855 635,599 47,639 46,978 11,092 13,828 Fair value of plan assets 620,260 598,865 — — 7,200 7,203 The following tables summarize Puget Energy's and PSE's pension benefit amounts recognized in AOCI for the years ended December 31, 2016 and 2015 : Puget Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 56,588 $ 45,447 $ 9,043 $ 9,848 $ (4,190 ) $ (1,834 ) Prior service cost (credit) (9,822 ) (11,802 ) 246 288 — — Total $ 46,766 $ 33,645 $ 9,289 $ 10,136 $ (4,190 ) $ (1,834 ) Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 217,143 $ 221,064 $ 11,978 $ 13,202 $ (5,994 ) $ 3,834 Prior service cost (credit) (7,806 ) (9,379 ) 251 295 — — Total $ 209,337 $ 211,685 $ 12,229 $ 13,497 $ (5,994 ) $ 3,834 The following tables summarize Puget Energy's and PSE's net periodic benefit cost for the years ended December 31, 2016 , 2015 and 2014 : Puget Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2014 2016 2015 2014 2016 2015 2014 Components of net periodic benefit cost: Service cost $ 18,913 $ 21,287 $ 17,437 $ 1,085 $ 1,108 $ 1,042 $ 93 $ 112 $ 112 Interest cost 28,689 28,088 28,039 2,325 2,281 2,310 533 621 684 Expected return on plan assets (46,619 ) (45,038 ) (42,464 ) — — — (446 ) (531 ) (535 ) Amortization of prior service cost (credit) (1,980 ) (1,980 ) (1,980 ) 42 42 42 — — — Amortization of net loss (gain) — 3,887 — 911 1,641 913 (386 ) (130 ) (393 ) Net periodic benefit cost $ (997 ) $ 6,244 $ 1,032 $ 4,363 $ 5,072 $ 4,307 $ (206 ) $ 72 $ (132 ) Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2014 2016 2015 2014 2016 2015 2014 Components of net periodic benefit cost: Service cost $ 18,913 $ 21,287 $ 17,437 $ 1,085 $ 1,108 $ 1,042 $ 93 $ 112 $ 112 Interest cost 28,689 28,088 28,039 2,325 2,281 2,310 533 621 684 Expected return on plan assets (46,814 ) (45,462 ) (43,252 ) — — — (446 ) (531 ) (535 ) Amortization of prior service cost (credit) (1,573 ) (1,573 ) (1,573 ) 44 44 44 — 3 3 Amortization of net loss(gain) 15,257 20,555 13,195 1,330 2,120 1,461 (632 ) (406 ) (702 ) Net periodic benefit cost $ 14,472 $ 22,895 $ 13,846 $ 4,784 $ 5,553 $ 4,857 $ (452 ) $ (201 ) $ (438 ) The following tables summarize Puget Energy's and PSE's benefit obligations recognized in other comprehensive income (OCI) for the years ended December 31, 2016 and 2015 : Puget Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ 11,141 $ (6,136 ) $ 106 $ (4,430 ) $ (2,742 ) $ (508 ) Amortization of net loss (gain) — (3,887 ) (910 ) (1,641 ) 385 131 Amortization of prior service credit 1,980 1,980 (42 ) (42 ) — — Total change in other comprehensive income for year $ 13,121 $ (8,043 ) $ (846 ) $ (6,113 ) $ (2,357 ) $ (377 ) Puget Sound Energy Qualified Pension Benefit SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ 11,336 $ (5,711 ) $ 106 $ (4,430 ) $ (2,742 ) $ (508 ) Amortization of net (loss) gain (15,257 ) (20,556 ) (1,330 ) (2,120 ) 631 407 Amortization of prior service cost (credit) 1,573 1,573 (44 ) (44 ) — (3 ) Total change in other comprehensive income for year $ (2,348 ) $ (24,694 ) $ (1,268 ) $ (6,594 ) $ (2,111 ) $ (104 ) The estimated net (loss) gain and prior service cost (credit) for the pension plans that will be amortized from accumulated OCI into net periodic benefit cost in 2017 by PSE are $(13.7) million and $(1.6) million , respectively. The estimated net (loss) gain for the SERP that will be amortized from accumulated OCI into net periodic benefit cost in 2017 is $(1.6) million . The estimated prior service cost (credit) for the SERP that will be amortized from accumulated OCI into net periodic benefit cost in 2017 is immaterial . The estimated net (loss) gain and prior service cost (credit) for the other postretirement plans that will be amortized from accumulated OCI into net periodic benefit cost in 2017 is immaterial. For Puget Energy, the overall amounts expected to be amortized from accumulated OCI into net period benefit cost in 2017 were immaterial. 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, 2017 are expected to be at least $18.0 million , $1.9 million and $0.3 million , respectively. Assumptions In accounting for pension and other benefit obligations and costs under the plans, the following weighted-average actuarial assumptions were used by the Company: Qualified Pension Benefits SERP Pension Benefits Other Benefits Benefit Obligation Assumptions 2016 2015 2014 2016 2015 2014 2016 2015 2014 Discount rate 4.50 % 4.65 % 4.25 % 4.50 % 4.65 % 4.25 % 4.50 % 4.65 % 4.25 % Rate of compensation increase 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 Medical trend rate — — — — — — 8.80 7.20 5.70 Benefit Cost Assumptions Discount rate 4.65 % 4.25 % 5.10 % 4.65 % 4.25 % 5.10 % 4.65 % 4.25 % 5.10 % Return on plan assets 7.75 7.75 7.75 — — — 6.75 7.00 7.00 Rate of compensation increase 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 Medical trend rate — — — — — — 5.30 7.20 6.70 The assumed medical inflation rate used to determine benefit obligations is 8.80% in 2017 grading down to 4.30% in 2018 . A 1.0% change in the assumed medical inflation rate would have the following effects: 2016 2015 (Dollars in Thousands) 1% Increase 1% Decrease 1% Increase 1% Decrease Effect on post-retirement benefit obligation $ 38 $ (35 ) $ 52 $ (42 ) Effect on service and interest cost components 2 (2 ) 2 (2 ) The Company has selected the expected return on plan assets based on a historical analysis of rates of return and the Company’s investment mix, market conditions, inflation and other factors. The expected rate of return is reviewed annually based on these factors. The Company’s accounting policy for calculating the market-related value of assets for the Company’s retirement plan is as follows. PSE market-related value of assets is based on a five-year smoothing of asset gains (losses) measured from the expected return on market-related assets. This is a calculated value that recognizes changes in fair value in a systematic and rational manner over five years. The same manner of calculating market-related value is used for all classes of assets, and is applied consistently from year to year. Puget Energy’s pension and other postretirement benefits income or costs depend on several factors and assumptions, including plan design, timing and amount of cash contributions to the plan, earnings on plan assets, discount rate, expected long-term rate of return, and mortality and health care costs trends. Changes in any of these factors or assumptions will affect the amount of income or expense that Puget Energy records in its financial statements in future years and its projected benefit obligation. Puget Energy has selected an expected return on plan assets based on a historical analysis of rates of return and Puget Energy’s investment mix, market conditions, inflation and other factors. As required by merger accounting rules, market-related value was reset to market value effective with the merger. The discount rates were determined by using market interest rate data and the weighted-average discount rate from Citigroup Pension Liability Index Curve. The Company also takes into account in determining the discount rate the expected changes in market interest rates and anticipated changes in the duration of the plan liabilities. Plan Benefits The expected total benefits to be paid during the next five years and the aggregate total to be paid for the five years thereafter are as follows: (Dollars in Thousands) 2017 2018 2019 2020 2021 2022-2026 Qualified Pension total benefits $ 41,400 $ 42,500 $ 43,600 $ 44,600 $ 45,200 $ 240,800 SERP Pension total benefits 1,911 5,278 5,666 4,454 1,724 34,043 Other Benefits total with Medicare Part D subsidy 928 893 863 829 787 3,873 Other Benefits total without Medicare Part D subsidy 1,256 1,239 1,216 1,191 1,158 5,294 Plan Assets Plan contributions and the actuarial present value of accumulated plan benefits are prepared based on certain assumptions pertaining to interest rates, inflation rates and employee demographics, all of which are subject to change. Due to uncertainties inherent in the estimations and assumptions process, changes in these estimates and assumptions in the near term may be material to the financial statements. The Company has a Retirement Plan Committee that establishes investment policies, objectives and strategies designed to balance expected return with a prudent level of risk. All changes to the investment policies are reviewed and approved by the Retirement Plan Committee prior to being implemented. The Retirement Plan Committee invests trust assets with investment managers who have historically achieved above-median long-term investment performance within the risk and asset allocation limits that have been established. Interim evaluations are routinely performed with the assistance of an outside investment consultant. To obtain the desired return needed to fund the pension benefit plans, the Retirement Plan Committee has established investment allocation percentages by asset classes as follows: Allocation Asset Class Minimum Target Maximum Domestic large cap equity 25 % 31 % 40 % Domestic small cap equity — 9 15 Non-U.S. equity 10 25 30 Fixed income 15 25 30 Real estate — — 10 Absolute return 5 10 15 Cash — — 5 Plan Fair Value Measurements ASC 715, “Compensation – Retirement Benefits” (ASC 715) directs companies to provide additional disclosures about plan assets of a defined benefit pension or other postretirement plan. The objectives of the disclosures are to disclose the following: (i) how investment allocation decisions are made, including the factors that are pertinent to an understanding of investment policies and strategies; (ii) major categories of plan assets; (iii) inputs and valuation techniques used to measure the fair value of plan assets; (iv) effect of fair value measurements using significant unobservable inputs (Level 3) on changes in plan assets for the period; and (v) significant concentrations of risk within plan assets. ASC 820 allows the reporting entity, as a practical expedient, to measure the fair value of investments that do not have readily determinable fair values on the basis of the net asset value per share of the investment if the net asset value of the investment is calculated in a matter consistent with ASC 946, “Financial Services – Investment Companies”. The standard requires disclosures about the nature and risk of the investments and whether the investments are probable of being sold at amounts different from the net asset value per share. The following table sets forth by level, within the fair value hierarchy, the qualified pension plan as of December 31, 2016 and 2015 : Recurring Fair Value Measures Recurring Fair Value Measures As of December 31, 2016 As of December 31, 2015 (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Mutual Funds $ 181,212 $ — $ 181,212 $ 169,165 $ — $ 169,165 Common Stock 154,255 — $ 154,255 146,321 — $ 146,321 Government Securities 18,754 16,197 $ 34,951 8,835 14,268 $ 23,103 Corporate Bonds — 38,543 $ 38,543 — 44,157 $ 44,157 Subtotal 354,221 54,740 408,961 324,321 58,425 382,746 Investments measured at NAV 1 * * 222,819 * * 223,663 Net (payable) receivable * * (9,894 ) * * (7,544 ) Total assets * * $ 621,886 * * $ 598,865 _______________ 1 In accordance with ASU 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent)", certain investments that were measured at NAV per share (or its equivalent) have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the line items presented in the statement of net assets available for benefits. Investments measured at NAV consist of common/collective trust funds and two partnerships held as of December 31, 2016 . Mesirow Institutional Multi-Strategy Fund Partnership, L.P. utilizes a combination of long and short strategies through investments in investment funds. The major strategy allocations of the investment funds include (1) Investments in debt obligations of public and private entities; typically in financial duress, and (2) Investments in equity positions on a global basis utilizing fundamental analysis. Grosvenor Institutional Partners Fund, L.P invests substantially all of the fund assets available in the Grosvenor Master Fund, a Cayman Islands exempted company which is sponsored, managed and has the same investment objective as the Partnership fund. In addition to the Master Fund, investments are made primarily in offshore investment funds, investment partnerships, and pooled investment vehicles; collectively referred to as Portfolio Funds, which generally implement "nontraditional" or "alternative" investment strategies. * Not Applicable. The following table sets forth by level, within the fair value hierarchy, the Other Benefits plan assets which consist of insurance benefits for retired employees, at fair value: Recurring Fair Value Measures Recurring Fair Value Measures As of December 31, 2016 As of December 31, 2015 (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Mutual fund 1 $ 7,182 $ — $ 7,182 $ 7,135 $ — $ 7,135 Cash equivalents 2 — 80 80 — 68 68 Total assets $ 7,182 $ 80 $ 7,262 $ 7,135 $ 68 $ 7,203 _______________ 1 This is a publicly traded balanced mutual fund. The fund seeks regular income, conservation of principal, and an opportunity for long-term growth of principal and income. The fair value is determined by taking the number of shares owned by the plan, and multiplying by the market price as of December 31, 2016 . 2 The investment consists of a money market fund (at level 1) and a collective trust fund (at level 2). The money market fund is valued at the net asset value per share of $1.00 per unit as of December 31, 2016 . The collective trust fund invests primarily in commercial paper, notes, repurchase agreements, and other evidences of indebtedness which are payable on demand or short-term in nature. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes The details of income tax (benefit) expense are as follows: Puget Energy Year Ended December 31, (Dollars in Thousands) 2016 2015 2014 Charged to operating expenses: Current: Federal $ — $ — $ — State 20 — — Deferred: Federal 140,315 91,968 57,152 State (131 ) (192 ) (167 ) Total income tax expense $ 140,204 $ 91,776 $ 56,985 Puget Sound Energy Year Ended December 31, (Dollars in Thousands) 2016 2015 2014 Charged to operating expenses: Current: Federal $ — $ — $ — State 20 — — Deferred: Federal 175,327 125,900 89,342 State — — — Total income tax expense $ 175,347 $ 125,900 $ 89,342 The following reconciliation compares pre-tax book income at the federal statutory rate of 35.0% to the actual income tax expense in the Statements of Income: Puget Energy Year Ended December 31, (Dollars in Thousands) 2016 2015 2014 Income taxes at the statutory rate $158,586 $116,534 $80,087 Increase (decrease): Production tax credit 1 (12,925) (19,470) (23,073) Utility plant differences 3,966 5,671 7,090 Treasury grant amortization (9,788) (8,807) (8,808) Other - net 365 (2,152) 1,689 Total income tax expense $140,204 $91,776 $56,985 Effective tax rate 30.9% 27.6% 24.9% Puget Sound Energy Year Ended December 31, (Dollars in Thousands) 2016 2015 2014 Income taxes at the statutory rate $194,572 $150,531 $114,084 Increase (decrease): Production tax credit 1 (12,925) (19,470) (23,073) Utility plant differences 3,966 5,671 7,090 Treasury grant amortization (9,788) (8,807) (8,808) Other - net (478) (2,025) 49 Total income tax expense $175,347 $125,900 $89,342 Effective tax rate 31.5% 29.3% 27.4% _______________ 1 PSE's Wild Horse wind plant and Hopkins Ridge wind plant earned their last PTCs in December 2016 and 2015, respectively. No further PTCs are expected. The Company’s net deferred tax liability at December 31, 2016 and 2015 is composed of amounts related to the following types of temporary differences: Puget Energy At December 31, (Dollars in Thousands) 2016 2015 Utility plant and equipment $ 1,880,782 $ 1,788,078 Regulatory asset for income taxes 72,038 73,231 Fair value of debt instruments 67,444 70,260 Pensions and other compensation 77,230 77,230 Other, net deferred tax liabilities 119,050 84,397 Subtotal deferred tax liabilities 2,216,544 2,093,196 Net operating loss carryforward (352,827 ) (384,338 ) Production tax credit carryforward (190,999 ) (178,075 ) Regulatory liability on production tax credit (101,787 ) (94,828 ) Subtotal deferred tax assets (645,613 ) (657,241 ) Total net deferred tax liabilities $ 1,570,931 $ 1,435,955 Puget Sound Energy At December 31, (Dollars in Thousands) 2016 2015 Utility plant and equipment $ 1,880,782 $ 1,788,078 Regulatory asset for income taxes 71,517 72,694 Other, net deferred tax liabilities 113,938 80,351 Subtotal deferred tax liabilities 2,066,237 1,941,123 Net operating loss carryforward (41,061 ) (111,604 ) Production tax credit carryforward (190,999 ) (178,075 ) Regulatory liability on production tax credit (101,787 ) (94,828 ) Subtotal deferred tax assets (333,847 ) (384,507 ) Total net deferred tax liabilities $ 1,732,390 $ 1,556,616 In November 2015, the FASB issued ASU 2015-17, "Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes". ASU 2015-17 requires reporting entities to classify deferred tax liabilities and assets as noncurrent in a classified balance sheet instead of separating such deferred taxes into current and noncurrent amounts. The Company calculates its deferred tax assets and liabilities under ASC 740, “Income Taxes” (ASC 740). ASC 740 requires recording deferred tax balances, at the currently enacted tax rate, on assets and liabilities that are reported differently for income tax purposes than for financial reporting purposes. The utilization of deferred tax assets requires sufficient taxable income in future years. ASC 740 requires a valuation allowance on deferred tax assets when it is more likely than not that the deferred tax assets will not be realized. The Company’s PTC carryforwards expire from 2027 through 2036. The Company’s net operating loss carryforwards expire from 2029 through 2036. No valuation allowance has been provided for PTC or net operating loss carryforwards. For ratemaking purposes, deferred taxes are not provided for certain temporary differences. PSE has established a regulatory asset for income taxes recoverable through future rates related to those temporary differences for which no deferred taxes have been provided, based on prior and expected future ratemaking treatment. The Company accounts for uncertain tax position under ASC 740, which clarifies the accounting for uncertainty in income taxes recognized in the financial statements. ASC 740 requires the use of a two-step approach for recognizing and measuring tax positions taken or expected to be taken in a tax return. First, a tax position should only be recognized when it is more likely than not, based on technical merits, that the position will be sustained upon challenge by the taxing authorities and taken by management to the court of last resort. Second, a tax position that meets the recognition threshold should be measured at the largest amount that has a greater than 50.0% likelihood of being sustained. As of December 31, 2016 and 2015 , the Company had no material unrecognized tax benefits. As a result, no interest or penalties were accrued for unrecognized tax benefits during the year. The Company has open tax years from 2013 through 2016. The Company classifies interest as interest expense and penalties as other expense in the financial statements. |
Litigation
Litigation | 12 Months Ended |
Dec. 31, 2016 | |
Litigation Disclosure [Abstract] | |
Litigation | Litigation Colstrip PSE has a 50% ownership interest in Colstrip Units 1 and 2, and a 25% interest in Colstrip Units 3 and 4. On March 6, 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. Based on a second amended complaint filed in August 2014, plaintiffs' lawsuit alleged violations of permitting requirements under the New Source Review/Prevention of Significant Deterioration program of the Clean Air Act arising from projects (plaintiffs initially claimed seventy-three projects, but this was reduced to two projects before trial in May 2016) undertaken at Colstrip during the time period from 2001 to 2012. On July 12, 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 on September 6, 2016. As part of the settlement, PSE agreed, along with Talen Energy (the owner of the other 50% interest in Colstrip Units 1 and 2), to retire the two oldest units (Units 1 and 2) at Colstrip in eastern Montana by no later than July 1, 2022. PSE expects that the Washington Commission will allow full recovery in rates of the net book value (NBV) at retirement and related decommissioning costs consistent with prior precedents. As a result, PSE reclassified $176.8 million from a plant asset to a regulatory asset, which represents the expected NBV at retirement of Colstrip Units 1 and 2, based on the expected shutdown date of July 1, 2022. Colstrip Units 3 and 4, which are newer and more efficient, are not affected by the settlement, and allegations in the lawsuit against Colstrip Units 3 and 4 were dismissed as part of the settlement. While PSE has estimated the asset retirement obligation for Colstrip Units 1 and 2, the full scope of decommissioning activities and costs are unknown and will vary from the estimates that are available at this time. Greenwood On March 9, 2016, a natural gas explosion occurred in the Greenwood neighborhood of Seattle, WA, damaging multiple structures. The Washington Commission Staff completed its investigation of the incident and filed a complaint September 20, 2016, seeking from PSE $3.2 million in fines. As a result, the Washington Commission will initiate a hearing before making a final determination. As of December 31, 2016 , PSE has accrued $3.2 million for the fine. Clean Air Rule PSE, along with other Washington natural gas utilities, jointly filed a lawsuit in federal court on September 27, 2016 (United States District Court Eastern District of Washington) and Washington State court (Thurston County Superior Court) on September 30, 2016 challenging Washington Department of Ecology’s Clean Air Rule. Other parties in the suit include Avista Corporation, Cascade Natural Gas Corp. and Northwest Natural Gas. The lawsuit contends that this Rule will have the unintended consequence of increasing carbon emissions while penalizing customers for using natural gas. Other Proceedings The Company is also involved in litigation relating to claims arising out of its operations in the normal course of business. The Company has recorded reserves of $0.7 million and $0.3 million relating to these claims as of December 31, 2016 and 2015 , respectively. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2016 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies For the year ended December 31, 2016 , approximately 13.7% of the Company’s energy output was obtained at an average cost of approximately $0.023 per Kilowatt Hour (kWh) through long-term contracts with three of the Washington Public Utility Districts (PUDs) that own hydroelectric projects on the Columbia River. The purchase of power from the Columbia River projects is on a pro rata share basis under which the Company pays a proportionate share of the annual debt service, operating and maintenance costs and other expenses associated with each project, in proportion to the contractual share of power that PSE obtains from that project. In these instances, PSE’s payments are not contingent upon the projects being operable; therefore, PSE is required to make the payments even if power is not delivered. These projects are financed through substantially level debt service payments and their annual costs should not vary significantly over the term of the contracts unless additional financing is required to meet the costs of major maintenance, repairs or replacements, or license requirements. The Company’s share of the costs and the output of the projects is subject to reduction due to various withdrawal rights of the PUDs and others over the contract lives. The Company's expenses under these PUD contracts were as follows for the years ended December 31: (Dollars in Thousands) 2016 2015 2014 PUD contract costs $ 77,667 $ 72,833 $ 69,661 As of December 31, 2016 , the Company purchased portions of the power output of the PUDs' projects as set forth in the following table: Company's Current Share of (Dollars in Thousands) Contract Expiration Percent of Output Megawatt Capacity Estimated 2017 Costs 2017 Debt Service Costs Interest included in 2017 Debt Service Costs Debt Outstanding Chelan County PUD: Rock Island Project 2031 25.0 % 156 $ 28,886 $ 10,430 $ 5,638 $ 88,518 Rocky Reach Project 2031 25.0 325 28,376 7,574 2,854 44,305 Douglas County PUD: Wells Project 2018 29.9 251 16,547 8,004 2,153 54,847 Grant County PUD: Priest Rapids Development 2052 0.6 8 2,809 1,670 1,670 18,579 Wanapum Development 2052 0.6 9 2,809 1,670 1,670 18,579 Total 749 $ 79,427 $ 29,348 $ 13,985 $ 224,828 The following table summarizes the Company’s estimated payment obligations for power purchases from the Columbia River projects, contracts with other utilities and contracts with non-utilities. These contracts have varying terms and may include escalation and termination provisions. (Dollars in Thousands) 2017 2018 2019 2020 2021 Thereafter Total Columbia River projects $ 73,733 $ 69,527 $ 58,921 $ 59,172 $ 56,396 $ 597,468 $ 915,217 Other utilities 10,499 1,257 888 — — — 12,644 Non-utility contracts 198,681 203,428 208,328 212,042 218,431 935,826 1,976,736 Total $ 282,913 $ 274,212 $ 268,137 $ 271,214 $ 274,827 $ 1,533,294 $ 2,904,597 Total purchased power contracts provided the Company with approximately 13.0 million , 11.2 million and 12.1 million MWhs of firm energy at a cost of approximately $402.5 million , $373.8 million and $401.4 million for the years 2016 , 2015 and 2014 , respectively. PSE enters into short-term energy supply contracts to meet its core customer needs. These contracts are sometimes classified as NPNS, however in most cases recorded at fair value in accordance with ASC 815. Commitments under these contracts are $45.7 million , $10.5 million and $3.9 million in 2017 , 2018 and 2019 , respectively. Natural Gas Supply Obligations The Company has entered into various firm supply, transportation and storage service contracts in order to ensure adequate availability of natural gas supply for its customers and generation requirements. The Company contracts for its long-term natural gas supply on a firm basis, which means the Company has a 100% daily take obligation and the supplier has a 100% daily delivery obligation to ensure service to PSE’s customers and generation requirements. The transportation and storage contracts, which have remaining terms from less than one year to 28 years, provide that the Company must pay a fixed demand charge each month, regardless of actual usage. The Company incurred demand charges for 2016 for firm transportation, storage and peaking services for its natural gas customers of $120.2 million . The Company incurred demand charges in 2016 for firm transportation and storage services for the natural gas supply for its combustion turbines in the amount of $43.2 million . The following table summarizes the Company’s obligations for future natural gas supply and demand charges through the primary terms of its existing contracts. The quantified obligations are based on the FERC and NEB (National Energy Board) currently authorized rates, which are subject to change. Natural Gas Supply and Demand Charge Obligations (Dollars in Thousands) 2017 2018 2019 2020 2021 Thereafter Total Natural gas supply $ 320,238 $ 211,256 $ 230,109 $ 177,390 $ 107,621 $ — $ 1,046,614 Firm transportation service 156,290 154,155 149,277 140,672 128,049 467,266 1,195,709 Firm storage service 6,616 3,861 2,943 1,950 1,619 2,475 19,464 Total $ 483,144 $ 369,272 $ 382,329 $ 320,012 $ 237,289 $ 469,741 $ 2,261,787 Service Contracts The following table summarizes the Company’s estimated obligations for service contracts through the terms of its existing contracts. Service Contract Obligations (Dollars in Thousands) 2017 2018 2019 2020 2021 Thereafter Total Energy production service contracts $ 31,573 $ 31,970 $ 31,313 $ 50,656 $ 32,934 $ 204,687 $ 383,133 Automated meter reading system 18,175 18,693 18,718 20,191 20,939 116,811 213,527 Total $ 49,748 $ 50,663 $ 50,031 $ 70,847 $ 53,873 $ 321,498 $ 596,660 Other Commitments and Contingencies For information regarding PSE's environmental remediation obligations, see Note 3, "Regulation and Rates," to the consolidated financial statements included in item 8 of this report. |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2016 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Related Party Transactions Scott Armstrong serves on the Board of Directors of the Company and, until its acquisition by Kaiser Permanente on February 1, 2017, was the President and Chief Executive Officer of Group Health Cooperative (Group Health). Group Health provided coverage to over 600,000 residents in Washington and Northern Idaho. Certain employees of PSE elected Group Health as their medical provider and as a result, PSE paid Group Health a total of $ 23.3 million and $ 20.3 million for medical coverage for the year ended December 31, 2016 and 2015 , respectively. Kimberly Harris, the President and Chief Executive Officer and a director of Puget Energy and PSE, is married to Kyle Branum, who through 2016 was a principal at the law firm Riddell Williams P.S. As of January 2017, Mr. Branum is a partner at Summit Law Group, which provides legal services to PSE. In 2016 and 2015 , Riddell Williams was paid $ 1.0 million and $ 1.8 million , respectively, for legal services provided to PSE and Mr. Branum was among the lawyers at Riddell Williams who provided such legal services. This work was performed under the supervision of PSE's General Counsel. On October 10, 2014, U.S. Bancorp announced the appointment of Kimberly Harris to its board of directors effective October 20, 2014. Ms. Harris is the President and Chief Executive Officer of both Puget Energy and PSE. U.S. Bancorp is the parent company of U.S. Bank N.A., which directly or through its subsidiaries or affiliates provides credit, banking, investment and trust services to both Puget Energy and PSE. For the year ended December 31, 2016 and 2015 , Puget Energy and PSE paid a total of approximately $0.3 million and $1.0 million , respectively, in fees and interest to U.S. Bank N.A. and its subsidiaries or affiliates. |
Segment Information
Segment Information | 12 Months Ended |
Dec. 31, 2016 | |
Segment Reporting [Abstract] | |
Segment Information | Segment Information Puget Energy operates one reportable business segment referred to as the regulated utility segment. Puget Energy’s regulated utility operation generates, purchases and sells electricity and purchases, transports and sells natural gas. The service territory of PSE covers approximately 6,000 square miles in the state of Washington. In managing the business, management reviews the consolidated financial statements for Puget Energy and PSE during the year. |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Income (Loss) | 12 Months Ended |
Dec. 31, 2016 | |
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract] | |
Accumulated Other Comprehensive Income (Loss) | Accumulated Other Comprehensive Income (Loss ) The following tables present the changes in the Company’s (loss) AOCI by component for the years ended December 31, 2016 , 2015 and 2014 , respectively: Puget Energy Net unrealized gain (loss) and prior service cost on pension plans Net unrealized gain (loss) on energy derivative instruments Net unrealized gain (loss) on interest rate swaps Changes in AOCI, net of tax (Dollars in Thousands) Total Balance at December 31, 2013 $ 48,514 $ (705 ) $ (94 ) $ 47,715 Other comprehensive income (loss) before reclassifications (84,301 ) — — (84,301 ) Amounts reclassified from accumulated other comprehensive income (loss), net of tax (923 ) 372 94 (457 ) Net current-period other comprehensive income (loss) (85,224 ) 372 94 (84,758 ) Balance at December 31, 2014 $ (36,710 ) $ (333 ) $ — $ (37,043 ) Other comprehensive income (loss) before reclassifications 7,196 — — 7,196 Amounts reclassified from accumulated other comprehensive income (loss), net of tax 2,248 333 — 2,581 Net current-period other comprehensive income (loss) 9,444 333 — 9,777 Balance at December 31, 2015 $ (27,266 ) $ — $ — $ (27,266 ) Other comprehensive income (loss) before reclassifications (5,528 ) — — (5,528 ) Amounts reclassified from accumulated other comprehensive income (loss), net of tax (918 ) — — (918 ) Net current-period other comprehensive income (loss) (6,446 ) — — (6,446 ) Balance at December 31, 2016 $ (33,712 ) $ — $ — $ (33,712 ) Puget Sound Energy Net unrealized gain (loss) and prior service cost on pension plans Net unrealized gain (loss) on energy derivative instruments Net unrealized gain (loss) on treasury interest rate swaps Changes in AOCI, net of tax (Dollars in Thousands) Total Balance at December 31, 2013 $ (87,405 ) $ (2,027 ) $ (6,307 ) $ (95,739 ) Other comprehensive income (loss) before reclassifications (84,955 ) — — (84,955 ) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 8,079 1,341 317 9,737 Net current-period other comprehensive income (loss) (76,876 ) 1,341 317 (75,218 ) Balance at December 31, 2014 $ (164,281 ) $ (686 ) $ (5,990 ) $ (170,957 ) Other comprehensive income (loss) before reclassifications 6,922 — — 6,922 Amounts reclassified from accumulated other comprehensive income (loss), net of tax 13,482 686 317 14,485 Net current-period other comprehensive income (loss) 20,404 686 317 21,407 Balance at December 31, 2015 $ (143,877 ) $ — $ (5,673 ) $ (149,550 ) Other comprehensive income (loss) before reclassifications (5,655 ) — — (5,655 ) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 9,377 — 317 9,694 Net current-period other comprehensive income (loss) 3,722 — 317 4,039 Balance at December 31, 2016 $ (140,155 ) $ — $ (5,356 ) $ (145,511 ) Details about the reclassifications out of AOCI (loss) for the years ended December 31, 2016 , 2015 and 2014 , respectively, are as follows: Puget Energy (Dollars in Thousands) Details about accumulated other comprehensive income (loss) components Affected line item in the statement where net income (loss) is presented Amount reclassified from accumulated other comprehensive income (loss) 2016 2015 2014 Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 1,938 $ 1,938 $ 1,938 Amortization of net gain (loss) (a) (525 ) (5,397 ) (519 ) Total before tax 1,413 (3,459 ) 1,419 Tax (expense) or benefit (495 ) 1,211 (496 ) Net of Tax 918 (2,248 ) 923 Net unrealized gain (loss) on energy derivative instruments: Commodity contracts: Electric derivatives Purchased electricity — (512 ) (572 ) Tax (expense) or benefit — 179 200 Net of Tax — (333 ) (372 ) Net unrealized gain (loss) on interest rate swaps: Interest rate contracts Interest expense — — (144 ) Tax (expense) or benefit — — 50 Net of Tax — — (94 ) Total reclassification for the period Net of Tax $ 918 $ (2,581 ) $ 457 _______________ (a) These AOCI components are included in the computation of net periodic pension cost (see Note 12, "Retirement Benefits" for additional details). Puget Sound Energy (Dollars in Thousands) Details about accumulated other comprehensive income (loss) components Affected line item in the statement where net income (loss) is presented Amount reclassified from accumulated other comprehensive income (loss) 2016 2015 2014 Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 1,529 $ 1,526 $ 1,526 Amortization of net gain (loss) (a) (15,955 ) (22,268 ) (13,954 ) Total before tax (14,426 ) (20,742 ) (12,428 ) Tax (expense) or benefit 5,049 7,260 4,349 Net of tax (9,377 ) (13,482 ) (8,079 ) Net unrealized gain (loss) on energy derivative instruments: Commodity contracts: Electric derivatives Purchased electricity — (1,055 ) (2,063 ) Tax (expense) or benefit — 369 722 Net of Tax — (686 ) (1,341 ) Net unrealized gain (loss) on treasury interest rate swaps: Interest rate contracts Interest expense (488 ) (488 ) (488 ) Tax (expense) or benefit 171 171 171 Net of Tax (317 ) (317 ) (317 ) Total reclassification for the period Net of Tax $ (9,694 ) $ (14,485 ) $ (9,737 ) _______________ (a) These AOCI components are included in the computation of net periodic pension cost (see Note 12, "Retirement Benefits" for additional details). |
SCHEDULE I CONDENSED FINANCIAL
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY | 12 Months Ended |
Dec. 31, 2016 | |
Condensed Financial Information of Parent Company Only Disclosure [Abstract] | |
Schedule I: Condensed Financial Information of Puget Energy | SCHEDULE I: CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY Puget Energy Condensed Statements of Income and Comprehensive Income (Loss) (Dollars in Thousands) Year Ended December 31, 2016 2015 2014 Non-utility expense and other $ (5,252 ) $ (1,617 ) $ (5,390 ) Other income (deductions): Equity in earnings of subsidiary 385,838 309,603 240,102 Non-hedged interest rate swap expense (1,062 ) (3,796 ) (3,915 ) Interest income 2 63 185 Interest expense (104,600 ) (100,114 ) (93,382 ) Income taxes 37,973 37,040 34,235 Net income (loss) 312,899 241,179 171,835 Comprehensive income (loss) $ 306,453 $ 250,956 $ 87,077 See accompanying notes to the condensed financial statements. Puget Energy Condensed Balance Sheets (Dollars in Thousands) December 31, 2016 2015 Assets: Investment in subsidiaries $ 3,571,550 $ 3,415,571 Other property and investments: Goodwill 1,656,513 1,656,513 Current assets: Cash 397 639 Receivables from affiliates 1 213 203 Total current assets 610 842 Long-term assets: Deferred income taxes 309,812 272,487 Other 521 537 Total long-term assets 310,333 273,024 Total assets $ 5,539,006 $ 5,345,950 Capitalization and liabilities: Common equity $ 3,688,713 $ 3,531,225 Long-term debt 1,808,828 1,783,898 Total capitalization 5,497,541 5,315,123 Current liabilities: Account Payable 15,801 171 Interest 25,523 25,606 Unrealized loss on derivative instruments 141 4,753 Total current liabilities 41,465 30,530 Long-term liabilities: Unrealized loss on derivative instruments — 297 Total long-term liabilities — 297 Commitments and contingencies Total capitalization and liabilities $ 5,539,006 $ 5,345,950 _______________ 1 Eliminated in consolidation. See accompanying notes to the condensed financial statements. Puget Energy Condensed Statements of Cash Flows (Dollars in Thousands) Year Ended December 31, 2016 2015 2014 Operating activities: Net cash provided by (used in) operating activities $ 145,719 $ 171,576 $ 225,459 Investing activities: Investment in subsidiaries — (28,900 ) — (Increase) decrease in loan to subsidiary — 28,933 665 Other (6,078 ) (5,632 ) (2,829 ) Net cash provided by (used in) investing activities (6,078 ) (5,599 ) (2,164 ) Financing activities: Dividends paid (148,965 ) (263,059 ) (223,428 ) Issuance of bond — 400,000 — Issuance/redemption of term-loan and other long-term debt 12,480 (299,000 ) — Issue costs and others (3,398 ) (3,341 ) 4 Net cash provided by (used in) by financing activities (139,883 ) (165,400 ) (223,424 ) Increase (decrease) in cash (242 ) 577 (129 ) Cash at beginning of year 639 62 191 Cash at end of year $ 397 $ 639 $ 62 See accompanying notes to the condensed financial statements. NOTES TO CONDENSED FINANCIAL STATEMENTS (1) Basis of Presentation Puget Energy is an energy services holding company that conducts substantially all of its business operations through its regulated subsidiary, PSE. Puget Energy also has a wholly-owned non-regulated subsidiary, named Puget LNG, LLC (Puget LNG). Puget LNG, was formed on November 29, 2016, and has the sole purpose of owning, developing and financing the non-regulated activity of a LNG facility at the Port of Tacoma, Washington. These condensed financial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These financial statements, in which Puget Energy’s subsidiaries have been included using the equity method, should be read in conjunction with the consolidated financial statements and notes thereto of Puget Energy included in Item 8, "Financial Statements and Supplementary Data" of this Form 10-K. Puget Energy owns 100% of the common stock of its subsidiaries. Equity earnings of subsidiary included earnings from PSE of $380.6 million , $304.2 million and $236.6 million for the years ended December 31, 2016 , 2015 and 2014 , respectively, and business combination accounting adjustments under ASC 805 recorded at Puget Energy for PSE of $5.2 million , $5.4 million and $3.5 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. Investment in subsidiaries includes Puget Energy business combination accounting adjustments under ASC 805 that are recorded at Puget Energy. Change in Accounting Principle On January 1, 2016, the Company changed its method of presenting unamortized debt issuance costs in the balance sheet. The new method of presenting debt issuance costs was adopted to comply with ASU 2015-03, "Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs" . ASU 2015-03 requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability, consistent with the presentation of a debt discount. The prior year comparative balance sheet has been adjusted to apply the new method retrospectively. Due to the change in accounting principle, the December 31, 2015 long-term asset financial statement line item “Other” and the liability financial statement line item “Long-term debt” both decreased $15.6 million at Puget Energy. (2) Debt For information concerning Puget Energy’s long-term debt obligations, see Note 6, "Long-Term Debt" to the consolidated financial statements included in Item 8 of this report. (3) Commitments and Contingencies For information concerning Puget Energy’s material contingencies and guarantees, see Note 15, "Commitments and Contingencies" to the consolidated financial statements included in Item 8 of this report. |
SCHEDULE II VALUATION AND QUALI
SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES | 12 Months Ended |
Dec. 31, 2016 | |
Valuation and Qualifying Accounts [Abstract] | |
Schedule II: Valuation and Qualifying Accounts and Reserves | SCHEDULE II: VALUATION AND QUALIFYING ACCOUNTS AND RESERVES Puget Energy and Puget Sound Energy (Dollars in Thousands) Balance at Beginning of Period Additions Charged to Costs and Expenses Deductions Balance at End of Period Year Ended December 31, 2016 Accounts deducted from assets on balance sheet: Allowance for doubtful accounts receivable $ 9,756 $ 24,389 $ 24,347 $ 9,798 Year Ended December 31, 2015 Accounts deducted from assets on balance sheet: Allowance for doubtful accounts receivable $ 7,472 $ 20,732 $ 18,448 $ 9,756 Year Ended December 31, 2014 Accounts deducted from assets on balance sheet: Allowance for doubtful accounts receivable $ 7,385 $ 27,228 $ 27,141 $ 7,472 |
Summary of Significant Accoun29
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Policies [Abstract] | |
Basis of Presentation | Basis of Presentation Puget Energy, Inc. (Puget Energy) is an energy services holding company that owns Puget Sound Energy, Inc. (PSE). PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering 6,000 square miles, primarily in the Puget Sound region. 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 Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805), 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 PSE’s financial statements do not include any ASC 805 purchase accounting adjustments. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (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. |
Utility Plant | Utility Plant Puget Energy and PSE capitalize, at original cost, additions to utility plant, including renewals and betterments. Costs include indirect costs such as engineering, supervision, certain taxes, pension and other employee benefits and an allowance for funds used during construction (AFUDC). Replacements of minor items of property are included in maintenance expense. When the utility plant is retired and removed from service, the original cost of the property is charged to accumulated depreciation and costs associated with removal of the property, less salvage, are charged to the cost of removal regulatory liability. Planned Major Maintenance Planned major maintenance is an activity that typically occurs when PSE overhauls or substantially upgrades various systems and equipment on its natural gas fired combustion turbines on a scheduled basis. Costs related to planned major maintenance are deferred and amortized to the next scheduled major maintenance. This accounting method also follows the Washington Utilities and Transportation Commission (Washington Commission) regulatory treatment related to these generating facilities. Non-Utility Property, Plant and Equipment For PSE, the costs of other property, plant and equipment are stated at historical cost. Expenditures for refurbishment and improvements that significantly add to productive capacity or extend useful life of an asset are capitalized. Replacements of minor items are expensed on a current basis. Gains and losses on assets sold or retired, which were previously recorded in utility plant, are apportioned between regulatory assets/liabilities and earnings. However, gains and losses on assets sold or retired, not previously recorded in utility plant, are reflected in earnings. |
Depreciation and Amortization | Depreciation and Amortization For financial statement purposes, the Company provides for depreciation and amortization on a straight-line basis. Amortization is recorded for intangibles such as regulatory assets and liabilities, computer software and franchises. The depreciation of vehicles and equipment is allocated to the asset and expense accounts based on usage. The annual depreciation provision stated as a percent of a depreciable electric utility plant was 2.8% , for each of 2016 , 2015 and 2014 ; depreciable natural gas utility plant was 3.4% , for each of 2016 , 2015 and 2014 ; and depreciable common utility plant was 9.7% , 8.5% and 8.5% in 2016 , 2015 and 2014 , respectively. Depreciation on other property, plant and equipment is calculated primarily on a straight-line basis over the useful lives of the assets. The cost of removal is collected from PSE’s customers through depreciation expense and any excess is recorded as a regulatory liability. |
Goodwill | Goodwill In 2009, Puget Holdings completed its merger with Puget Energy. Puget Energy remeasured the carrying amount of all its assets and liabilities to fair value, which resulted in recognition of approximately $1.7 billion in goodwill. ASC 350, “Intangibles - Goodwill and Other” (ASC 350), requires that goodwill be tested for impairment at the reporting unit level on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. These events or circumstances could include a significant change in the Company’s business or regulatory outlook, legal factors, a sale or disposition of a significant portion of a reporting unit or significant changes in the financial markets which could influence the Company’s access to capital and interest rates. Application of the goodwill impairment test requires judgment, including the identification of reporting units, assignment of assets and liabilities to reporting units, assignment of goodwill to reporting units and the determination of the fair value of the reporting units. Management has determined Puget Energy has only one reporting unit. The goodwill recorded by Puget Energy represents the potential long-term return to the Company’s investors. Goodwill is tested for impairment annually using a two-step process. The first step compares the carrying amount of the reporting unit with its fair value, with a carrying value higher than fair value indicating potential impairment. If the first step test fails, the second step is performed. This would entail a full valuation of Puget Energy’s assets and liabilities and comparing the valuation to its carrying amounts, with the aggregate difference indicating the amount of impairment. Goodwill of a reporting unit is required to be tested for impairment on an interim basis if an event occurs or circumstances change that would cause the fair value of a reporting unit to fall below its carrying amount. Puget Energy conducted its annual impairment test in 2016 using an October 1, 2016 measurement date. The fair value of Puget Energy’s reporting unit was estimated using both discounted cash flow and market approach. Such approaches are considered methodologies that market participants would use. This analysis requires significant judgments, including estimation of future cash flows, which is dependent on internal forecasts, estimation of long-term rate of growth for Puget Energy business, estimation of the useful life over which cash flows will occur, the selection of utility holding companies determined to be comparable to Puget Energy and determination of an appropriate weighted-average cost of capital or discount rate. The market approach estimates the fair value of the business based on market prices of stocks of comparable companies engaged in the same or similar lines of business. In addition, indications of market value are estimated by deriving multiples of equity or invested capital to various measures of revenue, earnings or cash flow. Changes in these estimates and/or assumptions could materially affect the determination of fair value and goodwill impairment of the reporting unit. Based on the test performed, management has determined that there was no indication of impairment of Puget Energy’s goodwill as of October 1, 2016 . There were no known events or circumstances from the date of the assessment through December 31, 2016 that would impact management’s conclusion. |
Cash and Cash Equivalents | Cash and Cash Equivalents Cash and cash equivalents consist of demand bank deposits and short-term highly liquid investments with original maturities of three months or less at the time of purchase. The carrying amounts of cash and cash equivalents are reported at cost and approximate fair value, due to the short-term maturity. |
Materials and Supplies | Materials and Supplies Materials and supplies are used primarily in the operation and maintenance of electric and natural gas distribution and transmission systems as well as spare parts for combustion turbines used for the generation of electricity. Puget Energy and PSE record these items at weighted-average cost. |
Fuel and Gas Inventory | Fuel and Natural Gas Inventory Fuel and natural gas inventory is used in the generation of electricity and for future sales to the Company’s natural gas customers. Fuel inventory consists of coal, diesel and natural gas used for generation. Natural gas inventory consists of natural gas and liquefied natural gas (LNG) held in storage for future sales. Puget Energy and PSE record these items at the lower of cost or market value using the weighted-average cost method. |
Regulatory Assets and Liabilities | Regulatory Assets and Liabilities PSE accounts for its regulated operations in accordance with ASC 980, “Regulated Operations” (ASC 980). ASC 980 requires PSE to defer certain costs that would otherwise be charged to expense, if it is probable that future rates will permit recovery of such costs. It similarly requires deferral of revenues or gains and losses that are expected to be returned to customers in the future. Accounting under ASC 980 is appropriate as long as rates are established by or subject to approval by independent third-party regulators; rates are designed to recover the specific enterprise’s cost of service; and in view of demand for service, it is reasonable to assume that rates set at levels that will recover costs can be charged to and collected from customers. In most cases, PSE classifies regulatory assets and liabilities as long-term due to the length of the amortization. For further details regarding regulatory assets and liabilities, see Note 3, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report. |
Allowance for Funds Used During Construction | Allowance for Funds Used During Construction AFUDC represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period. The amount of AFUDC recorded in each accounting period varies depending primarily upon the level of construction work in progress and the AFUDC rate used. AFUDC is capitalized as a part of the cost of utility plant; the AFUDC debt portion is credited to interest expense, while the AFUDC equity portion is credited to other income. Cash inflow related to AFUDC does not occur until these charges are reflected in rates. The current AFUDC rate authorized by the Washington Commission for natural gas and electric utility plant additions as of July 1, 2013 is 7.77% . The Washington Commission authorized the Company to calculate AFUDC using its allowed rate of return. To the extent amounts calculated using this rate exceed the AFUDC calculated rate using the Federal Energy Regulatory Commission (FERC) formula, PSE capitalizes the excess as a deferred asset, crediting other income. The deferred asset is being amortized over the average useful life of PSE’s non-project electric utility plant which is approximately 30 years . |
Revenue Recognition | Revenue Recognition Operating utility revenue is recognized when the basis of services is rendered, which includes estimated unbilled revenue, in accordance with ASC 605, “Revenue Recognition” (ASC 605). PSE's estimate of unbilled revenue is based on a calculation using meter readings from its automated meter reading (AMR) system. The estimate calculates unbilled usage at the end of each month as the difference between the customer meter readings on the last day of the month and the last customer meter readings billed. The unbilled usage is then priced at published rates for each schedule to estimate the unbilled revenues by customer. PSE collected Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes totaling $235.3 million , $234.2 million and $231.7 million for 2016 , 2015 and 2014 , respectively. The Company reports the collection of such taxes on a gross basis in operation revenue and as expense in taxes other than income taxes in the accompanying consolidated statements of income. The non-utility subsidiary recognizes revenue when services are performed or upon the sale of assets. Revenue from retail sales is billed based on tariff rates approved by the Washington Commission. PSE's electric and natural gas operations contain a revenue decoupling mechanism under which PSE's actual energy delivery revenues related to electric transmission and distribution, natural gas operations and general administrative costs are compared with authorized revenues allowed under the mechanism. The mechanism mitigates volatility in revenue due to weather and gross margin erosion related to energy efficiency. Any differences in revenue are deferred to a regulatory asset for under recovery or regulatory liability for over recovery under alternative revenue recognition standard. To record revenues under this program, the Company must be able to collect the revenue within 24 months based on alternative revenue recognition guidance. Decoupled rate increases are effective May 1 of each year subject to a 3.0% cap of total revenue for decoupled rate schedules. Any excess revenue above 3.0% will be included in the following year's decoupled rate. The Company will be able to recognize revenue below the 3.0% cap of total revenue for decoupled rate schedules. For revenue deferrals exceeding the annual 3.0% rate cap of total revenue for decoupled rate schedules, the Company will assess the excess amount to determine its ability to be collected within 24 months. For GAAP purposes only, the Company will not record any decoupling revenue that is expected to take longer than 24 months to collect following the end of the annual period in which the revenues would have otherwise been recognized. Once determined to be collectible within 24 months, any previously non-recorded amounts will be recorded. Revenues associated with energy costs under the power cost adjustment (PCA) mechanism and purchased gas adjustment (PGA) mechanism are excluded from the decoupling mechanism. |
Allowance for Doubtful Accounts | Allowance for Doubtful Accounts Allowance for doubtful accounts are provided for electric and natural gas customer accounts based upon a historical experience rate of write-offs of energy accounts receivable along with information on future economic outlook. The allowance account is adjusted monthly for this experience rate. The allowance account is maintained until either receipt of payment or the likelihood of collection is considered remote at which time the allowance account and corresponding receivable balance are written off. The Company’s balance for allowance for doubtful accounts at December 31, 2016 and 2015 was $9.8 million each year. |
Self Insurance | Self-Insurance PSE is self-insured for storm damage and environmental contamination occurring on PSE-owned property. In addition, PSE is required to meet a deductible for a portion of the risk associated with comprehensive liability, workers’ compensation claims and catastrophic property losses other than those which are storm related. The Washington Commission has approved the deferral of certain uninsured qualifying storm damage costs that exceed $8.0 million which will be requested for collection in future rates. Additionally, costs may only be deferred if the outage meets the Institute of Electrical and Electronics Engineers (IEEE) outage criteria for system average interruption duration index. |
Federal Income Taxes | Federal Income Taxes For presentation in Puget Energy's and PSE’s separate financial statements, income taxes are allocated to the subsidiaries on the basis of separate company computations of tax, modified by allocating certain consolidated group limitations which are attributed to the separate company. Taxes payable or receivable are settled with Puget Holdings, who is the ultimate tax payer. |
Natural Gas Off System Sales and Capacity Release | Natural Gas Off-System Sales and Capacity Release PSE contracts for firm natural gas supplies and holds firm transportation and storage capacity sufficient to meet the expected peak winter demand for natural gas by its firm customers. Due to the variability in weather, winter peaking consumption of natural gas by most of its customers and other factors, PSE holds contractual rights to natural gas supplies and transportation and storage capacity in excess of its average annual requirements to serve firm customers on its distribution system. For much of the year, there is excess capacity available for third-party natural gas sales, exchanges and capacity releases. PSE sells excess natural gas supplies, enters into natural gas supply exchanges with third parties outside of its distribution area and releases to third parties excess interstate natural gas pipeline capacity and natural gas storage rights on a short-term basis to mitigate the costs of firm transportation and storage capacity for its core natural gas customers. The proceeds from such activities, net of transactional costs, are accounted for as reductions in the cost of purchased natural gas and passed on to customers through the PGA mechanism, with no direct impact on net income. |
Non-Core Gas Sales | Non-Core Natural Gas Sales As part of the Company’s electric operations, PSE purchases natural gas for its gas-fired generation facilities. The projected volume of natural gas for power is relative to the price of natural gas. Based on the market prices for natural gas, PSE may use the natural gas it has already purchased to generate power or PSE may sell the already purchased natural gas. The net proceeds from selling natural gas, previously purchased for power generation, are accounted for in electric operating revenue and are included in the PCA mechanism. |
Production Tax Credit | Production Tax Credit Production Tax Credits (PTCs) represent federal income tax incentives available to taxpayers that generate energy from qualifying renewable sources. PSE records the benefit of the PTCs as a deferred credit until such time as PSE utilizes the tax credit on its tax return. Once utilized, PSE will reclassify the credits to a regulatory liability and pass the benefit to customers. |
Accounting for Derivatives | Accounting for Derivatives ASC 815 requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair value unless the contracts qualify for an exception. PSE enters into derivative contracts to manage its energy resource portfolio and interest rate exposure including forward physical and financial contracts and swaps. Some of PSE’s physical electric supply contracts qualify for the normal purchase normal sale (NPNS) exception to derivative accounting rules. PSE may enter into financial fixed price contracts to economically hedge the variability of certain index-based contracts. Those contracts that do not meet the NPNS exception are marked-to-market to current earnings in the statements of income, subject to deferral under ASC 980, for natural gas related derivatives due to the PGA mechanism. Puget Energy and PSE elected to de-designate all energy related derivative contracts previously recorded as cash flow hedges for the purpose of simplifying its financial reporting. The contracts that were de-designated related to physical electric supply contracts and natural gas swap contracts used to fix the price of natural gas for electric generation. For these contracts and for contracts initiated after such date, all mark-to-market adjustments are recognized through earnings. The amount previously recorded in accumulated other comprehensive income (AOCI) is transferred to earnings in the same period or periods during which the hedged transaction affects earnings or sooner if management determines that the forecasted transaction is probable of not occurring. When these contracts are settled, the contract price becomes part of purchased electricity or electric generation fuel which becomes part of PSE’s PCA mechanism and the unrealized gain or loss is listed separately under energy costs, as it represents the non-rate treatment of energy costs. The Company may enter into swap instruments or other financial derivative instruments to manage the interest rate risk associated with its long-term debt financing and debt instruments. As of December 31, 2016 , Puget Energy has interest rate swap contracts outstanding originally related to its long-term debt. For additional information, see Note 9 , "Accounting for Derivative Instruments and Hedging Activities" to the consolidated financial statements included in Item 8 of this report. |
Fair Value Measurements of Derivatives | Fair Value Measurements of Derivatives ASC 820, “Fair Value Measurements and Disclosures” (ASC 820), defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). As permitted under ASC 820, the Company utilizes a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing the majority of its assets and liabilities measured and reported at fair value. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company primarily applies the market approach for recurring fair value measurements as it believes that the approach is used by market participants for these types of assets and liabilities. Accordingly, the Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company values derivative instruments based on daily quoted prices from an independent external pricing service. When external quoted market prices are not available for derivative contracts, the Company uses a valuation model that uses volatility assumptions relating to future energy prices based on specific energy markets and utilizes externally available forward market price curves. All derivative instruments are sensitive to market price fluctuations that can occur on a daily basis. For additional information, see Note 10 , "Fair Value Measurements" to the consolidated financial statements included in Item 8 of this report. |
Debt Related Costs | Debt Related Costs Debt premiums, discounts, expenses and amounts received or incurred to settle hedges are amortized over the life of the related debt for the Company. The premiums and costs associated with reacquired debt are deferred and amortized over the life of the related new issuance, in accordance with ratemaking treatment for PSE. |
Regulation and Rates (Tables)
Regulation and Rates (Tables) | 6 Months Ended | 12 Months Ended |
Jun. 30, 2013 | Dec. 31, 2016 | |
Regulation and Rates [Line Items] | ||
Schedule of Net Regulatory Assets and Liabilities | The net regulatory assets and liabilities at December 31, 2016 and 2015 included the following: Puget Sound Energy Remaining Amortization Period December 31, (Dollars in Thousands) 2016 2015 Colstrip Regulatory Asset (a) $ 176,804 $ — Storm damage costs electric 1 to 2 years 122,709 125,777 Chelan PUD contract initiation 14.8 years 105,140 112,228 Decoupling deferrals and interest 156,408 104,150 Decoupling 24-month revenue reserve (20,847 ) (9,980 ) Total decoupling asset Less than 2 years 135,561 94,170 Lower Snake River 1 to 20.3 years 74,862 79,599 Deferred income taxes (a) 71,517 72,694 Environmental remediation (a) 74,557 66,887 Baker Dam licensing operating and maintenance costs 42 years 61,453 63,394 PGA deferral of unrealized losses on derivative instruments (a) — 60,889 Deferred Washington Commission AFUDC 35 years 51,404 52,197 Unamortized loss on reacquired debt 1 to 30 years 42,196 44,984 Property tax tracker Less than 2 years 41,949 40,353 Energy conservation costs 1 to 2 years 41,027 36,646 White River relicensing and other costs 15.9 years 21,627 23,054 Mint Farm ownership and operating costs 8.3 years 16,319 18,320 Ferndale 2.8 years 11,274 15,253 Electron unrecovered loss 2 years 7,178 10,569 Snoqualmie licensing operating and maintenance costs 28 years 8,018 7,980 Colstrip common property (a) 5,334 6,049 Colstrip major maintenance 2 years 6,589 5,897 Investment in Bonneville Exchange power contract 1 year 1,763 5,290 Snoqualmie 1.8 years 3,251 5,024 PCA mechanism (a) 4,531 — PGA receivable 1 year 2,785 — Various other regulatory assets Varies 25,337 24,248 Total PSE regulatory assets 1,113,185 971,502 Cost of removal (b) (369,300 ) (347,472 ) Treasury grants 3 to 42 years (133,709 ) (157,102 ) Production tax credits (c) (93,616 ) (93,616 ) Decoupling ROR excess earnings (13,300 ) (25,483 ) Decoupling deferrals and interest (16,448 ) — Total decoupling liability Less than 2 years (29,748 ) (25,483 ) PGA payable 1 year — (12,589 ) Summit purchase option buy-out 3.8 years (6,038 ) (7,612 ) Deferral of treasury grant amortization Less than 3 years (3,920 ) (6,058 ) PGA deferral of unrealized gains on derivative instruments (a) (7,517 ) — Lower Snake River interest due Less than 2 years (4,189 ) — Various other regulatory liabilities Up to 4 years (5,259 ) (13,751 ) Total PSE regulatory liabilities (653,296 ) (663,683 ) PSE net regulatory assets (liabilities) $ 459,889 $ 307,819 _______________ (a) Amortization periods vary depending on timing of underlying transactions or awaiting regulatory approval in a future Washington Commission rate proceeding. (b) The balance is dependent upon the cost of removal of underlying assets and the life of utility plant. (c) Amortization will begin once PTCs are utilized by PSE on its tax return. Puget Energy Remaining Amortization Period December 31, (Dollars in Thousands) 2016 2015 Total PSE regulatory assets (a) $ 1,113,185 $ 971,502 Puget Energy acquisition adjustments: Regulatory assets related to power contracts 1 to 21 years 22,613 26,223 Various other regulatory assets Varies 517 549 Total Puget Energy regulatory assets 1,136,315 998,274 Total PSE regulatory liabilities (a) (653,296 ) (663,683 ) Puget Energy acquisition adjustments: Regulatory liabilities related to power contracts 1 to 36 years (275,061 ) (325,788 ) Various other regulatory liabilities Varies (1,326 ) (1,347 ) Total Puget Energy regulatory liabilities (929,683 ) (990,818 ) Puget Energy net regulatory asset (liabilities) $ 206,632 $ 7,456 _______________ (a) Puget Energy’s regulatory assets and liabilities include purchase accounting adjustments under ASC 805. | |
Decoupling Mechanism [Member] | ||
Regulation and Rates [Line Items] | ||
Schedule of Graduated Scale of Rate Adjustment Mechanisms [Table Text Block] [Table Text Block] | In addition, PSE exceeded the earnings test threshold in 2016, 2015 and 2014. The amount of the reduction to the 2016 decoupling deferral will not be known until the final earnings test result is filed in PSE's decoupling mechanism filing that will be made on March 31, 2017. PSE recorded the following reductions in decoupling deferrals to the electric and natural gas rate increases above: Effective Date Reduction in Rate Increases due to Excess Earnings (Dollars in Millions) Electric: 2016 (estimated) $11.2 2015 16.3 2014 3.4 Natural Gas: 2016 (estimated) $2.1 2015 9.2 2014 — | |
Schedule of Graduated Scale of Rate Adjustment Mechanisms | The Washington Commission approved the following PSE requests to change rates under its electric and natural gas decoupling mechanisms: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) Electric: May 1, 2016 1.0% $20.8 May 1, 2015 2.6 53.8 May 1, 2014 0.5 10.6 Natural Gas: May 1, 2016 2.8% $25.4 May 1, 2015 2.1 22.0 May 1, 2014 (0.1) (1.0) | |
Schedule of Deferrals Not Included in Rate Increases [Table Text Block] | As noted earlier, the Company is also limited to a 3.0% annual decoupling related cap on increases in total revenue. This limitation has been triggered as follows: Effective Date Accrued Through Deferrals not Included in Annual Rate Increases (Dollars in Millions) Electric: 2015 $— 2014 1.9 Natural Gas: 2015 $28.7 2014 8.2 Existing deferrals may be included in customer rates beginning in May 2018, subject to subsequent application of the earnings test and the 3.0% cap on decoupling related rate increases. | |
Power Cost Only Rate Case (PCORC) | Electric [Member] | ||
Regulation and Rates [Line Items] | ||
Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments | The following table sets forth PCORC and update compliance filing rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) December 1, 2016 (1.7)% $(37.3) December 1, 2014 (0.9) (19.4) | |
Property tax tracker | Electric [Member] | ||
Regulation and Rates [Line Items] | ||
Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments | The following table sets forth property tax tracker mechanism rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) May 1, 2016 0.3% $5.7 May 1, 2015 0.3 6.5 May 1, 2014 0.5 11.0 | |
Property tax tracker | Gas | ||
Regulation and Rates [Line Items] | ||
Schedule of Graduated Scale of Rate Adjustment Mechanisms | The following table sets forth property tax tracker mechanism rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) May 1, 2016 0.4% $3.5 June 1, 2015 (0.2) (2.3) May 1, 2014 0.6 5.6 | |
Conservation Rider [Member] | Electric [Member] | ||
Regulation and Rates [Line Items] | ||
Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments | The following table sets forth conservation rider rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) May 1, 2017, proposed 0.7% $16.5 May 1, 2016 (0.5) (11.7) May 1, 2015 0.2 4.2 May 1, 2014 0.6 12.2 | |
Conservation Rider [Member] | Gas | ||
Regulation and Rates [Line Items] | ||
Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments | The following table sets forth conservation rider rate adjustments approved by the Washington Commission and the corresponding annual impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) May 1, 2017, proposed (0.1)% (1.0) May 1, 2016 0.3 2.9 May 1, 2015 0.2 2.3 | |
PCA Mechanism [Member] | Electric [Member] | ||
Regulation and Rates [Line Items] | ||
Schedule of Graduated Scale of Rate Adjustment Mechanisms | Annual Power Cost Variability Company’s Share Customers' Share +/- $20 million 100% —% +/- $20 million - $40 million 50 50 +/- $40 million - $120 million 10 90 +/- $120 + million 5 95 | On August 7, 2015, the Washington Commission issued an order approving the settlement proposing changes to the PCA mechanism. The settlement agreement took effect January 1, 2017 and will apply the following graduated scale: Annual Power Cost Variability Company's Share Customers' Share Over or Under Collection: 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 |
Treasury grants | Electric [Member] | ||
Regulation and Rates [Line Items] | ||
Schedule of Graduated Scale of Rate Adjustment Mechanisms | The following table sets forth Federal Incentive Tracker Tariff rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates from prior year Total credit to be passed back to eligible customers (Dollars in Millions) January 1, 2017, proposed 0.3% $(51.7) January 1, 2016 (0.2) (57.3) January 1, 2015 (0.2) (55.2) January 1, 2014 (0.3) (58.5) | |
Cost recovery mechanism [Member] | Gas | ||
Regulation and Rates [Line Items] | ||
Schedule of Graduated Scale of Rate Adjustment Mechanisms | The following table sets forth CRM rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) November 1, 2016 0.6% $5.6 November 1, 2015 0.5 5.3 November 1, 2014 0.2 2.3 | |
Purchased Gas Adjustment (PGA) | Gas | ||
Regulation and Rates [Line Items] | ||
Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments | The following table sets forth PGA rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) November 1, 2016 (0.4)% $(4.1) November 1, 2015 (17.4) (185.9) November 1, 2014 2.5 23.3 |
Utility Plant (Tables)
Utility Plant (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Utility Plant [Abstract] | |
Schedule of Utility Plant | Puget Energy Puget Sound Energy Utility Plant Estimated Useful Life At December 31, At December 31, (Dollars in Thousands) (Years) 2016 2015 2016 2015 Distribution plant 10-50 $ 5,287,542 $ 5,007,077 $ 6,922,176 $ 6,657,597 Production plant 25-125 3,007,546 3,028,481 3,910,129 3,950,231 Transmission plant 45-65 1,307,687 1,236,823 1,420,334 1,351,216 General plant 5-35 541,424 491,845 611,237 563,850 Intangible plant (including capitalized software) 3-50 347,697 305,705 338,327 294,380 Plant acquisition adjustment 2-22 242,826 242,826 282,792 282,792 Underground storage 25-60 30,695 28,914 44,206 42,545 Liquefied natural gas storage 25-45 12,628 12,628 14,498 14,498 Plant held for future use NA 52,484 55,890 52,636 56,042 Recoverable Cushion Gas NA 8,655 8,655 8,655 8,655 Plant not classified 1-125 159,345 65,892 159,345 65,892 Grant NA (99,100 ) (102,379 ) (99,100 ) (102,379 ) Capital leases, net of accumulated amortization 1 2 645 378 645 378 Less: accumulated provision for depreciation (2,161,796 ) (1,878,868 ) (4,927,602 ) (4,681,830 ) Subtotal $ 8,738,278 $ 8,503,867 $ 8,738,278 $ 8,503,867 Construction work in progress NA 420,278 408,795 420,278 408,795 Net utility plant $ 9,158,556 $ 8,912,662 $ 9,158,556 $ 8,912,662 _______________ 1 Accumulated amortization of capital leases at Puget Energy and PSE was $0.6 million in 2016 and $32.3 million in 2015 . |
Schedule of Jointly Owned Utility Plants | These amounts are also included in the Utility Plant table above. Puget Energy’s Share Puget Sound Energy’s Share Jointly Owned Generating Plants (Dollars in Thousands) Energy Source (Fuel) Company’s Ownership Share Plant in Service at Cost Accumulated Depreciation Plant in Service at Cost Accumulated Depreciation Colstrip Units 1 & 2 Coal 50% $ 70,717 $ (22,284 ) $ 204,334 $ (155,902 ) Colstrip Units 3 & 4 Coal 25% 307,383 (40,343 ) 575,902 (308,861 ) Colstrip Units 1 – 4 Common Facilities Coal various 83 (27 ) 252 (196 ) Frederickson 1 Natural Gas 49.85% 61,780 (9,779 ) 70,729 (18,728 ) Jackson Prairie Natural Gas Storage 33.34% 30,021 (5,544 ) 44,206 (19,730 ) |
Schedule of Asset Retirement Obligations | The following table describes the changes to the Company’s ARO liability as of December 31, 2016 and 2015 : At December 31, (Dollars in Thousands) 2016 2015 Asset retirement obligation at beginning of period $ 85,028 $ 48,909 New asset retirement obligation recognized in the period — 34,534 Liability adjustment in the period (411 ) (3,628 ) Revisions in estimated cash flows 113,081 3,403 Accretion expense 2,647 1,810 Asset retirement obligation at end of period $ 200,345 $ 85,028 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Debt Instrument [Line Items] | |
Schedule of Long-Term Debt Instruments | (Dollars in Thousands) At December 31, Series Type Due 2016 2015 Puget Sound Energy: 5.500% Promissory Note 2017 $ 2,412 $ 2,412 6.740% Senior Secured Note 2018 200,000 200,000 7.150% First Mortgage Bond 2025 15,000 15,000 7.200% First Mortgage Bond 2025 2,000 2,000 7.020% Senior Secured Note 2027 300,000 300,000 7.000% Senior Secured Note 2029 100,000 100,000 3.900% Pollution Control Bond 2031 138,460 138,460 4.000% Pollution Control Bond 2031 23,400 23,400 5.483% Senior Secured Note 2035 250,000 250,000 6.724% Senior Secured Note 2036 250,000 250,000 6.274% Senior Secured Note 2037 300,000 300,000 5.757% Senior Secured Note 2039 350,000 350,000 5.795% Senior Secured Note 2040 325,000 325,000 5.764% Senior Secured Note 2040 250,000 250,000 4.434% Senior Secured Note 2041 250,000 250,000 5.638% Senior Secured Note 2041 300,000 300,000 4.300% Senior Secured Note 2045 425,000 425,000 4.700% Senior Secured Note 2051 45,000 45,000 6.974% Junior Subordinated Note 2067 250,000 250,000 * Debt discount, issuance cost and other * (28,974 ) (31,910 ) Total PSE long-term debt 3,747,298 3,744,362 Puget Energy: * Fair value adjustment of PSE long-term debt * (199,436 ) (207,977 ) * Revolving Credit Agreement 2018 12,480 — 6.500% Senior Secured Note 2020 450,000 450,000 6.000% Senior Secured Note 2021 500,000 500,000 5.625% Senior Secured Note 2022 450,000 450,000 3.650% Senior Secured Note 2025 400,000 400,000 * Debt discount, issuance cost and other * (6,269 ) (8,867 ) Total Puget Energy long-term debt $ 5,354,073 $ 5,327,518 _______________ * Not Applicable. PSE's s |
Schedule of Maturities of Long-Term Debt | pal amounts of long-term debt maturities for the next five years and thereafter are as follows: (Dollars in Thousands) 2017 2018 2019 2020 2021 Thereafter Total Maturities of: PSE long-term debt $ 2,412 $ 200,000 $ — $ — $ — $ 3,573,860 $ 3,776,272 Puget Energy long-term debt — 12,480 — 450,000 500,000 850,000 1,812,480 Puget Energy long-term debt $ 2,412 $ 212,480 $ — $ 450,000 $ 500,000 $ 4,423,860 $ 5,588,752 |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Leases [Abstract] | |
Schedule of Operating Lease Expense | Operating lease expenses net of sublease receipts were: (Dollars in Thousands) At December 31, Years Operating Lease Expense 2016 $ 31,786 2015 27,843 2014 30,737 |
Schedule of Future Minimum Lease Payments for Non-cancellable Leases | Future minimum lease payments for non-cancelable leases net of sublease receipts are: (Dollars in Thousands) At December 31, Future Minimum Lease Payments Years Operating Capital 2017 $ 22,212 $ 296 2018 19,834 296 2019 18,078 74 2020 16,507 — 2021 8,137 — Thereafter 102,393 — Total minimum lease payments $ 187,161 $ 666 |
Accounting for Derivative Ins34
Accounting for Derivative Instruments and Hedging Activities (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Derivative [Line Items] | |
Schedule of Credit Risk Related Contingent Features [Table Text Block] | The table below presents the fair value of the overall contractual contingent liability positions for the Company's derivative activity: Puget Energy and Puget Sound Energy At December 31, (Dollars in Thousands) 2016 2015 Contingent Feature Fair Value 1 Liability Posted Collateral Contingent Collateral Fair Value 1 Liability Posted Collateral Contingent Collateral Credit rating 2 $ 4,894 $ — $ 4,894 $ 24,187 $ — $ 24,187 Requested credit for adequate assurance 7,427 — — 67,003 — — Forward value of contract 3 507 — — — — — Total $ 12,828 $ — $ 4,894 $ 91,190 $ — $ 24,187 _______________ 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. |
Offsetting Assets and Liabilities [Table Text Block] | 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 Puget Sound Energy At December 31, 2016 (Dollars in Thousands) Gross Amounts 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 Commodity Contracts Cash Collateral Received/Posted Net Amount Assets: Energy derivative contracts $ 63,079 $ — $ 63,079 $ (42,858 ) $ — $ 20,221 Liabilities: Energy derivative contracts 60,430 — 60,430 (42,858 ) — 17,572 Interest rate swaps 2 141 — 141 — — 141 Puget Energy and Puget Sound Energy At December 31, 2015 (Dollars in Thousands) Gross Amounts 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 Commodity Contracts Cash Collateral Received/Posted Net Amount Assets: Energy derivative contracts $ 29,643 $ — $ 29,643 $ (23,998 ) $ — $ 5,645 Liabilities: Energy derivative contracts 179,196 — 179,196 (23,998 ) — 155,198 Interest rate swaps 2 5,050 — 5,050 — — 5,050 _______________ 1 All Derivative Contract deals are executed under ISDA, NAESB and WSPP Master Netting Agreements with Right of set-off. 2 Interest Rate Swap Contracts are only held at Puget Energy. |
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value | The following table presents the volumes, fair values and locations of the Company's derivative instruments recorded on the balance sheets: Puget Energy and Puget Sound Energy At Year Ended December 31, (Dollars in Thousands) Volumes (millions) Assets 1 Liabilities 2 2016 2015 2016 2015 2016 2015 Interest rate swap derivatives 3 $450.0 $450.0 $ — $ — $ 141 $ 5,050 Electric portfolio derivatives * * 36,460 23,443 41,329 112,106 Natural gas derivatives (MMBtus) 4 336.4 369.5 26,619 6,200 19,101 67,090 Total derivative contracts ** ** $ 63,079 $ 29,643 $ 60,571 $ 184,246 Current ** ** $ 54,341 $ 24,418 $ 44,310 $ 136,173 Long-term ** ** 8,738 5,225 16,261 48,073 Total derivative contracts ** ** $ 63,079 $ 29,643 $ 60,571 $ 184,246 _______________ 1 Balance sheet location: Current and Long-term Unrealized gain on derivative instruments. 2 Balance sheet location: Current and Long-term Unrealized loss on derivative instruments. 3 Interest rate swap contracts are only held at Puget Energy. 4 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 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 186.8 million One Million British Thermal Units (MMBtus) and purchased electricity of 3.6 million megawatt hours (MWhs) at December 31, 2016 and 202.1 million MMBtus and 0.1 million MWhs at December 31, 2015 . ** Not meaningful and/or applicable. |
Parent Company [Member] | |
Derivative [Line Items] | |
Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance [Table Text Block] | The following tables present the effect and locations of the realized and unrealized gains (losses) of the Company's derivatives recorded on the statements of income: Puget Energy Year Ended December 31, (Dollars in Thousands) Location 2016 2015 2014 Interest rate contracts: Non-hedged interest rate swap (expense) income $ (1,062 ) $ (3,796 ) $ (3,915 ) Interest expense — 560 500 Gas for Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net 62,318 (9,315 ) (42,334 ) Realized Electric generation fuel (39,656 ) (44,648 ) 6,511 Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net 1 21,477 22,548 (41,812 ) Realized Purchased electricity (21,998 ) (39,137 ) (4,212 ) Total gain (loss) recognized in income on derivatives $ 21,079 $ (73,788 ) $ (85,262 ) |
PUGET SOUND ENERGY, INC. | |
Derivative [Line Items] | |
Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance [Table Text Block] | Puget Sound Energy Year Ended December 31, (Dollars in Thousands) Location 2016 2015 2014 Gas for Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net $ 62,318 $ (9,315 ) $ (42,334 ) Realized Electric generation fuel (39,656 ) (44,648 ) 6,511 Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net 1 21,477 22,003 (43,302 ) Realized Purchased electricity (21,998 ) (39,137 ) (4,212 ) Total gain (loss) recognized in income on derivatives $ 22,141 $ (71,097 ) $ (83,337 ) _______________ 1 Differences between Puget Energy and PSE for the twelve months ended December 31, 2015 and 2014 are due to certain derivative contracts recorded at fair value in 2009 and subsequently designated as NPNS or cash flow hedges. These differences occurred through February 2015. |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |
Fair Value Inputs, Liabilities, Quantitative Information | The fair value of the junior subordinated and long-term notes were estimated using the discounted cash flow method with U.S. Treasury yields and Company credit spreads as inputs, interpolating to the maturity date of each issue. Carrying values and estimated fair values were as follows: Puget Energy At December 31, 2016 At December 31, 2015 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Liabilities: Junior subordinated notes 2 $ 250,000 $ 210,261 $ 250,000 $ 211,173 Long-term debt (fixed-rate), net of discount 1 2 5,091,593 6,337,287 5,077,518 6,308,831 Long-term debt (variable-rate) 2 12,480 12,480 — — Total $ 5,354,073 $ 6,560,028 $ 5,327,518 $ 6,520,004 Puget Sound Energy At December 31, 2016 At December 31, 2015 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Liabilities: Junior subordinated notes 2 $ 250,000 $ 210,261 $ 250,000 $ 211,173 Long-term debt (fixed-rate), net of discount 2 2 3,497,298 4,360,783 3,494,362 4,329,444 Total $ 3,747,298 $ 4,571,044 $ 3,744,362 $ 4,540,617 |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block] | Puget Energy and Puget Sound Energy Year Ended December 31, Level 3 Roll-Forward Net (Liability) 2016 2015 2014 (Dollars in Thousands) Electric Gas Total Electric Gas Total Electric Gas Total Balance at beginning of period $ (7,345 ) $ (2,383 ) $ (9,728 ) $ (12,062 ) $ (2,040 ) $ (14,102 ) $ (15,421 ) $ (361 ) $ (15,782 ) Changes during period Realized and unrealized energy derivatives: Included in earnings 1 4,007 — 4,007 (6,432 ) — (6,432 ) (5,537 ) — (5,537 ) Included in regulatory assets / liabilities — 4,312 4,312 — 3,695 3,695 — 1,630 1,630 Settlements 2 (1,129 ) (2,679 ) (3,808 ) 902 (3,885 ) (2,983 ) 1,036 (1,534 ) (498 ) Transferred into Level 3 (3,021 ) — (3,021 ) (787 ) — (787 ) 5,155 (585 ) 4,570 Transferred out of Level 3 8,460 1,375 9,835 11,034 (153 ) 10,881 2,705 (1,190 ) 1,515 Balance at end of period $ 972 $ 625 $ 1,597 $ (7,345 ) $ (2,383 ) $ (9,728 ) $ (12,062 ) $ (2,040 ) $ (14,102 ) _______________ 1 Income Statement location: Unrealized (gain) loss on derivative instruments, net. Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $2.0 million , $(7.4) million and $(9.6) million for the years ended December 31, 2016 , 2015 and 2014 , respectively. 2 The Company had no purchases, sales or issuances during the reported periods. |
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Table Text Block] | Below are the forward price ranges for the Company's commodity contracts, as of December 31, 2016 : Puget Energy and Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Average Electric $5,794 $4,822 Discounted cash flow Power Prices $11.86 per MWh $33.52 per MWh $27.61 per MWh Natural gas $3,303 $2,678 Discounted cash flow Natural Gas Prices $2.00 per MMBtu $3.24 per MMBtu $2.42 per MMBtu _______________ 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. At December 31, 2016 , 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 $0.2 million . Below are significant unobservable inputs used in estimating the impaired long term power purchase contracts' fair value in 2016 and 2015 : Puget Energy Valuation Date Unobservable Input Low High Average September 30, 2016 Power prices $24.24 per MWh $58.96 per MWh $39.31 per MWh Power contract costs (in thousands) $618 per year $4,633 per year $2,472 per year March 31, 2016 Power prices $9.46 per MWh $25.96 per MWh $21.38 per MWh Power contract costs (in thousands) $4,100 per qtr. $4,659 per qtr. $4,452 per qtr. December 31, 2015 Power prices $15.16 per MWh $27.25 per MWh $23.23 per MWh Power contract costs (in thousands) $4,100 per qtr. $4,659 per qtr. $4,417 per qtr. 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 impairment on an annual basis, and upon the occurrence of any events or circumstances that would be more likely than not to reduce the fair value of the long-lived assets below their carrying value. One such triggering event is a significant decrease in the forward market prices of power. During 2016 and 2015 , Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets. |
Schedule of Impaired Intangible Assets [Table Text Block] | n 2016 and 2015 , due to decreases in forecasted revenue and cost estimates and continued significant decreases in forward power prices, the following impairments were recorded to the Company's intangible asset contracts, with corresponding reductions to the regulatory liability as follows: Puget Energy (Dollars in Thousands) Valuation Date Contract Name Carrying Value Fair Value Write Down September 30, 2016 Priest Rapids $ 18,969 $ 6,191 $ 12,778 March 31, 2016 Wells Hydro 25,193 19,855 5,338 December 31, 2015 Wells Hydro 32,988 27,628 5,360 |
Fair Value, Measurements, Recurring | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis | The following tables present 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 and the reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy: Puget Energy Fair Value Fair Value At December 31, 2016 At December 31, 2015 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Liabilities: Interest rate derivative instruments $ 141 $ — $ 141 $ 5,050 $ — $ 5,050 Total derivative liabilities $ 141 $ — $ 141 $ 5,050 $ — $ 5,050 Puget Energy and Fair Value Fair Value At December 31, 2016 At December 31, 2015 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Assets: Electric derivative instruments $ 30,666 $ 5,794 $ 36,460 $ 10,709 $ 12,734 $ 23,443 Natural gas derivative instruments 23,316 3,303 26,619 4,538 1,662 6,200 Total derivative assets $ 53,982 $ 9,097 $ 63,079 $ 15,247 $ 14,396 $ 29,643 Liabilities: Electric derivative instruments $ 36,507 $ 4,822 $ 41,329 $ 92,027 $ 20,079 $ 112,106 Natural gas derivative instruments 16,423 2,678 19,101 63,045 4,045 67,090 Total derivative liabilities $ 52,930 $ 7,500 $ 60,430 $ 155,072 $ 24,124 $ 179,196 |
Retirement Benefits (Tables)
Retirement Benefits (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Schedule of Changes in Projected Benefit Obligations | The following tables summarize the Company’s change in benefit obligation, change in plan assets and amounts recognized in the Statements of Financial Position for the years ended December 31, 2016 and 2015 : Puget Energy and Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Change in benefit obligation: Benefit obligation at beginning of period $ 643,088 $ 690,194 $ 51,279 $ 55,855 $ 13,946 $ 15,688 Service cost 18,913 21,287 1,085 1,108 93 112 Interest cost 28,689 28,088 2,325 2,281 533 621 Actuarial loss (gain) 1,545 (55,665 ) 106 (4,430 ) (2,262 ) (1,416 ) Benefits paid (38,730 ) (39,963 ) (3,061 ) (3,535 ) (1,264 ) (1,354 ) Medicare part D subsidy received — — — — 148 295 Administrative expense (898 ) (853 ) — — — — Benefit obligation at end of period $ 652,607 $ 643,088 $ 51,734 $ 51,279 $ 11,194 $ 13,946 |
Schedule of Changes in Fair Value of Plan Assets | Puget Energy and Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Change in plan assets: Fair value of plan assets at beginning of period $ 598,865 $ 626,173 $ — $ — $ 7,203 $ 8,360 Actual return on plan assets 37,022 (4,489 ) — — 926 (378 ) Employer contribution 24,000 18,000 3,061 3,535 335 575 Benefits paid (38,730 ) (39,963 ) (3,061 ) (3,535 ) (1,264 ) (1,354 ) Administrative expense (897 ) (856 ) — — — — Fair value of plan assets at end of period $ 620,260 $ 598,865 $ — $ — $ 7,200 $ 7,203 Funded status at end of period $ (32,347 ) $ (44,223 ) $ (51,734 ) $ (51,279 ) $ (3,994 ) $ (6,743 ) |
Schedule of Amounts Recognized in Balance Sheet and Accumulated Other Comprehensive Income | Puget Energy and Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Amounts recognized in Statement of Financial Position consist of: Noncurrent assets $ — $ — $ — $ — $ — $ — Current liabilities — — (1,911 ) (2,545 ) (325 ) (353 ) Noncurrent liabilities (32,347 ) (44,223 ) (49,823 ) (48,734 ) (3,669 ) (6,390 ) Net assets (liabilities) $ (32,347 ) $ (44,223 ) $ (51,734 ) $ (51,279 ) $ (3,994 ) $ (6,743 ) |
Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets [Table Text Block] | Puget Energy and Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Pension Plans with an Accumulated Benefit Obligation in excess of Plan Assets: Projected benefit obligation $ 652,607 $ 643,088 $ 51,734 $ 51,279 $ 11,194 $ 13,946 Accumulated benefit obligation 641,855 635,599 47,639 46,978 11,092 13,828 Fair value of plan assets 620,260 598,865 — — 7,200 7,203 |
Schedule of Net Benefit Costs | Puget Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2014 2016 2015 2014 2016 2015 2014 Components of net periodic benefit cost: Service cost $ 18,913 $ 21,287 $ 17,437 $ 1,085 $ 1,108 $ 1,042 $ 93 $ 112 $ 112 Interest cost 28,689 28,088 28,039 2,325 2,281 2,310 533 621 684 Expected return on plan assets (46,619 ) (45,038 ) (42,464 ) — — — (446 ) (531 ) (535 ) Amortization of prior service cost (credit) (1,980 ) (1,980 ) (1,980 ) 42 42 42 — — — Amortization of net loss (gain) — 3,887 — 911 1,641 913 (386 ) (130 ) (393 ) Net periodic benefit cost $ (997 ) $ 6,244 $ 1,032 $ 4,363 $ 5,072 $ 4,307 $ (206 ) $ 72 $ (132 ) |
Schedule of Amounts Recognized in Other Comprehensive Income (Loss) | Puget Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ 11,141 $ (6,136 ) $ 106 $ (4,430 ) $ (2,742 ) $ (508 ) Amortization of net loss (gain) — (3,887 ) (910 ) (1,641 ) 385 131 Amortization of prior service credit 1,980 1,980 (42 ) (42 ) — — Total change in other comprehensive income for year $ 13,121 $ (8,043 ) $ (846 ) $ (6,113 ) $ (2,357 ) $ (377 ) |
Schedule of Assumptions Used | In accounting for pension and other benefit obligations and costs under the plans, the following weighted-average actuarial assumptions were used by the Company: Qualified Pension Benefits SERP Pension Benefits Other Benefits Benefit Obligation Assumptions 2016 2015 2014 2016 2015 2014 2016 2015 2014 Discount rate 4.50 % 4.65 % 4.25 % 4.50 % 4.65 % 4.25 % 4.50 % 4.65 % 4.25 % Rate of compensation increase 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 Medical trend rate — — — — — — 8.80 7.20 5.70 Benefit Cost Assumptions Discount rate 4.65 % 4.25 % 5.10 % 4.65 % 4.25 % 5.10 % 4.65 % 4.25 % 5.10 % Return on plan assets 7.75 7.75 7.75 — — — 6.75 7.00 7.00 Rate of compensation increase 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 Medical trend rate — — — — — — 5.30 7.20 6.70 |
Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates | A 1.0% change in the assumed medical inflation rate would have the following effects: 2016 2015 (Dollars in Thousands) 1% Increase 1% Decrease 1% Increase 1% Decrease Effect on post-retirement benefit obligation $ 38 $ (35 ) $ 52 $ (42 ) Effect on service and interest cost components 2 (2 ) 2 (2 ) |
Schedule of Expected Benefit Payments | The expected total benefits to be paid during the next five years and the aggregate total to be paid for the five years thereafter are as follows: (Dollars in Thousands) 2017 2018 2019 2020 2021 2022-2026 Qualified Pension total benefits $ 41,400 $ 42,500 $ 43,600 $ 44,600 $ 45,200 $ 240,800 SERP Pension total benefits 1,911 5,278 5,666 4,454 1,724 34,043 Other Benefits total with Medicare Part D subsidy 928 893 863 829 787 3,873 Other Benefits total without Medicare Part D subsidy 1,256 1,239 1,216 1,191 1,158 5,294 |
Schedule of Allocation of Plan Assets | The following table sets forth by level, within the fair value hierarchy, the qualified pension plan as of December 31, 2016 and 2015 : Recurring Fair Value Measures Recurring Fair Value Measures As of December 31, 2016 As of December 31, 2015 (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Mutual Funds $ 181,212 $ — $ 181,212 $ 169,165 $ — $ 169,165 Common Stock 154,255 — $ 154,255 146,321 — $ 146,321 Government Securities 18,754 16,197 $ 34,951 8,835 14,268 $ 23,103 Corporate Bonds — 38,543 $ 38,543 — 44,157 $ 44,157 Subtotal 354,221 54,740 408,961 324,321 58,425 382,746 Investments measured at NAV 1 * * 222,819 * * 223,663 Net (payable) receivable * * (9,894 ) * * (7,544 ) Total assets * * $ 621,886 * * $ 598,865 _______________ 1 In accordance with ASU 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent)", certain investments that were measured at NAV per share (or its equivalent) have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the line items presented in the statement of net assets available for benefits. Investments measured at NAV consist of common/collective trust funds and two partnerships held as of December 31, 2016 . Mesirow Institutional Multi-Strategy Fund Partnership, L.P. utilizes a combination of long and short strategies through investments in investment funds. The major strategy allocations of the investment funds include (1) Investments in debt obligations of public and private entities; typically in financial duress, and (2) Investments in equity positions on a global basis utilizing fundamental analysis. Grosvenor Institutional Partners Fund, L.P invests substantially all of the fund assets available in the Grosvenor Master Fund, a Cayman Islands exempted company which is sponsored, managed and has the same investment objective as the Partnership fund. In addition to the Master Fund, investments are made primarily in offshore investment funds, investment partnerships, and pooled investment vehicles; collectively referred to as Portfolio Funds, which generally implement "nontraditional" or "alternative" investment strategies. The following table sets forth by level, within the fair value hierarchy, the Other Benefits plan assets which consist of insurance benefits for retired employees, at fair value: Recurring Fair Value Measures Recurring Fair Value Measures As of December 31, 2016 As of December 31, 2015 (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Mutual fund 1 $ 7,182 $ — $ 7,182 $ 7,135 $ — $ 7,135 Cash equivalents 2 — 80 80 — 68 68 Total assets $ 7,182 $ 80 $ 7,262 $ 7,135 $ 68 $ 7,203 _______________ 1 This is a publicly traded balanced mutual fund. The fund seeks regular income, conservation of principal, and an opportunity for long-term growth of principal and income. The fair value is determined by taking the number of shares owned by the plan, and multiplying by the market price as of December 31, 2016 . 2 The investment consists of a money market fund (at level 1) and a collective trust fund (at level 2). The money market fund is valued at the net asset value per share of $1.00 per unit as of December 31, 2016 . The collective trust fund invests primarily in commercial paper, notes, repurchase agreements, and other evidences of indebtedness which are payable on demand or short-term in nature. To obtain the desired return needed to fund the pension benefit plans, the Retirement Plan Committee has established investment allocation percentages by asset classes as follows: Allocation Asset Class Minimum Target Maximum Domestic large cap equity 25 % 31 % 40 % Domestic small cap equity — 9 15 Non-U.S. equity 10 25 30 Fixed income 15 25 30 Real estate — — 10 Absolute return 5 10 15 Cash — — 5 |
Parent Company [Member] | |
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Schedule of Amounts Recognized in Balance Sheet and Accumulated Other Comprehensive Income | Puget Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 56,588 $ 45,447 $ 9,043 $ 9,848 $ (4,190 ) $ (1,834 ) Prior service cost (credit) (9,822 ) (11,802 ) 246 288 — — Total $ 46,766 $ 33,645 $ 9,289 $ 10,136 $ (4,190 ) $ (1,834 ) |
PUGET SOUND ENERGY, INC. | |
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Schedule of Amounts Recognized in Balance Sheet and Accumulated Other Comprehensive Income | Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 217,143 $ 221,064 $ 11,978 $ 13,202 $ (5,994 ) $ 3,834 Prior service cost (credit) (7,806 ) (9,379 ) 251 295 — — Total $ 209,337 $ 211,685 $ 12,229 $ 13,497 $ (5,994 ) $ 3,834 |
Schedule of Net Benefit Costs | Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2014 2016 2015 2014 2016 2015 2014 Components of net periodic benefit cost: Service cost $ 18,913 $ 21,287 $ 17,437 $ 1,085 $ 1,108 $ 1,042 $ 93 $ 112 $ 112 Interest cost 28,689 28,088 28,039 2,325 2,281 2,310 533 621 684 Expected return on plan assets (46,814 ) (45,462 ) (43,252 ) — — — (446 ) (531 ) (535 ) Amortization of prior service cost (credit) (1,573 ) (1,573 ) (1,573 ) 44 44 44 — 3 3 Amortization of net loss(gain) 15,257 20,555 13,195 1,330 2,120 1,461 (632 ) (406 ) (702 ) Net periodic benefit cost $ 14,472 $ 22,895 $ 13,846 $ 4,784 $ 5,553 $ 4,857 $ (452 ) $ (201 ) $ (438 ) |
Schedule of Amounts Recognized in Other Comprehensive Income (Loss) | Puget Sound Energy Qualified Pension Benefit SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ 11,336 $ (5,711 ) $ 106 $ (4,430 ) $ (2,742 ) $ (508 ) Amortization of net (loss) gain (15,257 ) (20,556 ) (1,330 ) (2,120 ) 631 407 Amortization of prior service cost (credit) 1,573 1,573 (44 ) (44 ) — (3 ) Total change in other comprehensive income for year $ (2,348 ) $ (24,694 ) $ (1,268 ) $ (6,594 ) $ (2,111 ) $ (104 ) |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Income Tax Disclosures [Line Items] | |
Schedule of Components of Income Tax Expense (Benefit) | The details of income tax (benefit) expense are as follows: Puget Energy Year Ended December 31, (Dollars in Thousands) 2016 2015 2014 Charged to operating expenses: Current: Federal $ — $ — $ — State 20 — — Deferred: Federal 140,315 91,968 57,152 State (131 ) (192 ) (167 ) Total income tax expense $ 140,204 $ 91,776 $ 56,985 |
Schedule of Effective Income Tax Rate Reconciliation | The following reconciliation compares pre-tax book income at the federal statutory rate of 35.0% to the actual income tax expense in the Statements of Income: Puget Energy Year Ended December 31, (Dollars in Thousands) 2016 2015 2014 Income taxes at the statutory rate $158,586 $116,534 $80,087 Increase (decrease): Production tax credit 1 (12,925) (19,470) (23,073) Utility plant differences 3,966 5,671 7,090 Treasury grant amortization (9,788) (8,807) (8,808) Other - net 365 (2,152) 1,689 Total income tax expense $140,204 $91,776 $56,985 Effective tax rate 30.9% 27.6% 24.9% |
Schedule of Deferred Tax Assets and Liabilities | The Company’s net deferred tax liability at December 31, 2016 and 2015 is composed of amounts related to the following types of temporary differences: Puget Energy At December 31, (Dollars in Thousands) 2016 2015 Utility plant and equipment $ 1,880,782 $ 1,788,078 Regulatory asset for income taxes 72,038 73,231 Fair value of debt instruments 67,444 70,260 Pensions and other compensation 77,230 77,230 Other, net deferred tax liabilities 119,050 84,397 Subtotal deferred tax liabilities 2,216,544 2,093,196 Net operating loss carryforward (352,827 ) (384,338 ) Production tax credit carryforward (190,999 ) (178,075 ) Regulatory liability on production tax credit (101,787 ) (94,828 ) Subtotal deferred tax assets (645,613 ) (657,241 ) Total net deferred tax liabilities $ 1,570,931 $ 1,435,955 |
PUGET SOUND ENERGY, INC. | |
Income Tax Disclosures [Line Items] | |
Schedule of Components of Income Tax Expense (Benefit) | Puget Sound Energy Year Ended December 31, (Dollars in Thousands) 2016 2015 2014 Charged to operating expenses: Current: Federal $ — $ — $ — State 20 — — Deferred: Federal 175,327 125,900 89,342 State — — — Total income tax expense $ 175,347 $ 125,900 $ 89,342 |
Schedule of Effective Income Tax Rate Reconciliation | Puget Sound Energy Year Ended December 31, (Dollars in Thousands) 2016 2015 2014 Income taxes at the statutory rate $194,572 $150,531 $114,084 Increase (decrease): Production tax credit 1 (12,925) (19,470) (23,073) Utility plant differences 3,966 5,671 7,090 Treasury grant amortization (9,788) (8,807) (8,808) Other - net (478) (2,025) 49 Total income tax expense $175,347 $125,900 $89,342 Effective tax rate 31.5% 29.3% 27.4% |
Schedule of Deferred Tax Assets and Liabilities | Puget Sound Energy At December 31, (Dollars in Thousands) 2016 2015 Utility plant and equipment $ 1,880,782 $ 1,788,078 Regulatory asset for income taxes 71,517 72,694 Other, net deferred tax liabilities 113,938 80,351 Subtotal deferred tax liabilities 2,066,237 1,941,123 Net operating loss carryforward (41,061 ) (111,604 ) Production tax credit carryforward (190,999 ) (178,075 ) Regulatory liability on production tax credit (101,787 ) (94,828 ) Subtotal deferred tax assets (333,847 ) (384,507 ) Total net deferred tax liabilities $ 1,732,390 $ 1,556,616 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of Long-term Contracts for Purchase of Electric Power | The Company's expenses under these PUD contracts were as follows for the years ended December 31: (Dollars in Thousands) 2016 2015 2014 PUD contract costs $ 77,667 $ 72,833 $ 69,661 As of December 31, 2016 , the Company purchased portions of the power output of the PUDs' projects as set forth in the following table: Company's Current Share of (Dollars in Thousands) Contract Expiration Percent of Output Megawatt Capacity Estimated 2017 Costs 2017 Debt Service Costs Interest included in 2017 Debt Service Costs Debt Outstanding Chelan County PUD: Rock Island Project 2031 25.0 % 156 $ 28,886 $ 10,430 $ 5,638 $ 88,518 Rocky Reach Project 2031 25.0 325 28,376 7,574 2,854 44,305 Douglas County PUD: Wells Project 2018 29.9 251 16,547 8,004 2,153 54,847 Grant County PUD: Priest Rapids Development 2052 0.6 8 2,809 1,670 1,670 18,579 Wanapum Development 2052 0.6 9 2,809 1,670 1,670 18,579 Total 749 $ 79,427 $ 29,348 $ 13,985 $ 224,828 |
Schedule of Long-term Purchase Commitments | The following table summarizes the Company’s estimated obligations for service contracts through the terms of its existing contracts. Service Contract Obligations (Dollars in Thousands) 2017 2018 2019 2020 2021 Thereafter Total Energy production service contracts $ 31,573 $ 31,970 $ 31,313 $ 50,656 $ 32,934 $ 204,687 $ 383,133 Automated meter reading system 18,175 18,693 18,718 20,191 20,939 116,811 213,527 Total $ 49,748 $ 50,663 $ 50,031 $ 70,847 $ 53,873 $ 321,498 $ 596,660 The quantified obligations are based on the FERC and NEB (National Energy Board) currently authorized rates, which are subject to change. Natural Gas Supply and Demand Charge Obligations (Dollars in Thousands) 2017 2018 2019 2020 2021 Thereafter Total Natural gas supply $ 320,238 $ 211,256 $ 230,109 $ 177,390 $ 107,621 $ — $ 1,046,614 Firm transportation service 156,290 154,155 149,277 140,672 128,049 467,266 1,195,709 Firm storage service 6,616 3,861 2,943 1,950 1,619 2,475 19,464 Total $ 483,144 $ 369,272 $ 382,329 $ 320,012 $ 237,289 $ 469,741 $ 2,261,787 These contracts have varying terms and may include escalation and termination provisions. (Dollars in Thousands) 2017 2018 2019 2020 2021 Thereafter Total Columbia River projects $ 73,733 $ 69,527 $ 58,921 $ 59,172 $ 56,396 $ 597,468 $ 915,217 Other utilities 10,499 1,257 888 — — — 12,644 Non-utility contracts 198,681 203,428 208,328 212,042 218,431 935,826 1,976,736 Total $ 282,913 $ 274,212 $ 268,137 $ 271,214 $ 274,827 $ 1,533,294 $ 2,904,597 |
Accumulated Other Comprehensi39
Accumulated Other Comprehensive Income (Loss) (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract] | |
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block] | The following tables present the changes in the Company’s (loss) AOCI by component for the years ended December 31, 2016 , 2015 and 2014 , respectively: Puget Energy Net unrealized gain (loss) and prior service cost on pension plans Net unrealized gain (loss) on energy derivative instruments Net unrealized gain (loss) on interest rate swaps Changes in AOCI, net of tax (Dollars in Thousands) Total Balance at December 31, 2013 $ 48,514 $ (705 ) $ (94 ) $ 47,715 Other comprehensive income (loss) before reclassifications (84,301 ) — — (84,301 ) Amounts reclassified from accumulated other comprehensive income (loss), net of tax (923 ) 372 94 (457 ) Net current-period other comprehensive income (loss) (85,224 ) 372 94 (84,758 ) Balance at December 31, 2014 $ (36,710 ) $ (333 ) $ — $ (37,043 ) Other comprehensive income (loss) before reclassifications 7,196 — — 7,196 Amounts reclassified from accumulated other comprehensive income (loss), net of tax 2,248 333 — 2,581 Net current-period other comprehensive income (loss) 9,444 333 — 9,777 Balance at December 31, 2015 $ (27,266 ) $ — $ — $ (27,266 ) Other comprehensive income (loss) before reclassifications (5,528 ) — — (5,528 ) Amounts reclassified from accumulated other comprehensive income (loss), net of tax (918 ) — — (918 ) Net current-period other comprehensive income (loss) (6,446 ) — — (6,446 ) Balance at December 31, 2016 $ (33,712 ) $ — $ — $ (33,712 ) Puget Sound Energy Net unrealized gain (loss) and prior service cost on pension plans Net unrealized gain (loss) on energy derivative instruments Net unrealized gain (loss) on treasury interest rate swaps Changes in AOCI, net of tax (Dollars in Thousands) Total Balance at December 31, 2013 $ (87,405 ) $ (2,027 ) $ (6,307 ) $ (95,739 ) Other comprehensive income (loss) before reclassifications (84,955 ) — — (84,955 ) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 8,079 1,341 317 9,737 Net current-period other comprehensive income (loss) (76,876 ) 1,341 317 (75,218 ) Balance at December 31, 2014 $ (164,281 ) $ (686 ) $ (5,990 ) $ (170,957 ) Other comprehensive income (loss) before reclassifications 6,922 — — 6,922 Amounts reclassified from accumulated other comprehensive income (loss), net of tax 13,482 686 317 14,485 Net current-period other comprehensive income (loss) 20,404 686 317 21,407 Balance at December 31, 2015 $ (143,877 ) $ — $ (5,673 ) $ (149,550 ) Other comprehensive income (loss) before reclassifications (5,655 ) — — (5,655 ) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 9,377 — 317 9,694 Net current-period other comprehensive income (loss) 3,722 — 317 4,039 Balance at December 31, 2016 $ (140,155 ) $ — $ (5,356 ) $ (145,511 ) |
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block] | Details about the reclassifications out of AOCI (loss) for the years ended December 31, 2016 , 2015 and 2014 , respectively, are as follows: Puget Energy (Dollars in Thousands) Details about accumulated other comprehensive income (loss) components Affected line item in the statement where net income (loss) is presented Amount reclassified from accumulated other comprehensive income (loss) 2016 2015 2014 Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 1,938 $ 1,938 $ 1,938 Amortization of net gain (loss) (a) (525 ) (5,397 ) (519 ) Total before tax 1,413 (3,459 ) 1,419 Tax (expense) or benefit (495 ) 1,211 (496 ) Net of Tax 918 (2,248 ) 923 Net unrealized gain (loss) on energy derivative instruments: Commodity contracts: Electric derivatives Purchased electricity — (512 ) (572 ) Tax (expense) or benefit — 179 200 Net of Tax — (333 ) (372 ) Net unrealized gain (loss) on interest rate swaps: Interest rate contracts Interest expense — — (144 ) Tax (expense) or benefit — — 50 Net of Tax — — (94 ) Total reclassification for the period Net of Tax $ 918 $ (2,581 ) $ 457 _______________ (a) These AOCI components are included in the computation of net periodic pension cost (see Note 12, "Retirement Benefits" for additional details). Puget Sound Energy (Dollars in Thousands) Details about accumulated other comprehensive income (loss) components Affected line item in the statement where net income (loss) is presented Amount reclassified from accumulated other comprehensive income (loss) 2016 2015 2014 Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 1,529 $ 1,526 $ 1,526 Amortization of net gain (loss) (a) (15,955 ) (22,268 ) (13,954 ) Total before tax (14,426 ) (20,742 ) (12,428 ) Tax (expense) or benefit 5,049 7,260 4,349 Net of tax (9,377 ) (13,482 ) (8,079 ) Net unrealized gain (loss) on energy derivative instruments: Commodity contracts: Electric derivatives Purchased electricity — (1,055 ) (2,063 ) Tax (expense) or benefit — 369 722 Net of Tax — (686 ) (1,341 ) Net unrealized gain (loss) on treasury interest rate swaps: Interest rate contracts Interest expense (488 ) (488 ) (488 ) Tax (expense) or benefit 171 171 171 Net of Tax (317 ) (317 ) (317 ) Total reclassification for the period Net of Tax $ (9,694 ) $ (14,485 ) $ (9,737 ) _______________ (a) These AOCI components are included in the computation of net periodic pension cost (see Note 12, "Retirement Benefits" for additional details). |
Summary of Significant Accoun40
Summary of Significant Accounting Policies (Details) $ in Thousands | 6 Months Ended | 12 Months Ended | ||||
Dec. 31, 2013USD ($) | Dec. 31, 2016USD ($)mi²unit | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Jan. 01, 2015 | Feb. 06, 2009USD ($) | |
Accounting Policies | ||||||
Public Utilities, Allowance for Funds Used During Construction, Rate | 7.77% | |||||
Goodwill | $ 1,656,513 | $ 1,656,513 | $ 1,700,000 | |||
Number of reportable segments | unit | 1 | |||||
Cash and Cash Equivalents | ||||||
Cash and Cash Equivalents, at Carrying Value | $ 44,302 | $ 28,878 | 42,494 | $ 37,527 | ||
Revenue Recognition | ||||||
Excise taxes collected | 235,300 | 234,200 | $ 231,700 | |||
Allowance for Doubtful Accounts | ||||||
Allowance for doubtful accounts | 9,798 | $ 9,756 | ||||
Self Insurance [Abstract] | ||||||
Public Utilities, Rate Case, Deferred Storm Costs Threshold | $ 8,000 | |||||
Electric Transmission | ||||||
Accounting Policies | ||||||
Annual depreciation provision | 2.80% | |||||
Gas Transmission Equipment | ||||||
Accounting Policies | ||||||
Annual depreciation provision | 3.40% | |||||
Common Plant | ||||||
Accounting Policies | ||||||
Annual depreciation provision | 9.70% | 8.50% | 8.50% | |||
PUGET SOUND ENERGY, INC. | ||||||
Accounting Policies | ||||||
Area of service territory (sqmi) | mi² | 6,000 | |||||
Cash and Cash Equivalents | ||||||
Cash and Cash Equivalents, at Carrying Value | $ 44,111 | $ 28,481 | $ 41,856 | $ 37,466 | ||
Allowance for Doubtful Accounts | ||||||
Allowance for doubtful accounts | $ 9,798 | 9,756 | ||||
Maximum | ||||||
Accounting Policies | ||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease) | 3.00% | |||||
Adjustments for New Accounting Pronouncement [Member] | ||||||
Accounting Policies | ||||||
Unamortized Debt Issuance Expense | 38,400 | |||||
Adjustments for New Accounting Pronouncement [Member] | PUGET SOUND ENERGY, INC. | ||||||
Accounting Policies | ||||||
Unamortized Debt Issuance Expense | $ 30,000 |
Summary of Significant Accoun41
Summary of Significant Accounting Policies - AFUDC (Details) | 12 Months Ended |
Dec. 31, 2016 | |
Regulatory Assets [Line Items] | |
Public Utilities, Property, Plant and Equipment, Non-project Electric Utility Plant, Estimated Useful Life Average | 30 years |
Regulation and Rates Schedule o
Regulation and Rates Schedule of Allowed Return on the Net Regulatory Assets and Liabilities (Details) | 14 Months Ended |
Jun. 30, 2013 | |
Regulated Operations [Abstract] | |
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities | 7.80% |
Regulation and Rates Net regula
Regulation and Rates Net regulatory assets and liabilities (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | ||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 176,800 | ||
PUGET SOUND ENERGY, INC. | Decoupling rate of return sharing [Member] | |||
Regulatory Assets [Line Items] | |||
Regulatory Liabilities | (13,300) | $ (25,483) | |
PUGET SOUND ENERGY, INC. | Deferral and interest decoupling revenue [Member] | |||
Regulatory Assets [Line Items] | |||
Regulatory Liabilities | (16,448) | 0 | |
PUGET SOUND ENERGY, INC. | Cost of removal | |||
Regulatory Assets [Line Items] | |||
Regulatory Liabilities | [1] | $ (369,300) | (347,472) |
PUGET SOUND ENERGY, INC. | Treasury grants | |||
Regulatory Assets [Line Items] | |||
Net Regulatory Assets, Remaining Amortization Period, Max | 42 years | ||
Regulatory Liabilities | $ (133,709) | (157,102) | |
PUGET SOUND ENERGY, INC. | Deferred income tax charge | |||
Regulatory Assets [Line Items] | |||
Regulatory Liabilities | [2] | $ (93,616) | (93,616) |
PUGET SOUND ENERGY, INC. | Decoupling over-collection | |||
Regulatory Assets [Line Items] | |||
Net Regulatory Assets, Remaining Amortization Period | 2 years | ||
Regulatory Liabilities | $ (29,748) | (25,483) | |
PUGET SOUND ENERGY, INC. | PGA payable | |||
Regulatory Assets [Line Items] | |||
Net Regulatory Assets, Remaining Amortization Period | 1 year | ||
Regulatory Liabilities | $ 0 | (12,589) | |
PUGET SOUND ENERGY, INC. | Summit purchase option buy-out | |||
Regulatory Assets [Line Items] | |||
Net Regulatory Assets, Remaining Amortization Period | 3 years 10 months | ||
Regulatory Liabilities | $ (6,038) | (7,612) | |
PUGET SOUND ENERGY, INC. | Treasury grant amortization deferral [Member] | |||
Regulatory Assets [Line Items] | |||
Net Regulatory Assets, Remaining Amortization Period, Max | 3 years | ||
Regulatory Liabilities | $ (3,920) | (6,058) | |
PUGET SOUND ENERGY, INC. | Purchased Gas Adjustment Deferral of Unrealized Gains on Derivatives [Member] | |||
Regulatory Assets [Line Items] | |||
Regulatory Liabilities | [3] | (7,517) | 0 |
PUGET SOUND ENERGY, INC. | Lower Snake River interest due [Member] | |||
Regulatory Assets [Line Items] | |||
Regulatory Liabilities | $ (4,189) | 0 | |
PUGET SOUND ENERGY, INC. | Various other regulatory liabilities | |||
Regulatory Assets [Line Items] | |||
Net Regulatory Assets, Remaining Amortization Period, Max | 4 years | ||
Regulatory Liabilities | $ (5,259) | (13,751) | |
PUGET SOUND ENERGY, INC. | Liabilities, Total | |||
Regulatory Assets [Line Items] | |||
Regulatory Liabilities | (653,296) | (663,683) | |
PUGET SOUND ENERGY, INC. | Net Regulatory Assets | |||
Regulatory Assets [Line Items] | |||
Net Regulatory Assets | 459,889 | 307,819 | |
PUGET SOUND ENERGY, INC. | Colstrip Regulatory Asset [Domain] | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | [3] | 176,804 | 0 |
PUGET SOUND ENERGY, INC. | Storm Costs [Member] | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 122,709 | 125,777 | |
Net Regulatory Assets, Remaining Amortization Period, Max | 2 years | ||
PUGET SOUND ENERGY, INC. | Chelan PUD contract initiation | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 105,140 | 112,228 | |
Net Regulatory Assets, Remaining Amortization Period | 14 years 10 months | ||
PUGET SOUND ENERGY, INC. | Deferred decoupling revenue, gross [Member] | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 156,408 | 104,150 | |
PUGET SOUND ENERGY, INC. | Other decoupling 24 month reserve [Member] | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | (20,847) | (9,980) | |
PUGET SOUND ENERGY, INC. | Deferred decoupling revenue, net [Member] | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 135,561 | 94,170 | |
Net Regulatory Assets, Remaining Amortization Period | 2 years | ||
PUGET SOUND ENERGY, INC. | Lower Snake River | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 74,862 | 79,599 | |
Net Regulatory Assets, Remaining Amortization Period, Max | 20 years 4 months | ||
PUGET SOUND ENERGY, INC. | Deferred income tax charge | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | [3] | $ 71,517 | 72,694 |
PUGET SOUND ENERGY, INC. | Environmental remediation | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | [3] | 74,557 | 66,887 |
PUGET SOUND ENERGY, INC. | Baker Dam Licensing Operating Maintenance Costs [Member] | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 61,453 | 63,394 | |
Net Regulatory Assets, Remaining Amortization Period | 42 years | ||
PUGET SOUND ENERGY, INC. | PGA deferral of unrealized losses on derivative instruments | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | [3] | $ 0 | 60,889 |
PUGET SOUND ENERGY, INC. | Deferred Washington Commission AFUDC | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 51,404 | 52,197 | |
Net Regulatory Assets, Remaining Amortization Period, Max | 35 years | ||
PUGET SOUND ENERGY, INC. | Unamortized loss on reacquired debt | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 42,196 | 44,984 | |
Net Regulatory Assets, Remaining Amortization Period, Max | 30 years | ||
PUGET SOUND ENERGY, INC. | Property tax tracker | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 41,949 | 40,353 | |
Net Regulatory Assets, Remaining Amortization Period | 2 years | ||
PUGET SOUND ENERGY, INC. | Energy Conservation Costs [Member] | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 41,027 | 36,646 | |
Net Regulatory Assets, Remaining Amortization Period, Max | 2 years | ||
PUGET SOUND ENERGY, INC. | White River relicensing and other costs | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 21,627 | 23,054 | |
Net Regulatory Assets, Remaining Amortization Period | 15 years 10 months 24 days | ||
PUGET SOUND ENERGY, INC. | Mint Farm ownership and operating costs | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 16,319 | 18,320 | |
Net Regulatory Assets, Remaining Amortization Period | 8 years 4 months | ||
PUGET SOUND ENERGY, INC. | Ferndale | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 11,274 | 15,253 | |
Net Regulatory Assets, Remaining Amortization Period | 2 years 10 months | ||
PUGET SOUND ENERGY, INC. | Electron Unrecovered Loss | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 7,178 | 10,569 | |
Net Regulatory Assets, Remaining Amortization Period | 2 years | ||
PUGET SOUND ENERGY, INC. | Snoqualmie Licensing Operating Maintenance Costs | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 8,018 | 7,980 | |
Net Regulatory Assets, Remaining Amortization Period | 28 years | ||
PUGET SOUND ENERGY, INC. | Colstrip common property | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | [3] | $ 5,334 | 6,049 |
PUGET SOUND ENERGY, INC. | Colstrip major maintenance [Member] | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 6,589 | 5,897 | |
Net Regulatory Assets, Remaining Amortization Period | 2 years | ||
PUGET SOUND ENERGY, INC. | Investment in Bonneville Exchange power contract | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 1,763 | 5,290 | |
Net Regulatory Assets, Remaining Amortization Period | 1 year | ||
PUGET SOUND ENERGY, INC. | Snoqualmie | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 3,251 | 5,024 | |
Net Regulatory Assets, Remaining Amortization Period | 1 year 9 months | ||
PUGET SOUND ENERGY, INC. | PCA Mechanism [Member] | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | [3] | $ 4,531 | 0 |
PUGET SOUND ENERGY, INC. | PGA receivable [Domain] | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 2,785 | 0 | |
Net Regulatory Assets, Remaining Amortization Period | 1 year | ||
PUGET SOUND ENERGY, INC. | Various other regulatory assets | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 25,337 | 24,248 | |
PUGET SOUND ENERGY, INC. | Assets, Total | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 1,113,185 | 971,502 | |
Parent Company [Member] | Regulatory liabilities related to power contracts | |||
Regulatory Assets [Line Items] | |||
Net Regulatory Assets, Remaining Amortization Period, Max | 36 years | ||
Regulatory Liabilities | $ (275,061) | (325,788) | |
Parent Company [Member] | Various other regulatory liabilities | |||
Regulatory Assets [Line Items] | |||
Regulatory Liabilities | (1,326) | (1,347) | |
Parent Company [Member] | Liabilities, Total | |||
Regulatory Assets [Line Items] | |||
Regulatory Liabilities | (929,683) | (990,818) | |
Parent Company [Member] | Net Regulatory Assets | |||
Regulatory Assets [Line Items] | |||
Net Regulatory Assets | 206,632 | 7,456 | |
Parent Company [Member] | Various other regulatory assets | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | 517 | 549 | |
Parent Company [Member] | Requlatory Assets Related to Power Contracts | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 22,613 | 26,223 | |
Net Regulatory Assets, Remaining Amortization Period, Max | 21 years | ||
Parent Company [Member] | Assets, Total | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 1,136,315 | $ 998,274 | |
[1] | The balance is dependent upon the cost of removal of underlying assets and the life of utility plant. | ||
[2] | Amortization will begin once PTCs are utilized by PSE on its tax return. | ||
[3] | Amortization periods vary depending on timing of underlying transactions or awaiting regulatory approval in a future Washington Commission rate proceeding. |
Regulation and Rates Rate Adjus
Regulation and Rates Rate Adjustments (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | 14 Months Ended | |||||||||||||||||||
Sep. 30, 2014 | Mar. 31, 2013 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Jun. 30, 2013 | Dec. 13, 2017 | May 01, 2017 | Dec. 01, 2016 | Nov. 01, 2016 | May 01, 2016 | Oct. 31, 2015 | Jun. 01, 2015 | May 01, 2015 | Jan. 01, 2015 | Dec. 01, 2014 | Nov. 01, 2014 | May 01, 2014 | Jun. 25, 2013 | Mar. 30, 2013 | May 14, 2012 | |
Regulation and Rates [Line Items] | ||||||||||||||||||||||
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities | 7.80% | |||||||||||||||||||||
Treasury grant payment received | $ 0 | $ 0 | $ (107,876) | |||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Common Equity in Capital Structure | 48.00% | |||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Return on Equity | 9.80% | |||||||||||||||||||||
Purchased Gas Adjustment (PGA) | Gas | ||||||||||||||||||||||
Regulation and Rates [Line Items] | ||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease) | $ (4,100) | $ (185,900) | $ 23,300 | |||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease) | (0.40%) | (17.40%) | 2.50% | |||||||||||||||||||
Cost recovery mechanism [Member] | Gas | ||||||||||||||||||||||
Regulation and Rates [Line Items] | ||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease) | $ 5,600 | $ 5,300 | $ 2,300 | |||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease) | 0.60% | 0.50% | 0.20% | |||||||||||||||||||
Property tax tracker | Gas | ||||||||||||||||||||||
Regulation and Rates [Line Items] | ||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease) | $ 3,500 | $ (2,300) | $ 5,600 | |||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease) | 0.40% | (0.20%) | 0.60% | |||||||||||||||||||
Property tax tracker | Electric [Member] | ||||||||||||||||||||||
Regulation and Rates [Line Items] | ||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease) | $ 5,700 | $ 6,500 | $ 11,000 | |||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease) | 0.30% | 0.30% | 0.50% | |||||||||||||||||||
Decoupling Mechanism [Member] | Gas | ||||||||||||||||||||||
Regulation and Rates [Line Items] | ||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease) | $ 25,400 | $ 22,000 | $ (1,000) | |||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease) | 2.80% | 2.10% | 2.20% | (0.10%) | ||||||||||||||||||
Decoupling Mechanism [Member] | Electric [Member] | ||||||||||||||||||||||
Regulation and Rates [Line Items] | ||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease) | $ 20,800 | $ 53,800 | $ 10,600 | |||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease) | 1.00% | 2.60% | 3.00% | 0.50% | ||||||||||||||||||
Power Cost Only Rate Case (PCORC) | Electric [Member] | ||||||||||||||||||||||
Regulation and Rates [Line Items] | ||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease) | $ (37,300) | $ (19,400) | ||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease) | (1.70%) | (0.90%) | ||||||||||||||||||||
Energy Conservation Costs [Member] | Gas | ||||||||||||||||||||||
Regulation and Rates [Line Items] | ||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease) | $ 2,900 | $ 2,300 | ||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease) | 0.30% | 0.20% | ||||||||||||||||||||
Energy Conservation Costs [Member] | Electric [Member] | ||||||||||||||||||||||
Regulation and Rates [Line Items] | ||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease) | $ (11,700) | $ 4,200 | $ 12,200 | |||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease) | (0.50%) | 0.20% | 0.60% | |||||||||||||||||||
Jefferson County Public Utility District | ||||||||||||||||||||||
Regulation and Rates [Line Items] | ||||||||||||||||||||||
Property, Plant and Equipment, Net | $ 46,700 | |||||||||||||||||||||
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal | $ 60,000 | |||||||||||||||||||||
PUGET SOUND ENERGY, INC. | ||||||||||||||||||||||
Regulation and Rates [Line Items] | ||||||||||||||||||||||
American Recovery and Reinvestment Tax Act of 2009, Total Grant Pass Through Amount | (57,300) | (55,200) | (58,500) | |||||||||||||||||||
Treasury grant payment received | $ 0 | $ 0 | $ (107,876) | |||||||||||||||||||
American Recovery and Reinvestment Tax Act of 2009, Grant, Overall Average Rate Reduction | (0.20%) | (0.20%) | (0.30%) | |||||||||||||||||||
PUGET SOUND ENERGY, INC. | Decoupling Mechanism [Member] | ||||||||||||||||||||||
Regulation and Rates [Line Items] | ||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease) | $ (12,000) | |||||||||||||||||||||
PUGET SOUND ENERGY, INC. | Decoupling Mechanism [Member] | Gas | ||||||||||||||||||||||
Regulation and Rates [Line Items] | ||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease) | $ 2,100 | $ 9,200 | $ 0 | |||||||||||||||||||
PUGET SOUND ENERGY, INC. | Decoupling Mechanism [Member] | Electric [Member] | ||||||||||||||||||||||
Regulation and Rates [Line Items] | ||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease) | 11,200 | 16,300 | 3,400 | |||||||||||||||||||
PUGET SOUND ENERGY, INC. | Jefferson County Public Utility District | ||||||||||||||||||||||
Regulation and Rates [Line Items] | ||||||||||||||||||||||
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal | $ 7,500 | |||||||||||||||||||||
Customers | Jefferson County Public Utility District | ||||||||||||||||||||||
Regulation and Rates [Line Items] | ||||||||||||||||||||||
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal | $ 52,700 | |||||||||||||||||||||
Deferral Trigger [Member] [Member] | ||||||||||||||||||||||
Regulation and Rates [Line Items] | ||||||||||||||||||||||
Annual Power Cost Variability, Amount | $ 20,000 | $ 30,000 | ||||||||||||||||||||
Maximum | ||||||||||||||||||||||
Regulation and Rates [Line Items] | ||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease) | 3.00% | |||||||||||||||||||||
Maximum | Decoupling Mechanism [Member] | ||||||||||||||||||||||
Regulation and Rates [Line Items] | ||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease) | 3.00% | |||||||||||||||||||||
Deferred Revenue [Domain] | PUGET SOUND ENERGY, INC. | Decoupling Mechanism [Member] | Gas | ||||||||||||||||||||||
Regulation and Rates [Line Items] | ||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease) | 28,700 | 8,200 | ||||||||||||||||||||
Deferred Revenue [Domain] | PUGET SOUND ENERGY, INC. | Decoupling Mechanism [Member] | Electric [Member] | ||||||||||||||||||||||
Regulation and Rates [Line Items] | ||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease) | $ 0 | $ 1,900 | ||||||||||||||||||||
Scenario, Forecast [Member] | Energy Conservation Costs [Member] | Gas | ||||||||||||||||||||||
Regulation and Rates [Line Items] | ||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease) | $ (1,000) | |||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease) | (0.10%) | |||||||||||||||||||||
Scenario, Forecast [Member] | Energy Conservation Costs [Member] | Electric [Member] | ||||||||||||||||||||||
Regulation and Rates [Line Items] | ||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease) | $ 16,500 | |||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease) | 0.70% | |||||||||||||||||||||
Scenario, Forecast [Member] | PUGET SOUND ENERGY, INC. | ||||||||||||||||||||||
Regulation and Rates [Line Items] | ||||||||||||||||||||||
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities | 7.74% | |||||||||||||||||||||
Regulated Utility, After-tax Allowed Rate of Return on Net Regulatory Assets and Liabilities | 6.69% | |||||||||||||||||||||
American Recovery and Reinvestment Tax Act of 2009, Total Grant Pass Through Amount | $ (51,700) | |||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Common Equity in Capital Structure | 48.50% | |||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Return on Equity | 9.80% | |||||||||||||||||||||
American Recovery and Reinvestment Tax Act of 2009, Grant, Overall Average Rate Reduction | 0.30% | |||||||||||||||||||||
Scenario, Forecast [Member] | PUGET SOUND ENERGY, INC. | General Rate Case [Member] | Gas | ||||||||||||||||||||||
Regulation and Rates [Line Items] | ||||||||||||||||||||||
Public Utilities, Rate Case, Approved Overall Rate Impact Increase (Decrease) | $ (22,300) | |||||||||||||||||||||
Public Utilities, Rate Case, Approved Overall Effective Annual Rate Percentage Increase (Decrease) | (2.40%) | |||||||||||||||||||||
Scenario, Forecast [Member] | PUGET SOUND ENERGY, INC. | General Rate Case [Member] | Electric [Member] | ||||||||||||||||||||||
Regulation and Rates [Line Items] | ||||||||||||||||||||||
Public Utilities, Rate Case, Approved Overall Rate Impact Increase (Decrease) | $ 86,300 | |||||||||||||||||||||
Public Utilities, Rate Case, Approved Overall Effective Annual Rate Percentage Increase (Decrease) | 4.10% | |||||||||||||||||||||
Requlatory Assets Related to Power Contracts | Parent Company [Member] | ||||||||||||||||||||||
Regulation and Rates [Line Items] | ||||||||||||||||||||||
Net Regulatory Assets, Remaining Amortization Period, Min | 1 year | |||||||||||||||||||||
Net Regulatory Assets, Remaining Amortization Period, Max | 21 years |
Regulation and Rates (Details)
Regulation and Rates (Details) - USD ($) | 3 Months Ended | 12 Months Ended | 14 Months Ended | ||||||||||||||||||||
Sep. 30, 2014 | Mar. 31, 2013 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Jun. 30, 2013 | Dec. 13, 2017 | May 01, 2017 | Dec. 01, 2016 | Nov. 01, 2016 | May 01, 2016 | Oct. 31, 2015 | Sep. 30, 2015 | Jun. 01, 2015 | May 01, 2015 | Jan. 01, 2015 | Dec. 01, 2014 | Nov. 01, 2014 | May 01, 2014 | Jun. 25, 2013 | Mar. 30, 2013 | May 14, 2012 | |
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities | 7.80% | ||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Common Equity in Capital Structure | 48.00% | ||||||||||||||||||||||
Public Utilities, Rate Case, Deferred Storm Costs Threshold | $ 8,000,000 | ||||||||||||||||||||||
Accrual for Environmental Loss Contingencies | 24,900,000 | ||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Return on Equity | 9.80% | ||||||||||||||||||||||
Electric [Member] | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Environmental Remediation Expense | 6,200,000 | ||||||||||||||||||||||
Environmental Expense and Liabilities | 13,800,000 | $ 14,000,000 | $ 13,400,000 | ||||||||||||||||||||
Gas | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Environmental Remediation Expense | 38,000,000 | ||||||||||||||||||||||
Environmental Expense and Liabilities | 60,700,000 | 52,900,000 | $ 52,600,000 | ||||||||||||||||||||
PUGET SOUND ENERGY, INC. | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Regulatory Liabilities Reclassified from Accumulated Depreciation | 369,300,000 | 347,500,000 | |||||||||||||||||||||
Storm Damage Costs Incurred During Period | 22,000,000 | 33,600,000 | |||||||||||||||||||||
Storm Damage Costs Deferred During Period | $ 12,400,000 | $ 22,400,000 | |||||||||||||||||||||
American Recovery and Reinvestment Tax Act of 2009, Grant, Overall Average Rate Reduction | 0.20% | 0.20% | 0.30% | ||||||||||||||||||||
American Recovery and Reinvestment Tax Act of 2009, Total Grant Pass Through Amount | $ (57,300,000) | $ (55,200,000) | $ (58,500,000) | ||||||||||||||||||||
Range 1 [Member] | Company's share [Member] | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Annual Power Cost Variability, Percentage | 100.00% | ||||||||||||||||||||||
Range 1 [Member] | Customers share [Member] | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Annual Power Cost Variability, Percentage | 0.00% | ||||||||||||||||||||||
Range 2 [Member] | Company's share [Member] | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Annual Power Cost Variability, Percentage | 50.00% | ||||||||||||||||||||||
Range 2 [Member] | Customers share [Member] | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Annual Power Cost Variability, Percentage | 50.00% | ||||||||||||||||||||||
Range 3 [Member] | Company's share [Member] | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Annual Power Cost Variability, Percentage | 10.00% | ||||||||||||||||||||||
Range 3 [Member] | Customers share [Member] | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Annual Power Cost Variability, Percentage | 90.00% | ||||||||||||||||||||||
Range 4 [Member] | Company's share [Member] | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Annual Power Cost Variability, Percentage | 5.00% | ||||||||||||||||||||||
Range 4 [Member] | Customers share [Member] | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Annual Power Cost Variability, Percentage | 95.00% | ||||||||||||||||||||||
Under Recovery [Member] | Range 1 [Member] | Company's share [Member] | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Annual Power Cost Variability, Percentage | 100.00% | ||||||||||||||||||||||
Under Recovery [Member] | Range 1 [Member] | Customers share [Member] | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Annual Power Cost Variability, Percentage | 0.00% | ||||||||||||||||||||||
Under Recovery [Member] | Range 2 [Member] | Company's share [Member] | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Annual Power Cost Variability, Percentage | 50.00% | ||||||||||||||||||||||
Under Recovery [Member] | Range 2 [Member] | Customers share [Member] | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Annual Power Cost Variability, Percentage | 50.00% | ||||||||||||||||||||||
Under Recovery [Member] | Range 3 [Member] | Company's share [Member] | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Annual Power Cost Variability, Percentage | 10.00% | ||||||||||||||||||||||
Under Recovery [Member] | Range 3 [Member] | Customers share [Member] | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Annual Power Cost Variability, Percentage | 90.00% | ||||||||||||||||||||||
Over Recovery [Member] | Company's share [Member] | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Annual Power Cost Variability, Amount | 1,000,000 | 8,700,000 | |||||||||||||||||||||
Over Recovery [Member] | Customers share [Member] | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Annual Power Cost Variability, Amount | 0 | 0 | |||||||||||||||||||||
Over Recovery [Member] | Range 1 [Member] | Company's share [Member] | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Annual Power Cost Variability, Percentage | 100.00% | ||||||||||||||||||||||
Over Recovery [Member] | Range 1 [Member] | Customers share [Member] | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Annual Power Cost Variability, Percentage | 0.00% | ||||||||||||||||||||||
Over Recovery [Member] | Range 2 [Member] | Company's share [Member] | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Annual Power Cost Variability, Percentage | 35.00% | ||||||||||||||||||||||
Over Recovery [Member] | Range 2 [Member] | Customers share [Member] | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Annual Power Cost Variability, Percentage | 65.00% | ||||||||||||||||||||||
Over Recovery [Member] | Range 3 [Member] | Company's share [Member] | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Annual Power Cost Variability, Percentage | 10.00% | ||||||||||||||||||||||
Over Recovery [Member] | Range 3 [Member] | Customers share [Member] | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Annual Power Cost Variability, Percentage | 90.00% | ||||||||||||||||||||||
Decoupling Mechanism [Member] | Electric [Member] | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease) | 1.00% | 2.60% | 3.00% | 0.50% | |||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease) | $ 20,800,000 | $ 53,800,000 | $ 10,600,000 | ||||||||||||||||||||
Decoupling Mechanism [Member] | Gas | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease) | 2.80% | 2.10% | 2.20% | (0.10%) | |||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease) | $ 25,400,000 | $ 22,000,000 | $ (1,000,000) | ||||||||||||||||||||
Decoupling Mechanism [Member] | PUGET SOUND ENERGY, INC. | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease) | $ (12,000,000) | ||||||||||||||||||||||
Decoupling Mechanism [Member] | PUGET SOUND ENERGY, INC. | Electric [Member] | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease) | 11,200,000 | 16,300,000 | 3,400,000 | ||||||||||||||||||||
Decoupling Mechanism [Member] | PUGET SOUND ENERGY, INC. | Gas | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease) | 2,100,000 | 9,200,000 | 0 | ||||||||||||||||||||
Purchased Gas Adjustment (PGA) | Gas | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease) | (0.40%) | (17.40%) | 2.50% | ||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease) | $ (4,100,000) | $ (185,900,000) | $ 23,300,000 | ||||||||||||||||||||
Cost recovery mechanism [Member] | Gas | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease) | 0.60% | 0.50% | 0.20% | ||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease) | $ 5,600,000 | $ 5,300,000 | $ 2,300,000 | ||||||||||||||||||||
Energy Conservation Costs [Member] | Electric [Member] | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease) | (0.50%) | 0.20% | 0.60% | ||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease) | $ (11,700,000) | $ 4,200,000 | $ 12,200,000 | ||||||||||||||||||||
Energy Conservation Costs [Member] | Gas | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease) | 0.30% | 0.20% | |||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease) | $ 2,900,000 | $ 2,300,000 | |||||||||||||||||||||
Property tax tracker | Electric [Member] | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease) | 0.30% | 0.30% | 0.50% | ||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease) | $ 5,700,000 | $ 6,500,000 | $ 11,000,000 | ||||||||||||||||||||
Property tax tracker | Gas | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease) | 0.40% | (0.20%) | 0.60% | ||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease) | $ 3,500,000 | $ (2,300,000) | $ 5,600,000 | ||||||||||||||||||||
Power Cost Only Rate Case (PCORC) | Electric [Member] | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease) | (1.70%) | (0.90%) | |||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease) | $ (37,300,000) | $ (19,400,000) | |||||||||||||||||||||
Scenario, Forecast [Member] | PUGET SOUND ENERGY, INC. | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities | 7.74% | ||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Common Equity in Capital Structure | 48.50% | ||||||||||||||||||||||
Regulated Utility, After-tax Allowed Rate of Return on Net Regulatory Assets and Liabilities | 6.69% | ||||||||||||||||||||||
American Recovery and Reinvestment Tax Act of 2009, Grant, Overall Average Rate Reduction | (0.30%) | ||||||||||||||||||||||
American Recovery and Reinvestment Tax Act of 2009, Total Grant Pass Through Amount | $ (51,700,000) | ||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Return on Equity | 9.80% | ||||||||||||||||||||||
Scenario, Forecast [Member] | Energy Conservation Costs [Member] | Electric [Member] | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease) | 0.70% | ||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease) | $ 16,500,000 | ||||||||||||||||||||||
Scenario, Forecast [Member] | Energy Conservation Costs [Member] | Gas | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease) | (0.10%) | ||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease) | $ (1,000,000) | ||||||||||||||||||||||
Jefferson County Public Utility District | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Property, Plant and Equipment, Net | $ 46,700,000 | ||||||||||||||||||||||
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal | $ 60,000,000 | ||||||||||||||||||||||
Jefferson County Public Utility District | PUGET SOUND ENERGY, INC. | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal | $ 7,500,000 | ||||||||||||||||||||||
Jefferson County Public Utility District | Customers | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal | $ 52,700,000 | ||||||||||||||||||||||
Maximum | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease) | 3.00% | ||||||||||||||||||||||
Maximum | Decoupling Mechanism [Member] | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease) | 3.00% | ||||||||||||||||||||||
Deferred Revenue [Domain] | Decoupling Mechanism [Member] | PUGET SOUND ENERGY, INC. | Electric [Member] | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease) | 0 | 1,900,000 | |||||||||||||||||||||
Deferred Revenue [Domain] | Decoupling Mechanism [Member] | PUGET SOUND ENERGY, INC. | Gas | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease) | $ 28,700,000 | $ 8,200,000 | |||||||||||||||||||||
Deferral Trigger [Member] [Member] | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Annual Power Cost Variability, Amount | $ 20,000,000 | $ 30,000,000 | |||||||||||||||||||||
Regulatory liabilities related to power contracts | Parent Company [Member] | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Net Regulatory Assets, Remaining Amortization Period, Min | 1 year | ||||||||||||||||||||||
Net Regulatory Assets, Remaining Amortization Period, Max | 36 years | ||||||||||||||||||||||
Treasury grants | PUGET SOUND ENERGY, INC. | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Net Regulatory Assets, Remaining Amortization Period, Min | 3 years | ||||||||||||||||||||||
Net Regulatory Assets, Remaining Amortization Period, Max | 42 years | ||||||||||||||||||||||
Chelan PUD contract initiation | PUGET SOUND ENERGY, INC. | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Net Regulatory Assets, Remaining Amortization Period | 14 years 10 months | ||||||||||||||||||||||
Ferndale | PUGET SOUND ENERGY, INC. | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Net Regulatory Assets, Remaining Amortization Period | 2 years 10 months | ||||||||||||||||||||||
Deferred decoupling revenue, net [Member] | PUGET SOUND ENERGY, INC. | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Net Regulatory Assets, Remaining Amortization Period | 2 years | ||||||||||||||||||||||
Energy Conservation Costs [Member] | PUGET SOUND ENERGY, INC. | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Net Regulatory Assets, Remaining Amortization Period, Min | 1 year | ||||||||||||||||||||||
Net Regulatory Assets, Remaining Amortization Period, Max | 2 years | ||||||||||||||||||||||
Requlatory Assets Related to Power Contracts | Parent Company [Member] | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Net Regulatory Assets, Remaining Amortization Period, Min | 1 year | ||||||||||||||||||||||
Net Regulatory Assets, Remaining Amortization Period, Max | 21 years | ||||||||||||||||||||||
Lower Snake River | PUGET SOUND ENERGY, INC. | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Net Regulatory Assets, Remaining Amortization Period, Min | 1 year | ||||||||||||||||||||||
Net Regulatory Assets, Remaining Amortization Period, Max | 20 years 4 months | ||||||||||||||||||||||
Storm Costs [Member] | PUGET SOUND ENERGY, INC. | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Net Regulatory Assets, Remaining Amortization Period, Min | 1 year | ||||||||||||||||||||||
Net Regulatory Assets, Remaining Amortization Period, Max | 2 years | ||||||||||||||||||||||
Unamortized loss on reacquired debt | PUGET SOUND ENERGY, INC. | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Net Regulatory Assets, Remaining Amortization Period, Min | 1 year | ||||||||||||||||||||||
Net Regulatory Assets, Remaining Amortization Period, Max | 30 years | ||||||||||||||||||||||
Lower Snake River interest due [Member] | PUGET SOUND ENERGY, INC. | |||||||||||||||||||||||
Regulation and Rates [Line Items] | |||||||||||||||||||||||
Net Regulatory Assets, Remaining Amortization Period | 2 years |
Dividend Payment Restrictions (
Dividend Payment Restrictions (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Parent [Line Items] | |
Retained Earnings, Unappropriated | $ 532.9 |
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio, Threshold For Dividend Payment | 2 |
EBITDA Interest Expense Ratio | 3.5 |
EBITDA to Interest Expense Denominator | 1 |
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio at Period End | 1 |
PUGET SOUND ENERGY, INC. | |
Parent [Line Items] | |
Dividends, Common Equity Ratio, Threshold For Dividend Payment | 44.00% |
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio, Threshold For Dividend Payment | 3 |
Dividends, Common Equity Ratio at Period End | 47.90% |
EBITDA Interest Expense Ratio | 5.2 |
EBITDA to Interest Expense Denominator | 1 |
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio at Period End | 1 |
Utility Plant (Details)
Utility Plant (Details) - USD ($) $ in Thousands | 12 Months Ended | ||||
Dec. 31, 2016 | Sep. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | ||
Public Utility, Property, Plant and Equipment | |||||
Asset Retirement Obligations, Noncurrent | $ 45,700 | ||||
Decommissioning Liability, Noncurrent | $ 37,000 | $ 19,700 | |||
Accumulated amortization of capital leases | $ 600 | $ 32,300 | |||
Utility Plant | |||||
Distribution plant | 5,287,542 | 5,007,077 | |||
Production plant | 3,007,546 | 3,028,481 | |||
Transmission plant | 1,307,687 | 1,236,823 | |||
General plant | 541,424 | 491,845 | |||
Intangible plant (including capitalized software) | 347,697 | 305,705 | |||
Plant acquisition adjustment | 242,826 | 242,826 | |||
Underground storage | 30,695 | 28,914 | |||
Liquefied natural gas storage | 12,628 | 12,628 | |||
Plant held for future use | 52,484 | 55,890 | |||
Recoverable cushion gas | 8,655 | 8,655 | |||
Public Utilities, Property, Plant and Equipment, Other Property, Plant and Equipment | 159,345 | 65,892 | |||
Public Utilities, Property, Plant and Equipment Grant | (99,100) | (102,379) | |||
Capital leases, net of accumulated amortization | [1] | 645 | 378 | ||
Less: Accumulated depreciation and amortization | (2,161,796) | (1,878,868) | |||
Subtotal | 8,738,278 | 8,503,867 | |||
Construction work in progress | 420,278 | 408,795 | |||
Net utility plant | $ 9,158,556 | 8,912,662 | |||
Minimum | |||||
Public Utility, Property, Plant and Equipment | |||||
Distribution plant, Estimated Useful Life | 10 years | ||||
Production plant, Estimated Useful Life | 25 years | ||||
Transmission plant, Estimated Useful Life | 45 years | ||||
General plant, Estimated Useful Life | 5 years | ||||
Intangible plant (including capitalized software), Estimated Useful Life | 3 years | ||||
Plant acquisition adjustment, Estimated Useful Life | 7 years | ||||
Underground storage, Estimated Useful Life | 25 years | ||||
Liquefied natural gas storage, Estimated Useful Life | 25 years | ||||
Public Utilities, Property, Plant and Equipment, Plant Not Classified, Estimated Useful Life | 1 year | ||||
Capital leases, net of accumulated amortization, Estimated Useful Life | [1] | 1 year | |||
Maximum | |||||
Public Utility, Property, Plant and Equipment | |||||
Distribution plant, Estimated Useful Life | 50 years | ||||
Production plant, Estimated Useful Life | 125 years | ||||
Transmission plant, Estimated Useful Life | 65 years | ||||
General plant, Estimated Useful Life | 35 years | ||||
Intangible plant (including capitalized software), Estimated Useful Life | 50 years | ||||
Plant acquisition adjustment, Estimated Useful Life | 30 years | ||||
Underground storage, Estimated Useful Life | 60 years | ||||
Liquefied natural gas storage, Estimated Useful Life | 45 years | ||||
Public Utilities, Property, Plant and Equipment, Plant Not Classified, Estimated Useful Life | 100 years | ||||
Capital leases, net of accumulated amortization, Estimated Useful Life | [1] | 5 years | |||
PUGET SOUND ENERGY, INC. | |||||
Utility Plant | |||||
Distribution plant | $ 6,922,176 | 6,657,597 | |||
Production plant | 3,910,129 | 3,950,231 | |||
Transmission plant | 1,420,334 | 1,351,216 | |||
General plant | 611,237 | 563,850 | |||
Intangible plant (including capitalized software) | 338,327 | 294,380 | |||
Plant acquisition adjustment | 282,792 | 282,792 | |||
Underground storage | 44,206 | 42,545 | |||
Liquefied natural gas storage | 14,498 | 14,498 | |||
Plant held for future use | 52,636 | 56,042 | |||
Recoverable cushion gas | 8,655 | 8,655 | |||
Public Utilities, Property, Plant and Equipment, Other Property, Plant and Equipment | 159,345 | 65,892 | |||
Public Utilities, Property, Plant and Equipment Grant | (99,100) | (102,379) | |||
Capital leases, net of accumulated amortization | [1] | 645 | 378 | ||
Less: Accumulated depreciation and amortization | (4,927,602) | (4,681,830) | |||
Subtotal | 8,738,278 | 8,503,867 | |||
Construction work in progress | 420,278 | 408,795 | |||
Net utility plant | $ 9,158,556 | $ 8,912,662 | |||
[1] | Accumulated amortization of capital leases at Puget Energy and PSE was $0.6 million in 2016 and $32.3 million in 2015. |
Utility Plant - Jointly Owned U
Utility Plant - Jointly Owned Utility Plant (Details) $ in Thousands | Dec. 31, 2016USD ($) |
Colstrip Units 1 & 2 | |
Jointly Owned Utility Plant Interests | |
Company’s Ownership Share | 50.00% |
Plant in Service at Cost | $ 70,717 |
Accumulated Depreciation | $ (22,284) |
Colstrip Units 3 & 4 | |
Jointly Owned Utility Plant Interests | |
Company’s Ownership Share | 25.00% |
Plant in Service at Cost | $ 307,383 |
Accumulated Depreciation | (40,343) |
Colstrip Units 1 – 4 Common Facilities | |
Jointly Owned Utility Plant Interests | |
Plant in Service at Cost | 83 |
Accumulated Depreciation | $ (27) |
Frederickson 1 | |
Jointly Owned Utility Plant Interests | |
Company’s Ownership Share | 49.85% |
Plant in Service at Cost | $ 61,780 |
Accumulated Depreciation | $ (9,779) |
Jackson Prairie [Member] | |
Jointly Owned Utility Plant Interests | |
Company’s Ownership Share | 33.34% |
Plant in Service at Cost | $ 30,021 |
Accumulated Depreciation | (5,544) |
PUGET SOUND ENERGY, INC. | Colstrip Units 1 & 2 | |
Jointly Owned Utility Plant Interests | |
Plant in Service at Cost | 204,334 |
Accumulated Depreciation | (155,902) |
PUGET SOUND ENERGY, INC. | Colstrip Units 3 & 4 | |
Jointly Owned Utility Plant Interests | |
Plant in Service at Cost | 575,902 |
Accumulated Depreciation | (308,861) |
PUGET SOUND ENERGY, INC. | Colstrip Units 1 – 4 Common Facilities | |
Jointly Owned Utility Plant Interests | |
Plant in Service at Cost | 252 |
Accumulated Depreciation | (196) |
PUGET SOUND ENERGY, INC. | Frederickson 1 | |
Jointly Owned Utility Plant Interests | |
Plant in Service at Cost | 70,729 |
Accumulated Depreciation | (18,728) |
PUGET SOUND ENERGY, INC. | Jackson Prairie [Member] | |
Jointly Owned Utility Plant Interests | |
Plant in Service at Cost | 44,206 |
Accumulated Depreciation | $ (19,730) |
Utility Plant - Asset Retiremen
Utility Plant - Asset Retirement Obligation (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Asset retirement obligation at beginning of period | $ 85,028 | $ 48,909 |
New asset retirement obligation recognized in the period | 0 | 34,534 |
Liability adjustment in the period | (411) | (3,628) |
Revisions in estimated cash flows | 113,081 | 3,403 |
Accretion expense | 2,647 | 1,810 |
Asset retirement obligation at end of period | $ 200,345 | $ 85,028 |
Long-Term Debt (Schedule of Lon
Long-Term Debt (Schedule of Long-Term Debt Instruments) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Mar. 31, 2016 | ||
Debt Instrument [Line Items] | |||||
Current borrowing capacity of line of credit | $ 800,000 | ||||
Proceeds from long-term debt and bonds issued | 12,481 | $ 825,000 | $ 299,000 | ||
Total PSE long-term debt | 5,588,752 | ||||
Long Term Debt, Reconciliation, Fair Value Adjustment | (199,436) | (207,977) | |||
Long-term Line of Credit, Noncurrent | 12,480 | 0 | |||
Unamortized discount on senior notes | (6,269) | (8,867) | |||
Net PSE long-term debt | $ 5,354,073 | 5,327,518 | |||
Senior Secured Note | 6.500% Senior Secured Note Due 2020 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate percent | 6.50% | ||||
Total PSE long-term debt | $ 450,000 | 450,000 | |||
Senior Secured Note | 6.000% Senior Secured Note Due 2021 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate percent | 6.00% | ||||
Total PSE long-term debt | $ 500,000 | 500,000 | |||
Senior Secured Note | 5.625% Senior Secured Note Due 2022 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate percent | 5.625% | ||||
Total PSE long-term debt | $ 450,000 | 450,000 | |||
Senior Secured Note | 3.650% Senior Secured Note Due 2025 [Member] | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate percent | 3.65% | ||||
Total PSE long-term debt | $ 400,000 | 400,000 | |||
PUGET SOUND ENERGY, INC. | |||||
Debt Instrument [Line Items] | |||||
Current borrowing capacity of line of credit | 1,000,000 | ||||
Proceeds from long-term debt and bonds issued | 0 | 425,000 | $ 0 | ||
Total PSE long-term debt | 3,776,272 | ||||
Unamortized discount on senior notes | (28,974) | (31,910) | |||
Net PSE long-term debt | $ 3,747,298 | 3,744,362 | |||
PUGET SOUND ENERGY, INC. | Senior Notes and First Mortgage Bonds | 5.500% Secured Promissory Note Due 2017 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate percent | 5.50% | ||||
Total PSE long-term debt | [1] | $ 2,412 | 2,412 | ||
PUGET SOUND ENERGY, INC. | Senior Notes and First Mortgage Bonds | 7.150% Series Due 2025 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate percent | 7.15% | ||||
Total PSE long-term debt | $ 15,000 | 15,000 | |||
PUGET SOUND ENERGY, INC. | Senior Notes and First Mortgage Bonds | 7.200% Series Due 2025 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate percent | 7.20% | ||||
Total PSE long-term debt | $ 2,000 | 2,000 | |||
PUGET SOUND ENERGY, INC. | Pollution Control Bonds | 3.900% Series Due 2031 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate percent | 3.90% | ||||
Total PSE long-term debt | $ 138,460 | 138,460 | |||
PUGET SOUND ENERGY, INC. | Pollution Control Bonds | 4.000% Series Due 2031 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate percent | 4.00% | ||||
Total PSE long-term debt | $ 23,400 | 23,400 | |||
PUGET SOUND ENERGY, INC. | Junior Subordinated Notes | 6.974% Series Due 2067 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate percent | 6.974% | ||||
Total PSE long-term debt | $ 250,000 | 250,000 | |||
PUGET SOUND ENERGY, INC. | Senior Secured Note | 6.750% Series Due 2016 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate percent | 6.75% | ||||
Total PSE long-term debt | $ 250,000 | ||||
PUGET SOUND ENERGY, INC. | Senior Secured Note | 6.740% Series Due 2018 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate percent | 6.74% | ||||
Total PSE long-term debt | $ 200,000 | 200,000 | |||
PUGET SOUND ENERGY, INC. | Senior Secured Note | 7.020% Series Due 2027 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate percent | 7.02% | ||||
Total PSE long-term debt | $ 300,000 | 300,000 | |||
PUGET SOUND ENERGY, INC. | Senior Secured Note | 7.000% Series Due 2029 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate percent | 7.00% | ||||
Total PSE long-term debt | $ 100,000 | 100,000 | |||
PUGET SOUND ENERGY, INC. | Senior Secured Note | 5.483% Series Due 2035 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate percent | 5.483% | ||||
Total PSE long-term debt | $ 250,000 | 250,000 | |||
PUGET SOUND ENERGY, INC. | Senior Secured Note | 6.724% Series Due 2036 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate percent | 6.724% | ||||
Total PSE long-term debt | $ 250,000 | 250,000 | |||
PUGET SOUND ENERGY, INC. | Senior Secured Note | 6.274% Series Due 2037 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate percent | 6.274% | ||||
Total PSE long-term debt | $ 300,000 | 300,000 | |||
PUGET SOUND ENERGY, INC. | Senior Secured Note | 5.757% Series Due 2039 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate percent | 5.757% | ||||
Total PSE long-term debt | $ 350,000 | 350,000 | |||
PUGET SOUND ENERGY, INC. | Senior Secured Note | 5.795% Series Due 2040 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate percent | 5.795% | ||||
Total PSE long-term debt | $ 325,000 | 325,000 | |||
PUGET SOUND ENERGY, INC. | Senior Secured Note | 5.764% Series Due 2040 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate percent | 5.764% | ||||
Total PSE long-term debt | $ 250,000 | 250,000 | |||
PUGET SOUND ENERGY, INC. | Senior Secured Note | 4.434% Series Due 2041 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate percent | 4.434% | ||||
Total PSE long-term debt | $ 250,000 | 250,000 | |||
PUGET SOUND ENERGY, INC. | Senior Secured Note | 5.638% Series Due 2041 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate percent | 5.638% | ||||
Total PSE long-term debt | $ 300,000 | 300,000 | |||
PUGET SOUND ENERGY, INC. | Senior Secured Note | 4.300% Series Due 2045 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate percent | 4.30% | ||||
Total PSE long-term debt | $ 425,000 | 425,000 | |||
PUGET SOUND ENERGY, INC. | Senior Secured Note | 4.700% Series Due 2051 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate percent | 4.70% | ||||
Total PSE long-term debt | $ 45,000 | $ 45,000 | |||
PUGET SOUND ENERGY, INC. | Senior Secured Note | 3.650% Senior Secured Note Due 2025 [Member] | |||||
Debt Instrument [Line Items] | |||||
Total PSE long-term debt | $ 400,000 | ||||
[1] | Accumulated amortization of capital leases at Puget Energy and PSE was $0.6 million in 2016 and $32.3 million in 2015. |
Long-Term Debt (Narrative) (Det
Long-Term Debt (Narrative) (Details) - USD ($) | Dec. 31, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | May 12, 2015 | Feb. 10, 2012 |
Debt Instrument [Line Items] | |||||
Long-term debt | $ 5,588,752,000 | ||||
Current borrowing capacity of line of credit | 800,000,000 | ||||
Maximum borrowing capacity | 1,300,000,000 | ||||
Senior Secured Note | 3.650% Senior Secured Note Due 2025 [Member] | |||||
Debt Instrument [Line Items] | |||||
Long-term debt | $ 400,000,000 | $ 400,000,000 | |||
Stated interest rate percent | 3.65% | ||||
Revolving Credit Facility | |||||
Debt Instrument [Line Items] | |||||
Current borrowing capacity of line of credit | $ 800,000,000 | ||||
PUGET SOUND ENERGY, INC. | |||||
Debt Instrument [Line Items] | |||||
Long-term debt | $ 3,776,272,000 | ||||
Current borrowing capacity of line of credit | 1,000,000,000 | ||||
Maximum borrowing capacity | 1,500,000,000 | ||||
PUGET SOUND ENERGY, INC. | Senior Secured Note | 4.300% Series Due 2045 | |||||
Debt Instrument [Line Items] | |||||
Long-term debt | $ 425,000,000 | 425,000,000 | |||
Stated interest rate percent | 4.30% | ||||
PUGET SOUND ENERGY, INC. | Senior Secured Note | 5.197% Series Due 2015 | |||||
Debt Instrument [Line Items] | |||||
Long-term debt | $ 150,000,000 | ||||
Stated interest rate percent | 5.197% | ||||
PUGET SOUND ENERGY, INC. | Senior Secured Note | 6.750% Series Due 2016 | |||||
Debt Instrument [Line Items] | |||||
Long-term debt | $ 250,000,000 | ||||
Stated interest rate percent | 6.75% | ||||
PUGET SOUND ENERGY, INC. | Senior Secured Note | 3.650% Senior Secured Note Due 2025 [Member] | |||||
Debt Instrument [Line Items] | |||||
Long-term debt | $ 400,000,000 | ||||
PUGET SOUND ENERGY, INC. | Senior Notes [Member] | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate percent | 3.65% |
Long-Term Debt (Schedule of Mat
Long-Term Debt (Schedule of Maturities of Long-Term Debt) (Details) $ in Thousands | Dec. 31, 2016USD ($) |
Maturities of Long-term Debt [Abstract] | |
2,016 | $ 2,412 |
2,017 | 212,480 |
2,018 | 0 |
2,019 | 450,000 |
2,020 | 500,000 |
Thereafter | 4,423,860 |
Total long-term debt | 5,588,752 |
PUGET SOUND ENERGY, INC. | |
Maturities of Long-term Debt [Abstract] | |
2,016 | 2,412 |
2,017 | 200,000 |
2,018 | 0 |
2,019 | 0 |
2,020 | 0 |
Thereafter | 3,573,860 |
Total long-term debt | 3,776,272 |
Parent Company [Member] | |
Maturities of Long-term Debt [Abstract] | |
2,016 | 0 |
2,017 | 12,480 |
2,018 | 0 |
2,019 | 450,000 |
2,020 | 500,000 |
Thereafter | 850,000 |
Total long-term debt | $ 1,812,480 |
Liquidity Facilities and Othe53
Liquidity Facilities and Other Financing Arrangements (Details) - USD ($) | Feb. 10, 2012 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Short-term Debt [Line Items] | ||||
Short-term debt | $ 245,763,000 | $ 159,004,000 | ||
Current borrowing capacity of line of credit | 800,000,000 | |||
Maximum borrowing capacity | 1,300,000,000 | |||
Long-term Line of Credit, Noncurrent | 12,480,000 | 0 | ||
Energy Hedging Activities [Member] | ||||
Short-term Debt [Line Items] | ||||
Current borrowing capacity of line of credit | 350,000,000 | |||
Senior secured credit facility | ||||
Short-term Debt [Line Items] | ||||
Short-term debt | $ 0 | $ 0 | ||
Revolving Credit Facility | ||||
Short-term Debt [Line Items] | ||||
Current borrowing capacity of line of credit | $ 800,000,000 | |||
Basis spread on variable rate (percent) | 1.75% | |||
Commitment fee percentage for line of credit | 0.275% | |||
PUGET SOUND ENERGY, INC. | ||||
Short-term Debt [Line Items] | ||||
Short-term debt | $ 245,763,000 | $ 159,004,000 | $ 159,000,000 | |
Weighted-average interest rate on short-term debt (percent) | 3.21% | 4.24% | ||
Current borrowing capacity of line of credit | $ 1,000,000,000 | |||
Current same-day borrowing capacity | 75,000,000 | |||
Maximum borrowing capacity | $ 1,500,000,000 | |||
Maximum capitalization percentage | 65.00% | |||
Derivative, Basis Spread on Variable Rate | 1.75% | |||
Line of Credit, Unused Capacity, Commitment Fee Percentage | 0.275% | |||
PUGET SOUND ENERGY, INC. | Working Capital Needs | ||||
Short-term Debt [Line Items] | ||||
Current borrowing capacity of line of credit | $ 650,000,000 | |||
PUGET SOUND ENERGY, INC. | Energy Hedging Activities [Member] | ||||
Short-term Debt [Line Items] | ||||
Outstanding amount for line of credit | 1,000,000 | |||
Current borrowing capacity of line of credit | 350,000,000 | |||
PUGET SOUND ENERGY, INC. | Letter of Credit | Working Capital Needs | ||||
Short-term Debt [Line Items] | ||||
Outstanding amount for line of credit | 245,800,000 | |||
Current borrowing capacity of line of credit | 3,500,000 | |||
PUGET SOUND ENERGY, INC. | Senior secured credit facility | Promissory Note with Puget Energy | ||||
Short-term Debt [Line Items] | ||||
Current borrowing capacity of line of credit | $ 30,000,000 | |||
Basis spread on variable rate (percent) | 0.25% | |||
Debt instrument variable rate basis | one-month LIBOR | |||
Parent Company [Member] | ||||
Short-term Debt [Line Items] | ||||
Long-term Line of Credit, Noncurrent | $ 12,500,000 |
Leases (Schedule of Operating L
Leases (Schedule of Operating Lease Expense) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
PUGET SOUND ENERGY, INC. | |||
Operating Leases, Rent Expense, Net [Abstract] | |||
Operating lease expense net of sublease receipts | $ 31,786 | $ 27,843 | $ 30,737 |
Leases (Schedule of Future Mini
Leases (Schedule of Future Minimum Lease Payments for Non-cancellable Leases) (Details) - PUGET SOUND ENERGY, INC. $ in Thousands | Dec. 31, 2016USD ($) |
Operating | |
2,014 | $ 22,212 |
2,015 | 19,834 |
2,016 | 18,078 |
2,017 | 16,507 |
2,018 | 8,137 |
Thereafter | 102,393 |
Total minimum lease payments | 187,161 |
Capital | |
2,014 | 296 |
2,015 | 296 |
2,016 | 74 |
2,017 | 0 |
2,018 | 0 |
Thereafter | 0 |
Total minimum lease payments | $ 666 |
Accounting for Derivative Ins56
Accounting for Derivative Instruments and Hedging Activities (Narrative) (Details) $ in Thousands | Dec. 31, 2016USD ($)Contracts | Dec. 31, 2015USD ($) |
Electric Portfolio | ||
Derivative [Line Items] | ||
Collateral Already Posted, Aggregate Fair Value | $ 0 | $ 0 |
Parent Company [Member] | Interest Rate Swap [Member] | ||
Derivative [Line Items] | ||
Number of interest rate derivatives held | Contracts | 2 | |
Credit Rating | Natural Gas Portfolio | ||
Derivative [Line Items] | ||
Collateral Already Posted, Aggregate Fair Value | $ 1,000 | |
External Credit Rating, Investment Grade [Member] | Electric Portfolio | ||
Derivative [Line Items] | ||
Percentage of derivatives with credit risk exposure | 93.10% | |
External Credit Rating, Non Investment Grade [Member] | Electric Portfolio | ||
Derivative [Line Items] | ||
Percentage of derivatives with credit risk exposure | 6.90% |
Accounting for Derivative Ins57
Accounting for Derivative Instruments and Hedging Activities (Schedule of Derivative Assets and Liabilities) (Details) $ in Thousands, MWh in Millions, MMBTU in Millions | Dec. 31, 2016USD ($)MWhMMBTUContracts | Dec. 31, 2015USD ($)MWhMMBTU | ||
Derivative [Line Items] | ||||
Assets, Current | $ 54,341 | $ 24,418 | ||
Assets, Long-term | 8,738 | 5,225 | ||
Liabilities, Current | 44,310 | 136,173 | ||
Liabilities, Long-term | 16,261 | 48,073 | ||
Parent Company [Member] | ||||
Derivative [Line Items] | ||||
Liabilities, Current | 141 | 4,753 | ||
Liabilities, Long-term | 0 | 297 | ||
PUGET SOUND ENERGY, INC. | ||||
Derivative [Line Items] | ||||
Assets, Current | 54,341 | 24,418 | ||
Assets, Long-term | 8,738 | 5,225 | ||
Liabilities, Current | 44,170 | 131,420 | ||
Liabilities, Long-term | $ 16,261 | 47,776 | ||
Interest Rate Swap [Member] | Parent Company [Member] | ||||
Derivative [Line Items] | ||||
Number of interest rate derivatives held | Contracts | 2 | |||
Commodity Contract | ||||
Derivative [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | [1] | $ 63,079 | 29,643 | |
Total derivative assets | 63,079 | 29,643 | ||
Total derivative liabilities | 60,430 | 179,196 | ||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | 0 | 0 | ||
Derivative, Collateral, Obligation to Return Securities | (42,858) | (23,998) | ||
Derivative, Collateral, Obligation to Return Cash | 0 | 0 | ||
Derivative Asset, Fair Value, Amount Offset Against Collateral | 20,221 | 5,645 | ||
Derivative Liability, Fair Value, Gross Liability | [1] | 60,430 | 179,196 | |
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 0 | [2] | 0 | |
Derivative, Collateral, Right to Reclaim Securities | (42,858) | (23,998) | ||
Derivative, Collateral, Right to Reclaim Cash | 0 | 0 | ||
Derivative Liability, Fair Value, Amount Offset Against Collateral | 17,572 | 155,198 | ||
Interest Rate Contract | ||||
Derivative [Line Items] | ||||
Total derivative liabilities | [2] | 141 | 5,050 | |
Derivative Liability, Fair Value, Gross Liability | [1],[2] | 141 | 5,050 | |
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | [2] | 0 | ||
Derivative, Collateral, Right to Reclaim Securities | [2] | 0 | 0 | |
Derivative, Collateral, Right to Reclaim Cash | [2] | 0 | 0 | |
Derivative Liability, Fair Value, Amount Offset Against Collateral | [2] | 141 | 5,050 | |
Not Designated as Hedging Instrument | ||||
Derivative [Line Items] | ||||
Total derivative assets | [3] | 63,079 | 29,643 | |
Total derivative liabilities | [4] | 60,571 | 184,246 | |
Not Designated as Hedging Instrument | Parent Company [Member] | ||||
Derivative [Line Items] | ||||
Assets, Current | [3] | 54,341 | 24,418 | |
Assets, Long-term | [3] | 8,738 | 5,225 | |
Liabilities, Current | [4] | 44,310 | 136,173 | |
Liabilities, Long-term | [4] | 16,261 | 48,073 | |
Not Designated as Hedging Instrument | Interest Rate Swap [Member] | ||||
Derivative [Line Items] | ||||
Derivative, Notional Amount | [5] | 450,000 | 450,000 | |
Total derivative assets | [3],[5] | 0 | 0 | |
Total derivative liabilities | [4],[5] | $ 141 | $ 5,050 | |
Not Designated as Hedging Instrument | Electric Generation Fuel | ||||
Derivative [Line Items] | ||||
Derivative, Nonmonetary Notional Amount | MMBTU | 186.8 | 202.1 | ||
Not Designated as Hedging Instrument | Purchased Electricity | ||||
Derivative [Line Items] | ||||
Derivative, Nonmonetary Notional Amount | MWh | 3.6 | 0.1 | ||
Not Designated as Hedging Instrument | Electric Portfolio | ||||
Derivative [Line Items] | ||||
Total derivative assets | [3] | $ 36,460 | $ 23,443 | |
Total derivative liabilities | [4] | 41,329 | 112,106 | |
Not Designated as Hedging Instrument | Natural Gas Portfolio | ||||
Derivative [Line Items] | ||||
Total derivative assets | [3],[6] | 26,619 | 6,200 | |
Total derivative liabilities | [4],[6] | $ 19,101 | $ 67,090 | |
Not Designated as Hedging Instrument | Gas Derivatives | ||||
Derivative [Line Items] | ||||
Derivative, Nonmonetary Notional Amount | MMBTU | [6] | 336.4 | 369.5 | |
[1] | All Derivative Contract deals are executed under ISDA, NAESB and WSPP Master Netting Agreements with Right of set-off. | |||
[2] | Interest Rate Swap Contracts are only held at Puget Energy. | |||
[3] | Balance sheet location: Current and Long-term Unrealized gain on derivative instruments. | |||
[4] | Balance sheet location: Current and Long-term Unrealized loss on derivative instruments. | |||
[5] | Interest rate swap contracts are only held at Puget Energy. | |||
[6] | 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 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. |
Accounting for Derivative Ins58
Accounting for Derivative Instruments and Hedging Activities (Schedule of Amounts Recognized in Statement of Income) (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Derivative Instruments, (Loss) Gain [Line Items] | ||||
Unrealized (gain) loss on derivative instruments | $ (83,795) | $ (13,233) | $ 84,146 | |
PUGET SOUND ENERGY, INC. | ||||
Derivative Instruments, (Loss) Gain [Line Items] | ||||
Unrealized (gain) loss on derivative instruments | (83,795) | (12,688) | 85,636 | |
Not Designated as Hedging Instrument | ||||
Derivative Instruments, (Loss) Gain [Line Items] | ||||
Unrealized (gain) loss on derivative instruments | (21,079) | 73,788 | 85,262 | |
Not Designated as Hedging Instrument | Other Income (Deductions) | Interest Expense | ||||
Derivative Instruments, (Loss) Gain [Line Items] | ||||
Unrealized (gain) loss on derivative instruments | 1,062 | 3,796 | 3,915 | |
Not Designated as Hedging Instrument | Interest Rate Contract | Interest Expense | ||||
Derivative Instruments, (Loss) Gain [Line Items] | ||||
Unrealized (gain) loss on derivative instruments | 0 | (560) | (500) | |
Not Designated as Hedging Instrument | Energy Related Derivative [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net | ||||
Derivative Instruments, (Loss) Gain [Line Items] | ||||
Unrealized (gain) loss on derivative instruments | (62,318) | 9,315 | 42,334 | |
Not Designated as Hedging Instrument | Commodity Contract | Electric Generation Fuel | ||||
Derivative Instruments, (Loss) Gain [Line Items] | ||||
Unrealized (gain) loss on derivative instruments | 39,656 | 44,648 | (6,511) | |
Not Designated as Hedging Instrument | Commodity Contract | Purchased Electricity | ||||
Derivative Instruments, (Loss) Gain [Line Items] | ||||
Unrealized (gain) loss on derivative instruments | 21,998 | 39,137 | 4,212 | |
Not Designated as Hedging Instrument | Electric [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net | ||||
Derivative Instruments, (Loss) Gain [Line Items] | ||||
Unrealized (gain) loss on derivative instruments | [1] | (21,477) | (22,548) | 41,812 |
Not Designated as Hedging Instrument | PUGET SOUND ENERGY, INC. | ||||
Derivative Instruments, (Loss) Gain [Line Items] | ||||
Unrealized (gain) loss on derivative instruments | (22,141) | 71,097 | 83,337 | |
Not Designated as Hedging Instrument | PUGET SOUND ENERGY, INC. | Energy Related Derivative [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net | ||||
Derivative Instruments, (Loss) Gain [Line Items] | ||||
Unrealized (gain) loss on derivative instruments | (62,318) | 9,315 | 42,334 | |
Not Designated as Hedging Instrument | PUGET SOUND ENERGY, INC. | Commodity Contract | Electric Generation Fuel | ||||
Derivative Instruments, (Loss) Gain [Line Items] | ||||
Unrealized (gain) loss on derivative instruments | 39,656 | 44,648 | (6,511) | |
Not Designated as Hedging Instrument | PUGET SOUND ENERGY, INC. | Commodity Contract | Purchased Electricity | ||||
Derivative Instruments, (Loss) Gain [Line Items] | ||||
Unrealized (gain) loss on derivative instruments | 21,998 | 39,137 | 4,212 | |
Not Designated as Hedging Instrument | PUGET SOUND ENERGY, INC. | Electric [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net | ||||
Derivative Instruments, (Loss) Gain [Line Items] | ||||
Unrealized (gain) loss on derivative instruments | [1] | $ (21,477) | $ (22,003) | $ 43,302 |
[1] | Differences between Puget Energy and PSE for the twelve months ended December 31, 2015 and 2014 are due to certain derivative contracts recorded at fair value in 2009 and subsequently designated as NPNS or cash flow hedges. These differences occurred through February 2015. |
Accounting for Derivative Ins59
Accounting for Derivative Instruments and Hedging Activities (Schedule of Amounts Recognized in Other Comprehensive Income) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | Parent Company [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax | $ 0 | $ (512) | $ (572) |
Accounting for Derivative Ins60
Accounting for Derivative Instruments and Hedging Activities (Schedule of Effects of Non-hedging Derivative Instruments on Income) (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Total gain (loss) recognized in income on derivatives | $ 83,795 | $ 13,233 | $ (84,146) | |
Derivative contracts classified as financing activities due to merger | 0 | (8,045) | (16,349) | |
Other Comprehensive Income Reclassification Of Net Unrealized Gain Loss On Interest Rate Swaps During Period Net Of Tax | 0 | 0 | (94) | |
Not Designated as Hedging Instrument | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Total gain (loss) recognized in income on derivatives | 21,079 | (73,788) | (85,262) | |
Not Designated as Hedging Instrument | Energy Related Derivative [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Total gain (loss) recognized in income on derivatives | 62,318 | (9,315) | (42,334) | |
Not Designated as Hedging Instrument | Interest Rate Contract | Interest Expense | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Total gain (loss) recognized in income on derivatives | 0 | 560 | 500 | |
Not Designated as Hedging Instrument | Commodity contracts: | Electric Generation Fuel | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Total gain (loss) recognized in income on derivatives | (39,656) | (44,648) | 6,511 | |
Not Designated as Hedging Instrument | Commodity contracts: | Purchased Electricity | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Total gain (loss) recognized in income on derivatives | (21,998) | (39,137) | (4,212) | |
Not Designated as Hedging Instrument | Electric [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Total gain (loss) recognized in income on derivatives | [1] | 21,477 | 22,548 | (41,812) |
PUGET SOUND ENERGY, INC. | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Total gain (loss) recognized in income on derivatives | 83,795 | 12,688 | (85,636) | |
PUGET SOUND ENERGY, INC. | Not Designated as Hedging Instrument | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Total gain (loss) recognized in income on derivatives | 22,141 | (71,097) | (83,337) | |
PUGET SOUND ENERGY, INC. | Not Designated as Hedging Instrument | Energy Related Derivative [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Total gain (loss) recognized in income on derivatives | 62,318 | (9,315) | (42,334) | |
PUGET SOUND ENERGY, INC. | Not Designated as Hedging Instrument | Commodity contracts: | Electric Generation Fuel | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Total gain (loss) recognized in income on derivatives | (39,656) | (44,648) | 6,511 | |
PUGET SOUND ENERGY, INC. | Not Designated as Hedging Instrument | Commodity contracts: | Purchased Electricity | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Total gain (loss) recognized in income on derivatives | (21,998) | (39,137) | (4,212) | |
PUGET SOUND ENERGY, INC. | Not Designated as Hedging Instrument | Electric [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Total gain (loss) recognized in income on derivatives | [1] | $ 21,477 | $ 22,003 | $ (43,302) |
[1] | Differences between Puget Energy and PSE for the twelve months ended December 31, 2015 and 2014 are due to certain derivative contracts recorded at fair value in 2009 and subsequently designated as NPNS or cash flow hedges. These differences occurred through February 2015. |
Accounting for Derivative Ins61
Accounting for Derivative Instruments and Hedging Activities (Schedule of Contractual Contingent Liability Positions) (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | |
Electric Portfolio | |||
Derivative [Line Items] | |||
Fair Value Liability | [1] | $ 12,828 | $ 91,190 |
Collateral Already Posted, Aggregate Fair Value | 0 | 0 | |
Contingent Collateral | 4,894 | 24,187 | |
Credit Rating | Natural Gas Portfolio | |||
Derivative [Line Items] | |||
Collateral Already Posted, Aggregate Fair Value | 1,000 | ||
Forward Value of Contract [Member] | Electric Portfolio | |||
Derivative [Line Items] | |||
Fair Value Liability | [1],[2] | 507 | 0 |
Collateral Already Posted, Aggregate Fair Value | [2] | 0 | 0 |
Contingent Collateral | [2] | 0 | 0 |
Requested Credit for Adequate Assurance | Electric Portfolio | |||
Derivative [Line Items] | |||
Fair Value Liability | [1] | 7,427 | 67,003 |
Collateral Already Posted, Aggregate Fair Value | 0 | 0 | |
Contingent Collateral | 0 | 0 | |
Credit Rating | Electric Portfolio | |||
Derivative [Line Items] | |||
Fair Value Liability | [1],[3] | 4,894 | 24,187 |
Collateral Already Posted, Aggregate Fair Value | [3] | 0 | 0 |
Contingent Collateral | [3] | $ 4,894 | $ 24,187 |
[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] | 3 Collateral requirements may vary, based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds. | ||
[3] | 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. |
Fair Value Measurements - Asset
Fair Value Measurements - Assets and Liabilities Measured on Recurring Basis (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | |
Interest Rate Contract | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Liabilities | [1] | $ 141 | $ 5,050 |
Fair Value, Measurements, Recurring | Parent Company [Member] | Level 2 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Liabilities | 141 | 5,050 | |
Fair Value, Measurements, Recurring | Parent Company [Member] | Level 2 | Interest Rate Contract | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Liabilities | 141 | 5,050 | |
Fair Value, Measurements, Recurring | Parent Company [Member] | Level 3 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Liabilities | 0 | 0 | |
Fair Value, Measurements, Recurring | Parent Company [Member] | Level 3 | Electric Portfolio | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Assets | [2] | 5,794 | |
Derivative Liabilities | [2] | 4,822 | |
Fair Value, Measurements, Recurring | Parent Company [Member] | Level 3 | Natural Gas Portfolio | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Assets | [2] | 3,303 | |
Derivative Liabilities | [2] | 2,678 | |
Fair Value, Measurements, Recurring | Parent Company [Member] | Level 3 | Interest Rate Contract | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Liabilities | 0 | 0 | |
Fair Value, Measurements, Recurring | Parent Company [Member] | Total | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Liabilities | 141 | 5,050 | |
Fair Value, Measurements, Recurring | Parent Company [Member] | Total | Interest Rate Contract | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Liabilities | 141 | 5,050 | |
Fair Value, Measurements, Recurring | PUGET SOUND ENERGY, INC. | Level 2 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Assets | 53,982 | 15,247 | |
Derivative Liabilities | 52,930 | 155,072 | |
Fair Value, Measurements, Recurring | PUGET SOUND ENERGY, INC. | Level 2 | Electric Portfolio | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Assets | 30,666 | 10,709 | |
Derivative Liabilities | 36,507 | 92,027 | |
Fair Value, Measurements, Recurring | PUGET SOUND ENERGY, INC. | Level 2 | Natural Gas Portfolio | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Assets | 23,316 | 4,538 | |
Derivative Liabilities | 16,423 | 63,045 | |
Fair Value, Measurements, Recurring | PUGET SOUND ENERGY, INC. | Level 3 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Assets | 9,097 | 14,396 | |
Derivative Liabilities | 7,500 | 24,124 | |
Fair Value, Measurements, Recurring | PUGET SOUND ENERGY, INC. | Level 3 | Electric Portfolio | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Assets | 12,734 | ||
Derivative Liabilities | 20,079 | ||
Fair Value, Measurements, Recurring | PUGET SOUND ENERGY, INC. | Level 3 | Natural Gas Portfolio | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Assets | 1,662 | ||
Derivative Liabilities | 4,045 | ||
Fair Value, Measurements, Recurring | PUGET SOUND ENERGY, INC. | Total | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Assets | 63,079 | 29,643 | |
Derivative Liabilities | 60,430 | 179,196 | |
Fair Value, Measurements, Recurring | PUGET SOUND ENERGY, INC. | Total | Electric Portfolio | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Assets | 36,460 | 23,443 | |
Derivative Liabilities | 41,329 | 112,106 | |
Fair Value, Measurements, Recurring | PUGET SOUND ENERGY, INC. | Total | Natural Gas Portfolio | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Assets | 26,619 | 6,200 | |
Derivative Liabilities | 19,101 | 67,090 | |
Carrying Amount | Parent Company [Member] | Level 2 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Notes receivable and other | $ 49,100 | $ 52,800 | |
[1] | Interest Rate Swap Contracts are only held at Puget Energy. | ||
[2] | The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions. |
Fair Value Measurements - Debt
Fair Value Measurements - Debt at Carrying and Fair Value (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | |
PUGET SOUND ENERGY, INC. | Carrying Amount | Income Approach Valuation Technique | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure | $ 3,747,298 | $ 3,744,362 | |
PUGET SOUND ENERGY, INC. | Carrying Amount | Income Approach Valuation Technique | Level 2 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Unamortized Debt Issuance Expense | 27,200 | 30,000 | |
Junior subordinated notes | 250,000 | 250,000 | |
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure | [1] | 3,497,298 | 3,494,362 |
PUGET SOUND ENERGY, INC. | Total | Income Approach Valuation Technique | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure | 4,571,044 | 4,540,617 | |
PUGET SOUND ENERGY, INC. | Total | Income Approach Valuation Technique | Level 2 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Junior subordinated notes | 210,261 | 211,173 | |
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure | [1] | 4,360,783 | 4,329,444 |
Parent Company [Member] | Carrying Amount | Level 2 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Notes Receivable, Fair Value Disclosure | 49,100 | 52,800 | |
Parent Company [Member] | Carrying Amount | Income Approach Valuation Technique | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure | 5,354,073 | 5,327,518 | |
Parent Company [Member] | Carrying Amount | Income Approach Valuation Technique | Level 2 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Unamortized Debt Issuance Expense | 33,000 | 38,400 | |
Junior subordinated notes | 250,000 | 250,000 | |
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure | [2] | 5,091,593 | 5,077,518 |
Long-term Debt, Variable Rate, Net of Discount, Fair Value Disclosure | 12,480 | 0 | |
Parent Company [Member] | Total | Income Approach Valuation Technique | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure | 6,560,028 | 6,520,004 | |
Parent Company [Member] | Total | Income Approach Valuation Technique | Level 2 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Junior subordinated notes | 210,261 | 211,173 | |
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure | [2] | 6,337,287 | 6,308,831 |
Long-term Debt, Variable Rate, Net of Discount, Fair Value Disclosure | $ 12,480 | $ 0 | |
[1] | 2 The carrying value includes debt issuances costs of $27.2 million and $30.0 million for December 31, 2016 and 2015, respectively, which are not included in fair value. | ||
[2] | 1 The carrying value includes debt issuances costs of $33.0 million and $38.4 million for December 31, 2016 and 2015, respectively, which are not included in fair value. |
Fair Value Measurements - Unobs
Fair Value Measurements - Unobservable Input Reconciliation (Details) | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||
Mar. 31, 2016USD ($)$ / MWh | Sep. 30, 2016USD ($)$ / MWh | Dec. 31, 2016USD ($)$ / MWh | Dec. 31, 2015USD ($)$ / MWh | Dec. 31, 2014USD ($) | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||||
Balance at beginning of period | $ (9,728,000) | $ (9,728,000) | $ (9,728,000) | $ (14,102,000) | $ (15,782,000) | |
Included in earnings | [1] | 4,007,000 | (6,432,000) | (5,537,000) | ||
Included in regulatory assets / liabilities | 4,312,000 | 3,695,000 | 1,630,000 | |||
Settlements | [2] | (3,808,000) | (2,983,000) | (498,000) | ||
Transferred into Level 3 | (3,021,000) | (787,000) | 4,570,000 | |||
Transferred out of Level 3 | 9,835,000 | 10,881,000 | 1,515,000 | |||
Balance at end of period | 1,597,000 | (9,728,000) | (14,102,000) | |||
Electric Portfolio | ||||||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||||
Balance at beginning of period | (7,345,000) | (7,345,000) | (7,345,000) | (12,062,000) | (15,421,000) | |
Included in earnings | [1] | 4,007,000 | (6,432,000) | (5,537,000) | ||
Included in regulatory assets / liabilities | 0 | 0 | 0 | |||
Settlements | [2] | (1,129,000) | 902,000 | 1,036,000 | ||
Transferred into Level 3 | (3,021,000) | (787,000) | 5,155,000 | |||
Transferred out of Level 3 | 8,460,000 | 11,034,000 | 2,705,000 | |||
Balance at end of period | 972,000 | (7,345,000) | (12,062,000) | |||
Unrealized gain (loss) on derivative instruments, net | 2,000,000 | (7,400,000) | (9,600,000) | |||
Natural Gas Portfolio | ||||||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||||
Balance at beginning of period | $ (2,383,000) | $ (2,383,000) | (2,383,000) | (2,040,000) | (361,000) | |
Included in earnings | [1] | 0 | 0 | 0 | ||
Included in regulatory assets / liabilities | 4,312,000 | 3,695,000 | 1,630,000 | |||
Settlements | [2] | (2,679,000) | (3,885,000) | (1,534,000) | ||
Transferred into Level 3 | 0 | 0 | (585,000) | |||
Transferred out of Level 3 | 1,375,000 | (153,000) | (1,190,000) | |||
Balance at end of period | $ 625,000 | $ (2,383,000) | $ (2,040,000) | |||
Income Approach Valuation Technique | Minimum | ||||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||||
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh | 0 | 0 | 0 | |||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||||
Fair Value Inputs, Power Contract Costs | $ 4,100 | $ 618 | $ 4,100 | |||
Income Approach Valuation Technique | Minimum | Electric Portfolio | ||||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||||
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh | 11.86 | |||||
Income Approach Valuation Technique | Maximum | ||||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||||
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh | 25.96 | 58.96 | 27.25 | |||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||||
Fair Value Inputs, Power Contract Costs | $ 4,659 | $ 4,633 | $ 4,659 | |||
Income Approach Valuation Technique | Maximum | Electric Portfolio | ||||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||||
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh | 33.52 | |||||
Income Approach Valuation Technique | Weighted Average | ||||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||||
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh | 0 | 0 | 0 | |||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||||
Fair Value Inputs, Power Contract Costs | $ 4,452 | $ 2,472 | $ 4,417 | |||
Income Approach Valuation Technique | Weighted Average | Electric Portfolio | ||||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||||
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh | 27.61 | |||||
[1] | Income Statement location: Unrealized (gain) loss on derivative instruments, net. Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $2.0 million, $(7.4) million and $(9.6) million for the years ended December 31, 2016, 2015 and 2014, respectively. | |||||
[2] | The Company had no purchases, sales or issuances during the reported periods. |
Fair Value Measurements - Valua
Fair Value Measurements - Valuation Techniques (Details) | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||
Mar. 31, 2016USD ($)$ / MWh | Sep. 30, 2016USD ($)$ / MWh | Dec. 31, 2016USD ($)$ / MMBTU$ / MWh | Dec. 31, 2015USD ($)$ / MWh | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Impairment of Intangible Assets (Excluding Goodwill) | $ 5,338,000 | $ 12,778,000 | $ 5,360,000 | ||
Fair Value measurement, sensitivity analysis, hypothetical increase or decrease of market prices, result on fair value, percent | 10.00% | ||||
Fair Value Measurements, Sensitivity Analysis, Hypothetical Increase or Decrease of Market Prices, Result on Fair Value | $ 200,000 | ||||
Income Approach Valuation Technique | Minimum | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh | 0 | 0 | 0 | ||
Fair Value Inputs, Power Contract Costs | $ 4,100 | $ 618 | $ 4,100 | ||
Income Approach Valuation Technique | Maximum | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh | 25.96 | 58.96 | 27.25 | ||
Fair Value Inputs, Power Contract Costs | $ 4,659 | $ 4,633 | $ 4,659 | ||
Income Approach Valuation Technique | Weighted Average | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh | 0 | 0 | 0 | ||
Fair Value Inputs, Power Contract Costs | $ 4,452 | $ 2,472 | $ 4,417 | ||
Parent Company [Member] | Fair Value, Measurements, Recurring | Level 3 | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative liabilities | 0 | 0 | |||
Commodity Contract | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative assets | 63,079,000 | 29,643,000 | |||
Derivative liabilities | $ 60,430,000 | 179,196,000 | |||
Natural Gas Portfolio | Income Approach Valuation Technique | Minimum | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value Inputs, Price Per Millions of BTU | $ / MMBTU | 2 | ||||
Natural Gas Portfolio | Income Approach Valuation Technique | Maximum | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value Inputs, Price Per Millions of BTU | $ / MMBTU | 3.24 | ||||
Natural Gas Portfolio | Income Approach Valuation Technique | Weighted Average | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value Inputs, Price Per Millions of BTU | $ / MMBTU | 2.42 | ||||
Natural Gas Portfolio | Parent Company [Member] | Fair Value, Measurements, Recurring | Level 3 | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative assets | [1] | $ 3,303,000 | |||
Derivative liabilities | [1] | $ 2,678,000 | |||
Electric Portfolio | Income Approach Valuation Technique | Minimum | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh | 11.86 | ||||
Electric Portfolio | Income Approach Valuation Technique | Maximum | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh | 33.52 | ||||
Electric Portfolio | Income Approach Valuation Technique | Weighted Average | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh | 27.61 | ||||
Electric Portfolio | Parent Company [Member] | Fair Value, Measurements, Recurring | Level 3 | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative assets | [1] | $ 5,794,000 | |||
Derivative liabilities | [1] | $ 4,822,000 | |||
Wells Project | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Finite-Lived Intangible Assets, Net | 25,193,000 | 32,988,000 | |||
Priest Rapids Development | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Finite-Lived Intangible Assets, Net | 18,969,000 | ||||
Carrying Amount | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Finite-lived Intangible Assets, Fair Value Disclosure | $ 19,855,000 | $ 6,191,000 | $ 27,628,000 | ||
[1] | The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions. |
Employee Investment Plans (Deta
Employee Investment Plans (Details) - PUGET SOUND ENERGY, INC. $ in Millions | 3 Months Ended | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | |
Defined Contribution Plan | ||||
Employer matching contribution, percent | 1.00% | 4.00% | ||
Employer discretionary contribution amount | $ 17.2 | $ 16.1 | $ 14.9 | |
Defined Contribution Plan, Vesting Years | 3 | 3 | ||
6 percent | ||||
Defined Contribution Plan | ||||
Employer matching contribution, percent | 4.50% | |||
Maximum annual contribution per employee, percent | 6.00% | |||
Cash Balance Formula | ||||
Defined Contribution Plan | ||||
Employer matching contribution, percent | 100.00% | |||
Maximum annual contribution per employee, percent | 6.00% | |||
Employer additional contribution of base pay, percentage | 1.00% | |||
Cash Balance Formula | First 3 Percent | ||||
Defined Contribution Plan | ||||
Employer matching contribution, percent | 100.00% | |||
Maximum annual contribution per employee, percent | 3.00% | |||
Cash Balance Formula | Second 3 Percent | ||||
Defined Contribution Plan | ||||
Employer matching contribution, percent | 50.00% | |||
Maximum annual contribution per employee, percent | 3.00% | |||
Final Average Earnings Formula | ||||
Defined Contribution Plan | ||||
Employer matching contribution, percent | 55.00% | |||
Maximum annual contribution per employee, percent | 6.00% |
Retirement Benefits - Change in
Retirement Benefits - Change in Net Benefit Obligation and Fair Value (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Qualified Pension Benefits | |||
Change in benefit obligation: | |||
Benefit obligation at beginning of period | $ 643,088 | $ 690,194 | |
Service cost | 18,913 | 21,287 | $ 17,437 |
Interest cost | 28,689 | 28,088 | 28,039 |
Actuarial loss (gain) | 1,545 | (55,665) | |
Benefits paid | (38,730) | (39,963) | |
Medicare part D subsidy received | 0 | 0 | |
Defined Benefit Plan, Expected Administration Expenses | (898) | (853) | |
Benefit obligation at end of period | 652,607 | 643,088 | 690,194 |
Change in plan assets: | |||
Fair value of plan assets at beginning of period | 598,865 | 626,173 | |
Actual return on plan assets | 37,022 | (4,489) | |
Employer contribution | 24,000 | 18,000 | |
Benefits paid | (38,730) | (39,963) | |
Defined Benefit Plan, Administration Expenses | (897) | (856) | |
Fair value of plan assets at end of period | 620,260 | 598,865 | 626,173 |
Funded status at end of period | (32,347) | (44,223) | |
Supplemental Employee Retirement Plan [Member] | |||
Change in benefit obligation: | |||
Benefit obligation at beginning of period | 51,279 | 55,855 | |
Service cost | 1,085 | 1,108 | 1,042 |
Interest cost | 2,325 | 2,281 | 2,310 |
Actuarial loss (gain) | 106 | (4,430) | |
Benefits paid | (3,061) | (3,535) | |
Medicare part D subsidy received | 0 | 0 | |
Defined Benefit Plan, Expected Administration Expenses | 0 | 0 | |
Benefit obligation at end of period | 51,734 | 51,279 | 55,855 |
Change in plan assets: | |||
Fair value of plan assets at beginning of period | 0 | 0 | |
Actual return on plan assets | 0 | 0 | |
Employer contribution | 3,061 | 3,535 | |
Benefits paid | (3,061) | (3,535) | |
Defined Benefit Plan, Administration Expenses | 0 | 0 | |
Fair value of plan assets at end of period | 0 | 0 | 0 |
Funded status at end of period | (51,734) | (51,279) | |
Other Benefits | |||
Change in benefit obligation: | |||
Benefit obligation at beginning of period | 13,946 | 15,688 | |
Service cost | 93 | 112 | 112 |
Interest cost | 533 | 621 | 684 |
Actuarial loss (gain) | (2,262) | (1,416) | |
Benefits paid | (1,264) | (1,354) | |
Medicare part D subsidy received | 148 | 295 | |
Defined Benefit Plan, Expected Administration Expenses | 0 | 0 | |
Benefit obligation at end of period | 11,194 | 13,946 | 15,688 |
Change in plan assets: | |||
Fair value of plan assets at beginning of period | 7,203 | 8,360 | |
Actual return on plan assets | 926 | (378) | |
Employer contribution | 335 | 575 | |
Benefits paid | (1,264) | (1,354) | |
Defined Benefit Plan, Administration Expenses | 0 | 0 | |
Fair value of plan assets at end of period | 7,200 | 7,203 | 8,360 |
Funded status at end of period | (3,994) | (6,743) | |
PUGET SOUND ENERGY, INC. | Qualified Pension Benefits | |||
Change in benefit obligation: | |||
Service cost | 18,913 | 21,287 | 17,437 |
Interest cost | 28,689 | 28,088 | 28,039 |
PUGET SOUND ENERGY, INC. | Supplemental Employee Retirement Plan [Member] | |||
Change in benefit obligation: | |||
Service cost | 1,085 | 1,108 | 1,042 |
Interest cost | 2,325 | 2,281 | 2,310 |
PUGET SOUND ENERGY, INC. | Other Benefits | |||
Change in benefit obligation: | |||
Service cost | 93 | 112 | 112 |
Interest cost | 533 | 621 | $ 684 |
Estimate of Fair Value Measurement [Member] | Fair Value, Measurements, Recurring | Qualified Pension Benefits | |||
Change in plan assets: | |||
Fair value of plan assets at beginning of period | 598,865 | ||
Fair value of plan assets at end of period | 621,886 | 598,865 | |
Estimate of Fair Value Measurement [Member] | Fair Value, Measurements, Recurring | Other Benefits | |||
Change in plan assets: | |||
Fair value of plan assets at beginning of period | 7,203 | ||
Fair value of plan assets at end of period | 7,262 | 7,203 | |
Estimate of Fair Value Measurement [Member] | Net Receivables [Member] | Fair Value, Measurements, Recurring | Qualified Pension Benefits | |||
Change in plan assets: | |||
Fair value of plan assets at beginning of period | (7,544) | ||
Fair value of plan assets at end of period | $ (9,894) | $ (7,544) |
Retirement Benefits - Amounts R
Retirement Benefits - Amounts Recognized (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Qualified Pension Benefits | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Benefit Obligation | $ 652,607 | $ 643,088 | $ 690,194 |
Defined Benefit Plan, Accumulated Benefit Obligation | 641,855 | 635,599 | |
Defined Benefit Plan, Fair Value of Plan Assets | 620,260 | 598,865 | 626,173 |
Defined Benefit Plan, Amounts Recognized in Statement of Financial Position Consist of: [Abstract] | |||
Noncurrent assets | 0 | 0 | |
Current liabilities | 0 | 0 | |
Noncurrent liabilities | (32,347) | (44,223) | |
Net assets (liabilities) | (32,347) | (44,223) | |
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: | |||
Net loss (gain) | 11,141 | (6,136) | |
Amortization of net (loss) gain | 0 | (3,887) | |
Amortization of prior service cost (credit) | 1,980 | 1,980 | |
Total change in other comprehensive income for year | 13,121 | (8,043) | |
Supplemental Employee Retirement Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Benefit Obligation | 51,734 | 51,279 | 55,855 |
Defined Benefit Plan, Accumulated Benefit Obligation | 47,639 | 46,978 | |
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | 0 |
Defined Benefit Plan, Amounts Recognized in Statement of Financial Position Consist of: [Abstract] | |||
Noncurrent assets | 0 | 0 | |
Current liabilities | (1,911) | (2,545) | |
Noncurrent liabilities | (49,823) | (48,734) | |
Net assets (liabilities) | (51,734) | (51,279) | |
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: | |||
Net loss (gain) | 106 | (4,430) | |
Amortization of net (loss) gain | (910) | (1,641) | |
Amortization of prior service cost (credit) | (42) | (42) | |
Total change in other comprehensive income for year | (846) | (6,113) | |
Other Benefits | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Benefit Obligation | 11,194 | 13,946 | 15,688 |
Defined Benefit Plan, Accumulated Benefit Obligation | 11,092 | 13,828 | |
Defined Benefit Plan, Fair Value of Plan Assets | 7,200 | 7,203 | $ 8,360 |
Defined Benefit Plan, Amounts Recognized in Statement of Financial Position Consist of: [Abstract] | |||
Noncurrent assets | 0 | 0 | |
Current liabilities | (325) | (353) | |
Noncurrent liabilities | (3,669) | (6,390) | |
Net assets (liabilities) | (3,994) | (6,743) | |
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: | |||
Net loss (gain) | (2,742) | (508) | |
Amortization of net (loss) gain | 385 | 131 | |
Amortization of prior service cost (credit) | 0 | 0 | |
Total change in other comprehensive income for year | (2,357) | (377) | |
Parent Company [Member] | Qualified Pension Benefits | |||
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract] | |||
Net loss (gain) | 56,588 | 45,447 | |
Prior service cost (credit) | (9,822) | (11,802) | |
Total | 46,766 | 33,645 | |
Parent Company [Member] | Supplemental Employee Retirement Plan [Member] | |||
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract] | |||
Net loss (gain) | 9,043 | 9,848 | |
Prior service cost (credit) | 246 | 288 | |
Total | 9,289 | 10,136 | |
Parent Company [Member] | Other Benefits | |||
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract] | |||
Net loss (gain) | (4,190) | (1,834) | |
Prior service cost (credit) | 0 | 0 | |
Total | (4,190) | (1,834) | |
PUGET SOUND ENERGY, INC. | Qualified Pension Benefits | |||
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract] | |||
Net loss (gain) | 217,143 | 221,064 | |
Prior service cost (credit) | (7,806) | (9,379) | |
Total | 209,337 | 211,685 | |
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: | |||
Net loss (gain) | 11,336 | (5,711) | |
Amortization of net (loss) gain | (15,257) | (20,556) | |
Amortization of prior service cost (credit) | 1,573 | 1,573 | |
Total change in other comprehensive income for year | (2,348) | (24,694) | |
PUGET SOUND ENERGY, INC. | Supplemental Employee Retirement Plan [Member] | |||
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract] | |||
Net loss (gain) | 11,978 | 13,202 | |
Prior service cost (credit) | 251 | 295 | |
Total | 12,229 | 13,497 | |
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: | |||
Net loss (gain) | 106 | (4,430) | |
Amortization of net (loss) gain | (1,330) | (2,120) | |
Amortization of prior service cost (credit) | (44) | (44) | |
Total change in other comprehensive income for year | (1,268) | (6,594) | |
PUGET SOUND ENERGY, INC. | Other Benefits | |||
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract] | |||
Net loss (gain) | (5,994) | 3,834 | |
Prior service cost (credit) | 0 | 0 | |
Total | (5,994) | 3,834 | |
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: | |||
Net loss (gain) | (2,742) | (508) | |
Amortization of net (loss) gain | 631 | 407 | |
Amortization of prior service cost (credit) | 0 | (3) | |
Total change in other comprehensive income for year | $ (2,111) | $ (104) |
Retirement Benefits - Net Perio
Retirement Benefits - Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Qualified Pension Benefits | |||
Components of net periodic benefit cost: | |||
Service cost | $ 18,913 | $ 21,287 | $ 17,437 |
Interest cost | 28,689 | 28,088 | 28,039 |
Expected return on plan assets | (46,619) | (45,038) | (42,464) |
Amortization of prior service cost (credit) | (1,980) | (1,980) | (1,980) |
Amortization of net loss (gain) | 0 | 3,887 | 0 |
Net periodic benefit cost | (997) | 6,244 | 1,032 |
Supplemental Employee Retirement Plan [Member] | |||
Components of net periodic benefit cost: | |||
Service cost | 1,085 | 1,108 | 1,042 |
Interest cost | 2,325 | 2,281 | 2,310 |
Expected return on plan assets | 0 | 0 | 0 |
Amortization of prior service cost (credit) | 42 | 42 | 42 |
Amortization of net loss (gain) | 911 | 1,641 | 913 |
Net periodic benefit cost | 4,363 | 5,072 | 4,307 |
Other Benefits | |||
Components of net periodic benefit cost: | |||
Service cost | 93 | 112 | 112 |
Interest cost | 533 | 621 | 684 |
Expected return on plan assets | (446) | (531) | (535) |
Amortization of prior service cost (credit) | 0 | 0 | 0 |
Amortization of net loss (gain) | (386) | (130) | (393) |
Net periodic benefit cost | (206) | 72 | (132) |
PUGET SOUND ENERGY, INC. | Qualified Pension Benefits | |||
Components of net periodic benefit cost: | |||
Service cost | 18,913 | 21,287 | 17,437 |
Interest cost | 28,689 | 28,088 | 28,039 |
Expected return on plan assets | (46,814) | (45,462) | (43,252) |
Amortization of prior service cost (credit) | (1,573) | (1,573) | (1,573) |
Amortization of net loss (gain) | 15,257 | 20,555 | 13,195 |
Net periodic benefit cost | 14,472 | 22,895 | 13,846 |
PUGET SOUND ENERGY, INC. | Supplemental Employee Retirement Plan [Member] | |||
Components of net periodic benefit cost: | |||
Service cost | 1,085 | 1,108 | 1,042 |
Interest cost | 2,325 | 2,281 | 2,310 |
Expected return on plan assets | 0 | 0 | 0 |
Amortization of prior service cost (credit) | 44 | 44 | 44 |
Amortization of net loss (gain) | 1,330 | 2,120 | 1,461 |
Net periodic benefit cost | 4,784 | 5,553 | 4,857 |
PUGET SOUND ENERGY, INC. | Other Benefits | |||
Components of net periodic benefit cost: | |||
Service cost | 93 | 112 | 112 |
Interest cost | 533 | 621 | 684 |
Expected return on plan assets | (446) | (531) | (535) |
Amortization of prior service cost (credit) | 0 | 3 | 3 |
Amortization of net loss (gain) | (632) | (406) | (702) |
Net periodic benefit cost | $ (452) | $ (201) | $ (438) |
Retirement Benefits - Assumptio
Retirement Benefits - Assumptions (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Assumed Health Care Cost Trend Rates | |||
Medical inflation rate assumed for next fiscal year | 8.80% | ||
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates | |||
1% Increase, Effect on post-retirement benefit obligation | $ 38 | $ 52 | |
1% Decrease, Effect on post-retirement benefit obligation | (35) | (42) | |
1% Increase, Effect on service and interest cost components | 2 | 2 | |
1% Decrease, Effect on service and interest cost components | $ (2) | $ (2) | |
defined benefit plan health care cost trend rate assumed for next two years | 4.30% | ||
Qualified Pension Benefits | |||
Benefit Obligation Assumptions | |||
Discount rate | 4.50% | 4.65% | 4.25% |
Rate of compensation increase | 4.50% | 4.50% | 4.50% |
Medical trend rate | 0.00% | 0.00% | 0.00% |
Benefit Cost Assumptions | |||
Discount rate | 4.65% | 4.25% | 5.10% |
Return on plan assets | 7.75% | 7.75% | 7.75% |
Rate of compensation increase | 4.50% | 4.50% | 4.50% |
Medical trend rate | 0.00% | 0.00% | 0.00% |
Supplemental Employee Retirement Plan [Member] | |||
Benefit Obligation Assumptions | |||
Discount rate | 4.50% | 4.65% | 4.25% |
Rate of compensation increase | 4.50% | 4.50% | 4.50% |
Medical trend rate | 0.00% | 0.00% | 0.00% |
Benefit Cost Assumptions | |||
Discount rate | 4.65% | 4.25% | 5.10% |
Return on plan assets | 0.00% | 0.00% | 0.00% |
Rate of compensation increase | 4.50% | 4.50% | 4.50% |
Medical trend rate | 0.00% | 0.00% | 0.00% |
Other Benefits | |||
Benefit Obligation Assumptions | |||
Discount rate | 4.50% | 4.65% | 4.25% |
Rate of compensation increase | 4.50% | 4.50% | 4.50% |
Medical trend rate | 8.80% | 7.20% | 5.70% |
Benefit Cost Assumptions | |||
Discount rate | 4.65% | 4.25% | 5.10% |
Return on plan assets | 6.75% | 7.00% | 7.00% |
Rate of compensation increase | 4.50% | 4.50% | 4.50% |
Medical trend rate | 5.30% | 7.20% | 6.70% |
Retirement Benefits - Future Be
Retirement Benefits - Future Benefit Payments (Details) $ in Thousands | Dec. 31, 2016USD ($) |
Qualified Pension Benefits | |
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
2,016 | $ 41,400 |
2,017 | 42,500 |
2,018 | 43,600 |
2,019 | 44,600 |
2,020 | 45,200 |
2021-2025 | 240,800 |
Supplemental Employee Retirement Plan [Member] | |
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
2,016 | 1,911 |
2,017 | 5,278 |
2,018 | 5,666 |
2,019 | 4,454 |
2,020 | 1,724 |
2021-2025 | 34,043 |
Other Benefits | |
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
2,016 | 928 |
2,017 | 893 |
2,018 | 863 |
2,019 | 829 |
2,020 | 787 |
2021-2025 | 3,873 |
2016, without Medicare Part D subsidy | 1,256 |
2017, without Medicare Part D subsidy | 1,239 |
2018, without Medicare Part D subsidy | 1,216 |
2019, without Medicare Part D subsidy | 1,191 |
2020, without Medicare Part D subsidy | 1,158 |
2021-2025, without Medicare Part D subsidy | $ 5,294 |
Retirement Benefits - Plan Asse
Retirement Benefits - Plan Asset Allocation (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Qualified Pension Benefits | ||||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | $ 620,260 | $ 598,865 | $ 626,173 | |
Domestic Small Cap Equity Investments [Member] | ||||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum | 0.00% | |||
Target Allocation | 9.00% | |||
Target Allocation, Maximum | 15.00% | |||
Foreign Equity Funds [Member] | ||||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum | 10.00% | |||
Target Allocation | 25.00% | |||
Target Allocation, Maximum | 30.00% | |||
Domestic Large Cap Equity Investments [Member] | ||||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum | 25.00% | |||
Target Allocation | 31.00% | |||
Target Allocation, Maximum | 40.00% | |||
Fixed income | ||||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum | 15.00% | |||
Target Allocation | 25.00% | |||
Target Allocation, Maximum | 30.00% | |||
Real estate | ||||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum | 0.00% | |||
Target Allocation | 0.00% | |||
Target Allocation, Maximum | 10.00% | |||
Absolute return | ||||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum | 5.00% | |||
Target Allocation | 10.00% | |||
Target Allocation, Maximum | 15.00% | |||
Cash and cash equivalents | ||||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum | 0.00% | |||
Target Allocation | 0.00% | |||
Target Allocation, Maximum | 5.00% | |||
Fair Value, Measurements, Recurring | Qualified Pension Benefits | Total | ||||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | $ 621,886 | 598,865 | ||
Fair Value, Measurements, Recurring | Equities: | Qualified Pension Benefits | Level 1 | ||||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | 354,221 | 324,321 | ||
Fair Value, Measurements, Recurring | Equities: | Qualified Pension Benefits | Level 2 | ||||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | 54,740 | 58,425 | ||
Fair Value, Measurements, Recurring | Equities: | Qualified Pension Benefits | Total | ||||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | 408,961 | 382,746 | ||
Fair Value, Measurements, Recurring | Fair Value Measurement [Domain] | Qualified Pension Benefits | Total | ||||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | 222,819 | 223,663 | ||
Fair Value, Measurements, Recurring | Mutual Funds | Qualified Pension Benefits | Level 1 | ||||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [1] | 181,212 | 169,165 | |
Fair Value, Measurements, Recurring | Mutual Funds | Qualified Pension Benefits | Level 2 | ||||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [1] | 0 | 0 | |
Fair Value, Measurements, Recurring | Mutual Funds | Qualified Pension Benefits | Total | ||||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [1] | 181,212 | 169,165 | |
Fair Value, Measurements, Recurring | Common Stock | Qualified Pension Benefits | Level 1 | ||||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | 154,255 | 146,321 | ||
Fair Value, Measurements, Recurring | Common Stock | Qualified Pension Benefits | Level 2 | ||||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | ||
Fair Value, Measurements, Recurring | Common Stock | Qualified Pension Benefits | Total | ||||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | 154,255 | 146,321 | ||
Fair Value, Measurements, Recurring | US Treasury and Government [Member] | Qualified Pension Benefits | Level 1 | ||||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | 18,754 | 8,835 | ||
Fair Value, Measurements, Recurring | US Treasury and Government [Member] | Qualified Pension Benefits | Level 2 | ||||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | 16,197 | 14,268 | ||
Fair Value, Measurements, Recurring | US Treasury and Government [Member] | Qualified Pension Benefits | Total | ||||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | 34,951 | 23,103 | ||
Fair Value, Measurements, Recurring | Corporate Bond Securities [Member] | Qualified Pension Benefits | Level 1 | ||||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | ||
Fair Value, Measurements, Recurring | Corporate Bond Securities [Member] | Qualified Pension Benefits | Level 2 | ||||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | 38,543 | 44,157 | ||
Fair Value, Measurements, Recurring | Corporate Bond Securities [Member] | Qualified Pension Benefits | Total | ||||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | $ 38,543 | $ 44,157 | ||
[1] | December 31, 2016. |
Retirement Benefits - Fair Valu
Retirement Benefits - Fair Value Level 3 Rollforward (Details) - Qualified Pension Benefits - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Change in plan assets: | ||
Fair value of plan assets at beginning of period | $ 598,865 | $ 626,173 |
Fair value of plan assets at end of period | $ 620,260 | $ 598,865 |
Retirement Benefits - Textuals
Retirement Benefits - Textuals (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended |
Dec. 31, 2016 | Dec. 31, 2016 | |
PUGET SOUND ENERGY, INC. | ||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Contribution Plan, Employer Matching Contribution, Percent | 1.00% | 4.00% |
PUGET SOUND ENERGY, INC. | Qualified Pension Benefits | ||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year, Net Gain (Loss) | $ (13.7) | |
Pension and Other Postretirement Benefit Plans, Net Prior Service Cost or Credit, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year | (1.6) | |
PUGET SOUND ENERGY, INC. | Supplemental Employee Retirement Plan [Member] | ||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year, Net Gain (Loss) | (1.6) | |
PUGET SOUND ENERGY, INC. | Qualified Pension Benefits | ||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Estimated Future Employer Contributions in Current Fiscal Year | 18 | |
PUGET SOUND ENERGY, INC. | Supplemental Employee Retirement Plan [Member] | ||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Estimated Future Employer Contributions in Current Fiscal Year | 1.9 | |
PUGET SOUND ENERGY, INC. | Other Benefits | ||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Estimated Future Employer Contributions in Current Fiscal Year | $ 0.3 |
Retirement Benefits Accumulated
Retirement Benefits Accumulated Benefit Obligation (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Qualified Pension Benefits | ||||
Defined Contribution Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Benefit Obligation | $ 652,607 | $ 643,088 | $ 690,194 | |
Defined Benefit Plan, Accumulated Benefit Obligation | 641,855 | 635,599 | ||
Defined Benefit Plan, Fair Value of Plan Assets | 620,260 | 598,865 | 626,173 | |
Supplemental Employee Retirement Plan [Member] | ||||
Defined Contribution Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Benefit Obligation | 51,734 | 51,279 | 55,855 | |
Defined Benefit Plan, Accumulated Benefit Obligation | 47,639 | 46,978 | ||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | 0 | |
Other Pension Plan [Member] | ||||
Defined Contribution Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Benefit Obligation | 11,194 | 13,946 | 15,688 | |
Defined Benefit Plan, Accumulated Benefit Obligation | 11,092 | 13,828 | ||
Defined Benefit Plan, Fair Value of Plan Assets | 7,200 | 7,203 | $ 8,360 | |
Fair Value, Measurements, Recurring | Level 1 | Other Pension Plan [Member] | ||||
Defined Contribution Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | 7,182 | 7,135 | ||
Fair Value, Measurements, Recurring | Level 1 | Mutual Funds | Qualified Pension Benefits | ||||
Defined Contribution Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [1] | 181,212 | 169,165 | |
Fair Value, Measurements, Recurring | Level 1 | Mutual Funds | Other Pension Plan [Member] | ||||
Defined Contribution Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [2] | 7,182 | 7,135 | |
Fair Value, Measurements, Recurring | Level 1 | Cash and cash equivalents | Other Pension Plan [Member] | ||||
Defined Contribution Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [3] | 0 | 0 | |
Fair Value, Measurements, Recurring | Estimate of Fair Value Measurement [Member] | Qualified Pension Benefits | ||||
Defined Contribution Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | 621,886 | 598,865 | ||
Fair Value, Measurements, Recurring | Estimate of Fair Value Measurement [Member] | Other Pension Plan [Member] | ||||
Defined Contribution Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | 7,262 | 7,203 | ||
Fair Value, Measurements, Recurring | Estimate of Fair Value Measurement [Member] | Mutual Funds | Qualified Pension Benefits | ||||
Defined Contribution Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [1] | 181,212 | 169,165 | |
Fair Value, Measurements, Recurring | Estimate of Fair Value Measurement [Member] | Mutual Funds | Other Pension Plan [Member] | ||||
Defined Contribution Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [2] | 7,182 | 7,135 | |
Fair Value, Measurements, Recurring | Estimate of Fair Value Measurement [Member] | Cash and cash equivalents | Other Pension Plan [Member] | ||||
Defined Contribution Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [3] | 80 | 68 | |
Fair Value, Measurements, Recurring | Level 2 | Other Pension Plan [Member] | ||||
Defined Contribution Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | 80 | 68 | ||
Fair Value, Measurements, Recurring | Level 2 | Mutual Funds | Qualified Pension Benefits | ||||
Defined Contribution Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [1] | 0 | 0 | |
Fair Value, Measurements, Recurring | Level 2 | Mutual Funds | Other Pension Plan [Member] | ||||
Defined Contribution Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [2] | 0 | 0 | |
Fair Value, Measurements, Recurring | Level 2 | Cash and cash equivalents | Other Pension Plan [Member] | ||||
Defined Contribution Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [3] | $ 80 | $ 68 | |
[1] | December 31, 2016. | |||
[2] | This is a publicly traded balanced mutual fund. The fund seeks regular income, conservation of principal, and an opportunity for long-term growth of principal and income. The fair value is determined by taking the number of shares owned by the plan, and multiplying by the market price as of December 31, 2016. | |||
[3] | The investment consists of a money market fund (at level 1) and a collective trust fund (at level 2). The money market fund is valued at the net asset value per share of $1.00 per unit as of December 31, 2016. The collective trust fund invests primarily in commercial paper, notes, repurchase agreements, and other evidences of indebtedness which are payable on demand or short-term in nature. |
Income Taxes - Components of In
Income Taxes - Components of Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Income Tax Disclosures [Line Items] | |||
Current Federal Tax Expense (Benefit) | $ 0 | $ 0 | $ 0 |
Current State and Local Tax Expense (Benefit) | 20 | 0 | 0 |
Federal | 140,315 | 91,968 | 57,152 |
State | (131) | (192) | (167) |
Total income tax expense | 140,204 | 91,776 | 56,985 |
PUGET SOUND ENERGY, INC. | |||
Income Tax Disclosures [Line Items] | |||
Current Federal Tax Expense (Benefit) | 0 | 0 | 0 |
Current State and Local Tax Expense (Benefit) | 20 | 0 | 0 |
Federal | 175,327 | 125,900 | 89,342 |
State | 0 | 0 | 0 |
Total income tax expense | $ 175,347 | $ 125,900 | $ 89,342 |
Income Taxes - Income Tax Recon
Income Taxes - Income Tax Reconciliation (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Income Tax Disclosures [Line Items] | |||
Federal statutory rate | 35.00% | ||
Income Tax Reconciliation [Abstract] | |||
Income taxes at the statutory rate | $ 158,586 | $ 116,534 | $ 80,087 |
Production tax credit1 | (12,925) | (19,470) | (23,073) |
Utility plant differences | 3,966 | 5,671 | 7,090 |
Income Tax Reconciliation, Treasury Grant | (9,788) | (8,807) | (8,808) |
Other - net | 365 | (2,152) | 1,689 |
Total income tax expense | $ 140,204 | $ 91,776 | $ 56,985 |
Effective tax rate | 30.90% | 27.60% | 24.90% |
PUGET SOUND ENERGY, INC. | |||
Income Tax Reconciliation [Abstract] | |||
Income taxes at the statutory rate | $ 194,572 | $ 150,531 | $ 114,084 |
Production tax credit1 | (12,925) | (19,470) | (23,073) |
Utility plant differences | 3,966 | 5,671 | 7,090 |
Income Tax Reconciliation, Treasury Grant | (9,788) | (8,807) | (8,808) |
Other - net | (478) | (2,025) | 49 |
Total income tax expense | $ 175,347 | $ 125,900 | $ 89,342 |
Effective tax rate | 31.50% | 29.30% | 27.40% |
Income Taxes - Deferred Income
Income Taxes - Deferred Income Taxes (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Deferred Tax Liabilities, Gross | ||
Utility plant and equipment | $ 1,880,782 | $ 1,788,078 |
Regulatory asset for income taxes | 72,038 | 73,231 |
Fair value of debt instruments | 67,444 | 70,260 |
Deferred Tax Liabilities, Pension and Other Compensation | 77,230 | 77,230 |
Other, net deferred tax liabilities | 119,050 | 84,397 |
Subtotal deferred tax liabilities | 2,216,544 | 2,093,196 |
Deferred Tax Assets, Gross | ||
Net operating loss carryforward | (352,827) | (384,338) |
Production tax credit carryforward | (190,999) | (178,075) |
Regulatory liability on production tax credit | (101,787) | (94,828) |
Subtotal deferred tax assets | (645,613) | (657,241) |
Total net deferred tax liabilities | 1,570,931 | 1,435,955 |
PUGET SOUND ENERGY, INC. | ||
Deferred Tax Liabilities, Gross | ||
Utility plant and equipment | 1,880,782 | 1,788,078 |
Regulatory asset for income taxes | 71,517 | 72,694 |
Other, net deferred tax liabilities | 113,938 | 80,351 |
Subtotal deferred tax liabilities | 2,066,237 | 1,941,123 |
Deferred Tax Assets, Gross | ||
Net operating loss carryforward | (41,061) | (111,604) |
Production tax credit carryforward | (190,999) | (178,075) |
Regulatory liability on production tax credit | (101,787) | (94,828) |
Subtotal deferred tax assets | (333,847) | (384,507) |
Total net deferred tax liabilities | $ 1,732,390 | $ 1,556,616 |
Income Taxes - Balance Sheet Lo
Income Taxes - Balance Sheet Location (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Income Tax Disclosures [Line Items] | ||
Non-current deferred taxes | $ 1,570,931 | $ 1,435,955 |
Total net deferred tax liabilities | 1,570,931 | 1,435,955 |
PUGET SOUND ENERGY, INC. | ||
Income Tax Disclosures [Line Items] | ||
Non-current deferred taxes | 1,732,390 | 1,556,616 |
Total net deferred tax liabilities | $ 1,732,390 | $ 1,556,616 |
Litigation (Details)
Litigation (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Loss Contingencies [Line Items] | ||
Regulatory Assets | $ 176.8 | |
Loss Contingency, Estimate of Possible Loss | 3.2 | |
Loss Contingency, Accrual, Current | 3.2 | |
Pending Litigation | ||
Loss Contingencies [Line Items] | ||
Litigation claims accrual | $ 0.7 | $ 0.3 |
Colstrip Unit One and Two | ||
Loss Contingencies [Line Items] | ||
Equity Method Investment, Ownership Percentage | 50.00% | |
Colstrip Unit Three and Four | ||
Loss Contingencies [Line Items] | ||
Equity Method Investment, Ownership Percentage | 25.00% |
Commitments and Contingencies81
Commitments and Contingencies (Details) $ in Thousands, MWh in Millions | 12 Months Ended | ||
Dec. 31, 2016USD ($)MWhContracts$ / kWhMW | Dec. 31, 2015USD ($)MWh | Dec. 31, 2014USD ($)MWh | |
Long-term Purchase Commitment [Line Items] | |||
Long-term Line of Credit, Noncurrent | $ 12,480 | $ 0 | |
Percentage of Company's energy output (percent) | 13.70% | ||
Average cost of Company's energy output (US$ per kWh) | $ / kWh | 0 | ||
Number of Public Utility Districts with long term purchase agreements | Contracts | 3 | ||
Contract expenses | $ 77,667 | $ 72,833 | $ 69,661 |
Megawatt Capacity | MW | 749 | ||
Estimated 2017 Costs | $ 79,427 | ||
2017 Debt Service Costs | 29,348 | ||
Interest included in 2017 Debt Service Costs | 13,985 | ||
Debt Outstanding | 224,828 | ||
Payment Obligations for Power Purchases | |||
2,014 | 282,913 | ||
2,015 | 274,212 | ||
2,016 | 268,137 | ||
2,017 | 271,214 | ||
2,018 | 274,827 | ||
Thereafter | 1,533,294 | ||
Total | $ 2,904,597 | ||
Total energy obtained during period under purchased power contracts (MWh) | MWh | 13 | 11.2 | 12.1 |
Cost incurred during period to provide energy under purchased power contracts | $ 402,500 | $ 373,800 | $ 401,400 |
Daily take obligation under long-term service contract (percent) | 100.00% | ||
Daily delivery obligation under long-term service contract (percent) | 100.00% | ||
Natural Gas Portfolio [Member] | |||
Payment Obligations for Power Purchases | |||
2,014 | $ 320,238 | ||
2,015 | 211,256 | ||
2,016 | 230,109 | ||
2,017 | 177,390 | ||
2,018 | 107,621 | ||
Thereafter | 0 | ||
Total | 1,046,614 | ||
Columbia River projects | |||
Payment Obligations for Power Purchases | |||
2,014 | 73,733 | ||
2,015 | 69,527 | ||
2,016 | 58,921 | ||
2,017 | 59,172 | ||
2,018 | 56,396 | ||
Thereafter | 597,468 | ||
Total | 915,217 | ||
Other utilities | |||
Payment Obligations for Power Purchases | |||
2,014 | 10,499 | ||
2,015 | 1,257 | ||
2,016 | 888 | ||
2,017 | 0 | ||
2,018 | 0 | ||
Thereafter | 0 | ||
Total | 12,644 | ||
Non-utility contracts | |||
Payment Obligations for Power Purchases | |||
2,014 | 198,681 | ||
2,015 | 203,428 | ||
2,016 | 208,328 | ||
2,017 | 212,042 | ||
2,018 | 218,431 | ||
Thereafter | 935,826 | ||
Total | 1,976,736 | ||
Short-term energy supply contracts | |||
Payment Obligations for Power Purchases | |||
2,014 | 45,700 | ||
2,015 | 10,500 | ||
2,016 | 3,900 | ||
Firm transportation service | |||
Payment Obligations for Power Purchases | |||
2,014 | 156,290 | ||
2,015 | 154,155 | ||
2,016 | 149,277 | ||
2,017 | 140,672 | ||
2,018 | 128,049 | ||
Thereafter | 467,266 | ||
Total | 1,195,709 | ||
Firm Storage and Peaking Service [Member] | |||
Payment Obligations for Power Purchases | |||
2,014 | 6,616 | ||
2,015 | 3,861 | ||
2,016 | 2,943 | ||
2,017 | 1,950 | ||
2,018 | 1,619 | ||
Thereafter | 2,475 | ||
Total | 19,464 | ||
Long-term Purchase Commitment, Demand Charges | 120,200 | ||
Firm natural gas supply | |||
Payment Obligations for Power Purchases | |||
2,014 | 483,144 | ||
2,015 | 369,272 | ||
2,016 | 382,329 | ||
2,017 | 320,012 | ||
2,018 | 237,289 | ||
Thereafter | 469,741 | ||
Total | 2,261,787 | ||
Combustion turbines | |||
Payment Obligations for Power Purchases | |||
Long-term Purchase Commitment, Demand Charges | 43,200 | ||
Energy production service contracts | |||
Payment Obligations for Power Purchases | |||
2,014 | 31,573 | ||
2,015 | 31,970 | ||
2,016 | 31,313 | ||
2,017 | 50,656 | ||
2,018 | 32,934 | ||
Thereafter | 204,687 | ||
Total | 383,133 | ||
Automated meter reading system | |||
Payment Obligations for Power Purchases | |||
2,014 | 18,175 | ||
2,015 | 18,693 | ||
2,016 | 18,718 | ||
2,017 | 20,191 | ||
2,018 | 20,939 | ||
Thereafter | 116,811 | ||
Total | 213,527 | ||
Service contract obligations | |||
Payment Obligations for Power Purchases | |||
2,014 | 49,748 | ||
2,015 | 50,663 | ||
2,016 | 50,031 | ||
2,017 | 70,847 | ||
2,018 | 53,873 | ||
Thereafter | 321,498 | ||
Total | $ 596,660 | ||
Minimum | Combustion turbines | |||
Payment Obligations for Power Purchases | |||
Remaining terms under contract | less than one year | ||
Maximum | Combustion turbines | |||
Payment Obligations for Power Purchases | |||
Remaining terms under contract | 28 | ||
Rock Island Project | |||
Long-term Purchase Commitment [Line Items] | |||
Percent of Output | 25.00% | ||
Megawatt Capacity | MW | 156 | ||
Estimated 2017 Costs | $ 28,886 | ||
2017 Debt Service Costs | 10,430 | ||
Interest included in 2017 Debt Service Costs | 5,638 | ||
Debt Outstanding | $ 88,518 | ||
Rocky Reach Project | |||
Long-term Purchase Commitment [Line Items] | |||
Percent of Output | 25.00% | ||
Megawatt Capacity | MW | 325 | ||
Estimated 2017 Costs | $ 28,376 | ||
2017 Debt Service Costs | 7,574 | ||
Interest included in 2017 Debt Service Costs | 2,854 | ||
Debt Outstanding | $ 44,305 | ||
Wells Project | |||
Long-term Purchase Commitment [Line Items] | |||
Percent of Output | 29.90% | ||
Megawatt Capacity | MW | 251 | ||
Estimated 2017 Costs | $ 16,547 | ||
2017 Debt Service Costs | 8,004 | ||
Interest included in 2017 Debt Service Costs | 2,153 | ||
Debt Outstanding | $ 54,847 | ||
Priest Rapids Development | |||
Long-term Purchase Commitment [Line Items] | |||
Percent of Output | 0.60% | ||
Megawatt Capacity | MW | 8 | ||
Estimated 2017 Costs | $ 2,809 | ||
2017 Debt Service Costs | 1,670 | ||
Interest included in 2017 Debt Service Costs | 1,670 | ||
Debt Outstanding | $ 18,579 | ||
Wanapum Development | |||
Long-term Purchase Commitment [Line Items] | |||
Percent of Output | 0.60% | ||
Megawatt Capacity | MW | 9 | ||
Estimated 2017 Costs | $ 2,809 | ||
2017 Debt Service Costs | 1,670 | ||
Interest included in 2017 Debt Service Costs | 1,670 | ||
Debt Outstanding | $ 18,579 |
Related Party Transactions (Det
Related Party Transactions (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Related Party Transaction [Line Items] | ||
Related Party Transaction, Due from (to) Related Party | $ 300 | $ 1,000 |
Affiliated Entity [Member] | ||
Related Party Transaction [Line Items] | ||
Related Party Transaction, Amounts of Transaction | 1,000 | 1,810 |
PUGET SOUND ENERGY, INC. | ||
Related Party Transaction [Line Items] | ||
Related Party Transaction, Amounts of Transaction | $ 23,300 | $ 20,300 |
Segment Information (Details)
Segment Information (Details) | 12 Months Ended |
Dec. 31, 2016mi²segment | |
Segment Reporting Information [Line Items] | |
Number of operating segments | segment | 1 |
PUGET SOUND ENERGY, INC. | |
Segment Reporting Information [Line Items] | |
Area of service territory (sqmi) | mi² | 6,000 |
Accumulated Other Comprehensi84
Accumulated Other Comprehensive Income (Loss) Changes in AOCI, net of tax (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Accumulated other comprehensive income (loss), net of tax | $ (27,266) | ||
Accumulated other comprehensive income (loss), net of tax | (33,712) | $ (27,266) | |
PUGET SOUND ENERGY, INC. | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Accumulated other comprehensive income (loss), net of tax | (149,550) | ||
Accumulated other comprehensive income (loss), net of tax | (145,511) | (149,550) | |
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Accumulated other comprehensive income (loss), net of tax | (27,266) | (36,710) | $ 48,514 |
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax | (5,528) | 7,196 | (84,301) |
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | (918) | 2,248 | (923) |
Other Comprehensive Income (Loss), Net of Tax | (6,446) | 9,444 | (85,224) |
Accumulated other comprehensive income (loss), net of tax | (33,712) | (27,266) | (36,710) |
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | PUGET SOUND ENERGY, INC. | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Accumulated other comprehensive income (loss), net of tax | (143,877) | (164,281) | (87,405) |
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax | (5,655) | 6,922 | (84,955) |
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | 9,377 | 13,482 | 8,079 |
Other Comprehensive Income (Loss), Net of Tax | 3,722 | 20,404 | (76,876) |
Accumulated other comprehensive income (loss), net of tax | (140,155) | (143,877) | (164,281) |
Comprehensive Income [Member] | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Accumulated other comprehensive income (loss), net of tax | (27,266) | (37,043) | 47,715 |
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax | (5,528) | 7,196 | (84,301) |
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | (918) | 2,581 | (457) |
Other Comprehensive Income (Loss), Net of Tax | (6,446) | 9,777 | (84,758) |
Accumulated other comprehensive income (loss), net of tax | (33,712) | (27,266) | (37,043) |
Comprehensive Income [Member] | PUGET SOUND ENERGY, INC. | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Accumulated other comprehensive income (loss), net of tax | (149,550) | (170,957) | (95,739) |
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax | (5,655) | 6,922 | (84,955) |
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | 9,694 | 14,485 | 9,737 |
Other Comprehensive Income (Loss), Net of Tax | 4,039 | 21,407 | (75,218) |
Accumulated other comprehensive income (loss), net of tax | (145,511) | (149,550) | (170,957) |
Energy Related Derivative [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest [Member] | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Accumulated other comprehensive income (loss), net of tax | 0 | (333) | (705) |
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax | 0 | 0 | 0 |
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | 0 | 333 | 372 |
Other Comprehensive Income (Loss), Net of Tax | 0 | 333 | 372 |
Accumulated other comprehensive income (loss), net of tax | 0 | 0 | (333) |
Energy Related Derivative [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest [Member] | PUGET SOUND ENERGY, INC. | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Accumulated other comprehensive income (loss), net of tax | 0 | (686) | (2,027) |
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax | 0 | 0 | 0 |
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | 0 | 686 | 1,341 |
Other Comprehensive Income (Loss), Net of Tax | 0 | 686 | 1,341 |
Accumulated other comprehensive income (loss), net of tax | 0 | 0 | (686) |
Interest Rate Swap [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest [Member] | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Accumulated other comprehensive income (loss), net of tax | 0 | 0 | (94) |
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax | 0 | 0 | 0 |
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | 0 | 0 | 94 |
Other Comprehensive Income (Loss), Net of Tax | 0 | 0 | 94 |
Accumulated other comprehensive income (loss), net of tax | 0 | 0 | 0 |
Interest Rate Swap [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest [Member] | PUGET SOUND ENERGY, INC. | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Accumulated other comprehensive income (loss), net of tax | (5,673) | (5,990) | (6,307) |
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax | 0 | 0 | 0 |
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | 317 | 317 | 317 |
Other Comprehensive Income (Loss), Net of Tax | 317 | 317 | 317 |
Accumulated other comprehensive income (loss), net of tax | $ (5,356) | $ (5,673) | $ (5,990) |
Accumulated Other Comprehensi85
Accumulated Other Comprehensive Income (Loss) Reclassifications Out of Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Reclassification out of Accumulated Other Comprehensive Income [Line Items] | ||||
Reclassification of net unrealized loss on energy derivative instruments during the period, tax | $ 0 | $ (179) | $ (200) | |
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax | 0 | (333) | (372) | |
PUGET SOUND ENERGY, INC. | ||||
Reclassification out of Accumulated Other Comprehensive Income [Line Items] | ||||
Reclassification of net unrealized loss on energy derivative instruments during the period, tax | 0 | (369) | (722) | |
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax | 0 | (686) | (1,341) | |
Reclassification out of Accumulated Other Comprehensive Income | Parent Company [Member] | ||||
Reclassification out of Accumulated Other Comprehensive Income [Line Items] | ||||
Comprehensive income (loss) | 918 | (2,581) | 457 | |
Reclassification out of Accumulated Other Comprehensive Income | PUGET SOUND ENERGY, INC. | ||||
Reclassification out of Accumulated Other Comprehensive Income [Line Items] | ||||
Comprehensive income (loss) | (9,694) | (14,485) | (9,737) | |
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | Parent Company [Member] | ||||
Reclassification out of Accumulated Other Comprehensive Income [Line Items] | ||||
Amortization of prior service cost | [1] | 1,938 | 1,938 | 1,938 |
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, before Tax | [1] | (525) | (5,397) | (519) |
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, before Tax | 1,413 | (3,459) | 1,419 | |
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Tax | (495) | 1,211 | (496) | |
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Net of Tax | 918 | (2,248) | 923 | |
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Noncontrolling Interest [Member] | Energy Related Derivative [Member] | PUGET SOUND ENERGY, INC. | ||||
Reclassification out of Accumulated Other Comprehensive Income [Line Items] | ||||
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax | 0 | (1,055) | (2,063) | |
Reclassification of net unrealized loss on energy derivative instruments during the period, tax | 0 | 369 | 722 | |
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax | 0 | (686) | (1,341) | |
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Noncontrolling Interest [Member] | Interest Rate Swap [Member] | PUGET SOUND ENERGY, INC. | ||||
Reclassification out of Accumulated Other Comprehensive Income [Line Items] | ||||
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax | (488) | (488) | (488) | |
Reclassification of net unrealized loss on energy derivative instruments during the period, tax | 171 | 171 | 171 | |
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax | (317) | (317) | (317) | |
Accumulated Defined Benefit Plans Adjustment Attributable to Noncontrolling Interest [Member] | PUGET SOUND ENERGY, INC. | ||||
Reclassification out of Accumulated Other Comprehensive Income [Line Items] | ||||
Amortization of prior service cost | [2] | 1,529 | 1,526 | 1,526 |
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, before Tax | [2] | (15,955) | (22,268) | (13,954) |
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, before Tax | (14,426) | (20,742) | (12,428) | |
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Tax | 5,049 | 7,260 | 4,349 | |
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Net of Tax | (9,377) | (13,482) | (8,079) | |
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | Energy Related Derivative [Member] | Parent Company [Member] | ||||
Reclassification out of Accumulated Other Comprehensive Income [Line Items] | ||||
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax | 0 | (512) | (572) | |
Reclassification of net unrealized loss on energy derivative instruments during the period, tax | 0 | 179 | 200 | |
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax | 0 | (333) | (372) | |
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | Interest Rate Swap [Member] | Parent Company [Member] | ||||
Reclassification out of Accumulated Other Comprehensive Income [Line Items] | ||||
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax | 0 | 0 | (144) | |
Reclassification of net unrealized loss on energy derivative instruments during the period, tax | 0 | 0 | 50 | |
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax | $ 0 | $ 0 | $ (94) | |
[1] | These AOCI components are included in the computation of net periodic pension cost (see Note 12, "Retirement Benefits" for additional details). | |||
[2] | These AOCI components are included in the computation of net periodic pension cost (see Note 12, "Retirement Benefits" for additional details). |
SUPPLEMENTAL QUARTERLY FINANCIA
SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Quarterly Financial Information [Line Items] | |||||||||||
Operating revenues | $ 3,164,301 | $ 3,092,700 | $ 3,113,171 | ||||||||
Operating income | 785,384 | 671,925 | 577,851 | ||||||||
Net income (loss) | 312,899 | 241,179 | 171,835 | ||||||||
Parent Company [Member] | |||||||||||
Quarterly Financial Information [Line Items] | |||||||||||
Operating revenues | $ 915,157 | $ 618,278 | $ 668,169 | $ 962,697 | $ 901,791 | $ 605,733 | $ 658,341 | $ 926,835 | |||
Operating income | 236,854 | 88,072 | 175,634 | 284,824 | 230,030 | 69,888 | 126,772 | 245,235 | |||
Net income (loss) | 104,825 | 2,335 | 64,553 | 141,186 | 107,815 | (7,928) | 25,616 | 115,676 | 312,899 | 241,179 | 171,835 |
PUGET SOUND ENERGY, INC. | |||||||||||
Quarterly Financial Information [Line Items] | |||||||||||
Operating revenues | 915,158 | 618,594 | 668,169 | 962,697 | 902,161 | 605,913 | 658,341 | 926,843 | 3,164,618 | 3,093,258 | 3,116,123 |
Operating income | 237,101 | 84,476 | 171,991 | 281,425 | 226,446 | 66,036 | 122,753 | 240,903 | 774,993 | 656,138 | 568,693 |
Net income (loss) | $ 124,199 | $ 18,977 | $ 80,900 | $ 156,505 | $ 122,514 | $ 9,876 | $ 42,699 | $ 129,100 | $ 380,581 | $ 304,189 | $ 236,614 |
SCHEDULE I CONDENSED FINANCIA87
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY - Condensed Statements of Income (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Condensed Financial Statements, Captions [Line Items] | |||||||||||
Non-utility expense and other | $ (27,151) | $ (10,818) | $ (13,109) | ||||||||
Non-hedged interest rate swap expense | (1,062) | (3,796) | (3,915) | ||||||||
Interest expense | (355,139) | (356,696) | (367,308) | ||||||||
Income taxes | (140,204) | (91,776) | (56,985) | ||||||||
Net income (loss) | 312,899 | 241,179 | 171,835 | ||||||||
Comprehensive income (loss) | 306,453 | 250,956 | 87,077 | ||||||||
Parent Company [Member] | |||||||||||
Condensed Financial Statements, Captions [Line Items] | |||||||||||
Non-utility expense and other | (5,252) | (1,617) | (5,390) | ||||||||
Equity In Net Income (Loss) Of Subsidiaries | 385,838 | 309,603 | 240,102 | ||||||||
Non-hedged interest rate swap expense | (1,062) | (3,796) | (3,915) | ||||||||
Interest income | 2 | 63 | 185 | ||||||||
Interest expense | (104,600) | (100,114) | (93,382) | ||||||||
Income taxes | 37,973 | 37,040 | 34,235 | ||||||||
Net income (loss) | $ 104,825 | $ 2,335 | $ 64,553 | $ 141,186 | $ 107,815 | $ (7,928) | $ 25,616 | $ 115,676 | 312,899 | 241,179 | 171,835 |
Comprehensive income (loss) | $ 306,453 | $ 250,956 | $ 87,077 |
SCHEDULE I CONDENSED FINANCIA88
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY - Condensed Balance Sheets (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Feb. 06, 2009 | |
Other property and investments: | ||||||
Goodwill | $ 1,656,513 | $ 1,656,513 | $ 1,700,000 | |||
Current assets: | ||||||
Cash and Cash Equivalents, at Carrying Value | 28,878 | 42,494 | $ 37,527 | $ 44,302 | ||
Total current assets | 902,868 | 807,579 | ||||
Long-term assets: | ||||||
Other | 58,109 | 58,513 | ||||
Total assets | 13,266,380 | 12,814,254 | ||||
Capitalization and liabilities: | ||||||
Common equity | 3,688,713 | 3,531,225 | 3,543,328 | 3,679,679 | ||
Long-term debt | 1,812,480 | 1,800,000 | ||||
Total capitalization | 9,040,374 | 8,858,743 | ||||
Current liabilities: | ||||||
Accounts payable | 317,043 | 259,353 | ||||
Interest | 73,610 | 73,378 | ||||
Deferred income taxes | 1,570,931 | 1,435,955 | ||||
Unrealized loss on derivative instruments | 44,310 | 136,173 | ||||
Total current liabilities | 919,470 | 851,286 | ||||
Long-term liabilities: | ||||||
Unrealized loss on derivative instruments | 16,261 | 48,073 | ||||
Total capitalization and liabilities | 13,266,380 | 12,814,254 | ||||
Parent Company [Member] | ||||||
Assets: | ||||||
Investments in subsidiaries | 3,571,550 | 3,415,571 | ||||
Other property and investments: | ||||||
Goodwill | 1,656,513 | 1,656,513 | ||||
Current assets: | ||||||
Cash and Cash Equivalents, at Carrying Value | 397 | 639 | $ 62 | $ 191 | ||
Receivables from affiliates | [1] | 213 | 203 | |||
Total current assets | 610 | 842 | ||||
Long-term assets: | ||||||
Deferred income taxes | 309,812 | 272,487 | ||||
Other | 521 | 537 | ||||
Total long-term assets | 310,333 | 273,024 | ||||
Total assets | 5,539,006 | 5,345,950 | ||||
Capitalization and liabilities: | ||||||
Common equity | 3,688,713 | 3,531,225 | ||||
Long-term debt | 1,808,828 | 1,783,898 | ||||
Total capitalization | 5,497,541 | 5,315,123 | ||||
Current liabilities: | ||||||
Accounts payable | 15,801 | 171 | ||||
Interest | 25,523 | 25,606 | ||||
Unrealized loss on derivative instruments | 141 | 4,753 | ||||
Total current liabilities | 41,465 | 30,530 | ||||
Long-term liabilities: | ||||||
Unrealized loss on derivative instruments | 0 | 297 | ||||
Total long-term liabilities | 0 | 297 | ||||
Total capitalization and liabilities | $ 5,539,006 | $ 5,345,950 | ||||
[1] | Eliminated in consolidation. |
SCHEDULE I CONDENSED FINANCIA89
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY - Condensed Statements of Cash Flows (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Adjustments to reconcile net income to net cash provided by (used in) operating activities: | |||
Net cash provided by (used in) operating activities | $ 729,290 | $ 648,722 | $ 701,782 |
Investing activities: | |||
Other | (1,921) | 754 | (4,512) |
Net cash provided by (used in) investing activities | (712,834) | (561,557) | (395,162) |
Financing activities: | |||
Dividends paid | (148,965) | (263,059) | (223,428) |
Proceeds from long-term debt and bonds issued | 12,481 | 825,000 | 299,000 |
Issuance/redemption of term-loan and other long-term debt | 0 | (711,000) | (299,000) |
Net cash provided by (used in) financing activities | (30,072) | (82,198) | (313,395) |
Net increase (decrease) in cash and cash equivalents | (13,616) | 4,967 | (6,775) |
Cash and cash equivalents at beginning of period | 42,494 | 37,527 | 44,302 |
Cash and cash equivalents at end of period | 28,878 | 42,494 | 37,527 |
Parent Company [Member] | |||
Adjustments to reconcile net income to net cash provided by (used in) operating activities: | |||
Net cash provided by (used in) operating activities | 145,719 | 171,576 | 225,459 |
Investing activities: | |||
Adjustments to Additional Paid in Capital, Other | 0 | (28,900) | 0 |
(Increase) decrease in loan to subsidiary | 0 | 28,933 | 665 |
Other | (6,078) | (5,632) | (2,829) |
Net cash provided by (used in) investing activities | (6,078) | (5,599) | (2,164) |
Financing activities: | |||
Dividends paid | (148,965) | (263,059) | (223,428) |
Proceeds from long-term debt and bonds issued | 0 | 400,000 | 0 |
Issuance/redemption of term-loan and other long-term debt | 12,480 | (299,000) | 0 |
Issue costs and others | (3,398) | (3,341) | 4 |
Net cash provided by (used in) financing activities | (139,883) | (165,400) | (223,424) |
Net increase (decrease) in cash and cash equivalents | (242) | 577 | (129) |
Cash and cash equivalents at beginning of period | 639 | 62 | 191 |
Cash and cash equivalents at end of period | $ 397 | $ 639 | $ 62 |
SCHEDULE I CONDENSED FINANCIA90
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY Notes (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Net income | $ 312,899 | $ 241,179 | $ 171,835 | ||||||||
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | 306,453 | 250,956 | 87,077 | ||||||||
Net Cash Provided by (Used in) Operating Activities | 729,290 | 648,722 | 701,782 | ||||||||
Net Cash Provided by (Used in) Investing Activities | (712,834) | (561,557) | (395,162) | ||||||||
Parent Company [Member] | |||||||||||
Net income | $ 104,825 | $ 2,335 | $ 64,553 | $ 141,186 | $ 107,815 | $ (7,928) | $ 25,616 | $ 115,676 | 312,899 | 241,179 | 171,835 |
Goodwill, Purchase Accounting Adjustments | 5,200 | 5,400 | 3,500 | ||||||||
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | 306,453 | 250,956 | 87,077 | ||||||||
Net Cash Provided by (Used in) Operating Activities | 145,719 | 171,576 | 225,459 | ||||||||
Net Cash Provided by (Used in) Investing Activities | (6,078) | (5,599) | (2,164) | ||||||||
PUGET SOUND ENERGY, INC. | |||||||||||
Net income | $ 124,199 | $ 18,977 | $ 80,900 | $ 156,505 | $ 122,514 | $ 9,876 | $ 42,699 | $ 129,100 | 380,581 | 304,189 | 236,614 |
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | 384,620 | 325,596 | 161,396 | ||||||||
Net Cash Provided by (Used in) Operating Activities | 818,916 | 738,781 | 782,727 | ||||||||
Net Cash Provided by (Used in) Investing Activities | $ (681,425) | $ (555,925) | $ (392,333) |
SCHEDULE II VALUATION AND QUA91
SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Details) - Allowance for doubtful accounts receivable - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Movement in Valuation Allowances and Reserves [Roll Forward] | |||
Balance At Beginning of Period | $ 9,756 | $ 7,472 | $ 7,385 |
Additions Charged to Costs and Expenses | 24,389 | 20,732 | 27,228 |
Deductions | 24,347 | 18,448 | 27,141 |
Balance At End Of Period | $ 9,798 | $ 9,756 | $ 7,472 |