Document And Entity Information
Document And Entity Information | 3 Months Ended |
Mar. 31, 2018shares | |
Entity Information [Line Items] | |
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 Common Stock, Shares Outstanding | 200 |
Document Fiscal Year Focus | 2,018 |
Document Fiscal Period Focus | Q1 |
Document Type | 10-Q |
Amendment Flag | false |
Document Period End Date | Mar. 31, 2018 |
Subsidiaries [Member] | |
Entity Information [Line Items] | |
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 Common Stock, Shares Outstanding | 85,903,791 |
Document Fiscal Year Focus | 2,018 |
Document Fiscal Period Focus | Q1 |
Document Type | 10-Q |
Amendment Flag | false |
Document Period End Date | Mar. 31, 2018 |
CONSOLIDATED STATEMENTS OF INCO
CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Operating revenue: | ||
Electric | $ 699,686 | $ 668,984 |
Natural gas | 330,284 | 400,065 |
Other | 8,038 | 8,183 |
Total operating revenue | 1,038,008 | 1,077,232 |
Energy costs: | ||
Purchased electricity | 154,206 | 179,582 |
Electric generation fuel | 42,423 | 51,310 |
Residential exchange | (23,943) | (23,447) |
Purchased natural gas | 127,615 | 152,801 |
Unrealized (gain) loss on derivative instruments, net | (996) | 19,288 |
Utility operations and maintenance | 160,524 | 152,030 |
Non-utility expense and other | 12,830 | 5,195 |
Depreciation and amortization | 184,512 | 115,253 |
Conservation amortization | 36,864 | 34,761 |
Taxes other than income taxes | 111,188 | 118,732 |
Total operating expenses | 805,223 | 805,505 |
Operating income (loss) | 232,785 | 271,727 |
Other income (expense): | ||
Other income | 13,455 | 5,959 |
Other expense | (2,098) | (1,215) |
Non-hedged interest rate swap (expense) income | 0 | 28 |
Interest charges: | ||
AFUDC | 2,884 | 2,176 |
Interest expense | (88,326) | (88,582) |
Income (loss) before income taxes | 158,700 | 190,093 |
Income tax (benefit) expense | 11,803 | 62,543 |
Net income (loss) | 146,897 | 127,550 |
Subsidiaries [Member] | ||
Operating revenue: | ||
Electric | 699,686 | 668,984 |
Natural gas | 330,284 | 400,065 |
Other | 8,038 | 8,183 |
Total operating revenue | 1,038,008 | 1,077,232 |
Energy costs: | ||
Purchased electricity | 154,206 | 179,582 |
Electric generation fuel | 42,423 | 51,310 |
Residential exchange | (23,943) | (23,447) |
Purchased natural gas | 127,615 | 152,801 |
Unrealized (gain) loss on derivative instruments, net | (996) | 19,288 |
Utility operations and maintenance | 160,524 | 152,030 |
Non-utility expense and other | 9,781 | 8,491 |
Depreciation and amortization | 184,490 | 115,253 |
Conservation amortization | 36,864 | 34,761 |
Taxes other than income taxes | 111,188 | 118,732 |
Total operating expenses | 802,152 | 808,801 |
Operating income (loss) | 235,856 | 268,431 |
Other income (expense): | ||
Other income | 7,641 | 5,959 |
Other expense | (2,098) | (1,215) |
Interest charges: | ||
AFUDC | 2,884 | 2,176 |
Interest expense | (59,555) | (60,461) |
Income (loss) before income taxes | 184,728 | 214,890 |
Income tax (benefit) expense | 21,691 | 71,798 |
Net income (loss) | $ 163,037 | $ 143,092 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Parent [Line Items] | ||
Net income (loss) | $ 146,897 | $ 127,550 |
Other comprehensive income (loss): | ||
Net unrealized gain (loss) from pension and postretirement plans, net of tax | 227 | 880 |
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings | (5,230) | 0 |
Other comprehensive income (loss) | (5,003) | 880 |
Comprehensive income (loss) | 141,894 | 128,430 |
Subsidiaries [Member] | ||
Parent [Line Items] | ||
Net income (loss) | 163,037 | 143,092 |
Other comprehensive income (loss): | ||
Net unrealized gain (loss) from pension and postretirement plans, net of tax | 2,863 | 3,216 |
Amortization of treasury interest rate swaps to earnings, net of tax | 96 | 79 |
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings | (27,333) | 0 |
Other comprehensive income (loss) | (24,374) | 3,295 |
Comprehensive income (loss) | $ 138,663 | $ 146,387 |
CONSOLIDATED STATEMENTS OF COM4
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Net unrealized gain (loss) from pension and postretirement plans, net of tax | $ 60 | $ 474 |
Subsidiaries [Member] | ||
Net unrealized gain (loss) from pension and postretirement plans, net of tax | 761 | 1,732 |
Amortization of treasury interest rate swaps to earnings, net of tax | $ 26 | $ 43 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 |
Utility plant (at original cost, including construction work in progress of $575,180 and $495,937, respectively): | ||
Electric plant | $ 8,220,325 | $ 8,135,847 |
Natural gas plant | 3,375,064 | 3,307,545 |
Common plant | 861,481 | 811,815 |
Less: Accumulated depreciation and amortization | (2,537,651) | (2,428,524) |
Net utility plant | 9,919,219 | 9,826,683 |
Other property and investments: | ||
Goodwill | 1,656,513 | 1,656,513 |
Other property and investments | 202,830 | 182,355 |
Total other property and investments | 1,859,343 | 1,838,868 |
Current assets: | ||
Cash and cash equivalents | 12,056 | 26,616 |
Restricted cash | 13,747 | 10,145 |
Accounts receivable, net of allowance for doubtful accounts | 338,405 | 341,110 |
Unbilled revenue | 173,845 | 222,186 |
Materials and supplies, at average cost | 108,828 | 107,003 |
Fuel and gas inventory, at average cost | 34,365 | 49,908 |
Unrealized gain on derivative instruments | 23,718 | 22,247 |
Prepaid expense and other | 23,499 | 21,996 |
Power contract acquisition adjustment gain | 6,436 | 12,207 |
Total current assets | 734,899 | 813,418 |
Other long-term and regulatory assets: | ||
Power cost adjustment mechanism | 4,612 | 4,576 |
Regulatory assets related to power contracts | 18,956 | 19,454 |
Other regulatory assets | 852,328 | 948,532 |
Derivative Asset, Noncurrent | 3,443 | 2,158 |
Power contract acquisition adjustment gain | 161,517 | 162,711 |
Other | 77,656 | 74,389 |
Total other long-term and regulatory assets | 1,118,512 | 1,211,820 |
Total assets | 13,631,973 | 13,690,789 |
Capitalization: | ||
Common stock | 0 | 0 |
Additional paid-in capital | 3,308,957 | 3,308,957 |
Earnings reinvested in the business | 587,385 | 465,355 |
Accumulated other comprehensive income (loss), net of tax | (29,285) | (24,282) |
Total common shareholder's equity | 3,867,057 | 3,750,030 |
Long-term debt: | ||
First mortgage bonds and senior notes | 3,164,412 | 3,164,412 |
Pollution control bonds | 161,860 | 161,860 |
Junior subordinated notes | 56,553 | 250,000 |
Long-term debt | 1,915,779 | 1,902,600 |
Debt discount, issuance costs and other | (217,935) | (220,943) |
Total long-term debt | 5,080,669 | 5,257,929 |
Total capitalization | 8,947,726 | 9,007,959 |
Current liabilities: | ||
Accounts payable | 319,927 | 359,586 |
Short-term debt | 370,689 | 329,463 |
Current maturities of long-term debt | 200,000 | 200,000 |
Purchased gas adjustment liability | 33,663 | 16,051 |
Accrued expenses: | ||
Taxes | 137,562 | 117,948 |
Salaries and wages | 32,355 | 53,220 |
Interest | 73,817 | 73,564 |
Unrealized loss on derivative instruments | 67,513 | 64,859 |
Power contract acquisition adjustment loss | 2,687 | 2,762 |
Other | 104,095 | 80,206 |
Total current liabilities | 1,342,308 | 1,297,659 |
Long-term and regulatory liabilities: | ||
Deferred income taxes | 770,417 | 746,868 |
Unrealized loss on derivative instruments | 16,567 | 21,235 |
Regulatory liabilities | 734,526 | 731,587 |
Regulatory liability for deferred income taxes | 1,002,654 | 1,011,626 |
Regulatory liabilities related to power contracts | 167,953 | 174,918 |
Power contract acquisition adjustment loss | 16,267 | 16,693 |
Other deferred credits | 633,555 | 682,244 |
Total long-term and regulatory liabilities | 3,341,939 | 3,385,171 |
Commitments and contingencies (Note 8) | ||
Total capitalization and liabilities | 13,631,973 | 13,690,789 |
Subsidiaries [Member] | ||
Utility plant (at original cost, including construction work in progress of $575,180 and $495,937, respectively): | ||
Electric plant | 10,308,382 | 10,232,771 |
Natural gas plant | 3,949,052 | 3,882,733 |
Common plant | 892,642 | 843,145 |
Less: Accumulated depreciation and amortization | (5,230,857) | (5,131,966) |
Net utility plant | 9,919,219 | 9,826,683 |
Other property and investments: | ||
Other property and investments | 76,576 | 76,350 |
Total other property and investments | 76,576 | 76,350 |
Current assets: | ||
Cash and cash equivalents | 11,226 | 25,864 |
Restricted cash | 13,747 | 10,145 |
Accounts receivable, net of allowance for doubtful accounts | 348,759 | 343,546 |
Unbilled revenue | 173,845 | 222,186 |
Materials and supplies, at average cost | 108,828 | 107,003 |
Fuel and gas inventory, at average cost | 33,042 | 48,585 |
Unrealized gain on derivative instruments | 23,718 | 22,247 |
Prepaid expense and other | 23,499 | 21,996 |
Total current assets | 736,664 | 801,572 |
Other long-term and regulatory assets: | ||
Power cost adjustment mechanism | 4,612 | 4,576 |
Other regulatory assets | 852,328 | 948,540 |
Derivative Asset, Noncurrent | 3,443 | 2,158 |
Other | 75,227 | 71,827 |
Total other long-term and regulatory assets | 935,610 | 1,027,101 |
Total assets | 11,668,069 | 11,731,706 |
Capitalization: | ||
Common stock | 859 | 859 |
Additional paid-in capital | 3,275,105 | 3,275,105 |
Earnings reinvested in the business | 583,824 | 452,066 |
Accumulated other comprehensive income (loss), net of tax | (151,280) | (126,906) |
Total common shareholder's equity | 3,708,508 | 3,601,124 |
Long-term debt: | ||
First mortgage bonds and senior notes | 3,164,412 | 3,164,412 |
Pollution control bonds | 161,860 | 161,860 |
Junior subordinated notes | 56,553 | 250,000 |
Debt discount, issuance costs and other | (25,941) | (26,361) |
Total long-term debt | 3,356,884 | 3,549,911 |
Total capitalization | 7,065,392 | 7,151,035 |
Current liabilities: | ||
Accounts payable | 319,927 | 359,585 |
Short-term debt | 370,689 | 329,463 |
Current maturities of long-term debt | 200,000 | 200,000 |
Purchased gas adjustment liability | 33,663 | 16,051 |
Accrued expenses: | ||
Taxes | 141,578 | 117,063 |
Salaries and wages | 32,355 | 53,220 |
Interest | 50,806 | 47,837 |
Unrealized loss on derivative instruments | 67,513 | 64,859 |
Other | 104,095 | 80,206 |
Total current liabilities | 1,320,626 | 1,268,284 |
Long-term and regulatory liabilities: | ||
Deferred income taxes | 898,746 | 869,473 |
Unrealized loss on derivative instruments | 16,567 | 21,235 |
Regulatory liabilities | 733,203 | 730,273 |
Regulatory liability for deferred income taxes | 1,003,278 | 1,012,260 |
Other deferred credits | 630,257 | 679,146 |
Total long-term and regulatory liabilities | 3,282,051 | 3,312,387 |
Commitments and contingencies (Note 8) | ||
Total capitalization and liabilities | $ 11,668,069 | $ 11,731,706 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 |
ASSETS | ||
Construction work in progress | $ 575,180 | $ 495,937 |
Current assets: | ||
Allowance for doubtful accounts | $ 9,997 | $ 8,901 |
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 |
Subsidiaries [Member] | ||
ASSETS | ||
Construction work in progress | $ 575,180 | $ 495,937 |
Current assets: | ||
Allowance for doubtful accounts | $ 9,997 | $ 8,901 |
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 CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Operating activities: | ||
Net income (loss) | $ 146,897 | $ 127,550 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||
Depreciation and amortization | 184,512 | 115,253 |
Conservation amortization | 36,864 | 34,761 |
Deferred income taxes and tax credits, net | 14,517 | 55,957 |
Net unrealized (gain) loss on derivative instruments | (996) | 19,147 |
AFUDC – equity | (3,351) | (2,928) |
Monetized production tax credits | (43,586) | 0 |
Adjustments, Noncash Items, to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities | 3,720 | 4,214 |
Funding of pension liability | (4,500) | (9,000) |
Regulatory Assets | 20,871 | (2,073) |
Other long-term assets and liabilities | (13,160) | 13,543 |
Change in certain current assets and liabilities: | ||
Accounts receivable and unbilled revenue | 49,476 | 52,860 |
Materials and supplies | (1,825) | 3,304 |
Fuel and gas inventory | 15,543 | 19,346 |
Prepayments and other | (1,503) | (4,354) |
Purchased gas adjustment | 17,612 | 13,375 |
Accounts payable | (27,973) | (41,451) |
Taxes payable | 19,614 | 29,374 |
Other | (13,411) | (677) |
Net cash provided by (used in) operating activities | 399,321 | 428,201 |
Investing activities: | ||
Construction expenditures - excluding equity AFUDC | (241,181) | (223,635) |
Other | 1,570 | (3,804) |
Net cash provided by (used in) investing activities | (239,611) | (227,439) |
Financing activities: | ||
Change in short-term debt, net | 41,226 | (230,763) |
Dividends paid | (30,096) | (8) |
Proceeds from long-term debt and bonds issued | 13,179 | 10,663 |
Redemption of bonds and notes | (193,447) | 0 |
Other | (1,530) | 4,605 |
Net cash provided by (used in) financing activities | (170,668) | (215,503) |
Net increase (decrease) in cash and cash equivalents | (10,958) | (14,741) |
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Beginning of Period | 36,761 | 41,296 |
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, End of Period | 25,803 | 26,555 |
Supplemental cash flow information: | ||
Cash payments for interest (net of capitalized interest) | 81,736 | 76,644 |
Cash payments (refunds) for income taxes | 0 | 0 |
Accounts payable for capital expenditures eliminated from cash flows | 90,169 | 45,945 |
Subsidiaries [Member] | ||
Operating activities: | ||
Net income (loss) | 163,037 | 143,092 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||
Depreciation and amortization | 184,490 | 115,253 |
Conservation amortization | 36,864 | 34,761 |
Deferred income taxes and tax credits, net | 19,505 | 65,212 |
Net unrealized (gain) loss on derivative instruments | (996) | 19,288 |
AFUDC – equity | (3,351) | (2,928) |
Monetized production tax credits | (43,586) | 0 |
Adjustments, Noncash Items, to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities | 1,131 | 1,410 |
Funding of pension liability | (4,500) | (9,000) |
Regulatory Assets | 20,871 | (2,073) |
Other long-term assets and liabilities | (9,844) | (8,088) |
Change in certain current assets and liabilities: | ||
Accounts receivable and unbilled revenue | 41,558 | 44,630 |
Materials and supplies | (1,825) | 3,304 |
Fuel and gas inventory | 15,543 | 19,346 |
Prepayments and other | (1,503) | (4,354) |
Purchased gas adjustment | 17,612 | 13,375 |
Accounts payable | (27,973) | (41,451) |
Taxes payable | 24,515 | 29,374 |
Other | (10,694) | 1,515 |
Net cash provided by (used in) operating activities | 420,854 | 422,666 |
Investing activities: | ||
Construction expenditures - excluding equity AFUDC | (221,099) | (179,622) |
Other | 1,570 | (3,367) |
Net cash provided by (used in) investing activities | (219,529) | (182,989) |
Financing activities: | ||
Change in short-term debt, net | 41,226 | (230,763) |
Dividends paid | (58,611) | (28,712) |
Redemption of bonds and notes | (193,447) | 0 |
Other | (1,529) | 4,635 |
Net cash provided by (used in) financing activities | (212,361) | (254,840) |
Net increase (decrease) in cash and cash equivalents | (11,036) | (15,163) |
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Beginning of Period | 36,009 | 40,899 |
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, End of Period | 24,973 | 25,736 |
Supplemental cash flow information: | ||
Cash payments for interest (net of capitalized interest) | 52,847 | 48,989 |
Cash payments (refunds) for income taxes | 0 | 0 |
Accounts payable for capital expenditures eliminated from cash flows | $ 90,169 | $ 45,945 |
Summary of Consolidation Policy
Summary of Consolidation Policy | 3 Months Ended |
Mar. 31, 2018 | |
Accounting Policies [Abstract] | |
Summary of Consolidation Policy | Basis of Presentation Puget Energy is an energy services holding company that owns Puget Sound Energy (PSE). PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering approximately 6,000 square miles, primarily in the Puget Sound region. Puget Energy also has a wholly-owned non-regulated subsidiary, Puget LNG, LLC (Puget LNG), which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma LNG facility, currently under construction. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that occur under PSE and are allocated to Puget LNG are related party transactions by nature. As of March 31, 2018 , Puget LNG has incurred $124.4 million in construction work in progress and operating costs related to Puget LNG’s portion of the Tacoma LNG facility. The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries. PSE’s consolidated financial statements include the accounts of PSE and its subsidiary. Puget Energy and PSE are collectively referred to herein as “the Company”. The consolidated financial statements are presented after elimination of all significant intercompany items and transactions. PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any Accounting Standards Codification (ASC) 805, “Business Combinations” (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. Tacoma LNG Facility The Tacoma LNG facility is intended to provide peak-shaving services to PSE’s natural gas customers. By storing surplus natural gas, PSE is able to meet the requirements of peak consumption later during different seasons. LNG will also provide fuel to transportation customers, particularly in the marine market. On January 24, 2018, the Puget Sound Clean Air Agency determined a Supplemental Environmental Impact Statement is necessary in order to rule on the air quality permit for the facility. As a result of requiring a Supplemental Environmental Impact Statement, the Company's construction schedule may be impacted depending on the Puget Sound Clean Air Agency's timing and decision on the air quality permit. If delayed, the construction schedule and costs may be adversely impacted. Pursuant to an order by the Washington Commission, PSE will be allocated approximately 43.0% of common capital and operating costs, consistent with the regulated portion of the Tacoma LNG facility. The remaining 57.0% of common capital and operating costs of the Tacoma LNG facility will be allocated to Puget LNG. For Puget Energy, $124.3 million in construction work in progress related to Puget LNG’s portion of the Tacoma LNG facility is reported in the “Other property and investments” financial statement line item. For PSE, construction work in progress of $102.6 million related to PSE’s portion of the Tacoma LNG facility is reported in the “Utility plant - Natural gas plant” line item, as PSE is a regulated entity. |
New Accounting Pronouncements
New Accounting Pronouncements | 3 Months Ended |
Mar. 31, 2018 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
New Accounting Pronouncements | New Accounting Pronouncements Recently Adopted Accounting Guidance Income Taxes In March 2018, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2018-05, "Income Taxes (Topic 740): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118" . The staff of the U.S. Securities and Exchange Commission (SEC) recognized the complexity of reflecting the impacts of the Tax Cuts Job Act (TCJA), and on December 22, 2017 issued guidance in Staff Accounting Bulletin 118 (SAB 118), which clarifies accounting for income taxes under Accounting Standards Codification (ASC) 740 if information is not yet available or complete and provides for up to a one year period in which to complete the required analysis and accounting (the measurement period). SAB 118 describes three scenarios (or “buckets”) associated with a company’s status of accounting for income tax reform: (i) a company is complete with its accounting for certain effects of tax reform, (ii) a company is able to determine a reasonable estimate for certain effects of tax reform and records that estimate as a provisional amount, or (iii) a company is not able to determine a reasonable estimate and therefore continues to apply ASC 740, based on the provisions of the tax laws that were in effect immediately prior to the TCJA being enacted. The Company has completed the required analysis and accounting for substantially all the effects of the TCJA's enactment and has made a reasonable estimate as to the other effects and has reflected the measurement and accounting of the effects in the consolidated financial statements. The items reflected as provisional amounts include tax depreciation and amortization and other book to tax differences. The Company has accounted for these items based on its interpretation of the TCJA. Further interpretive guidance on the TCJA from the IRS, U.S. Treasury Department, or the Joint Committee on Taxation may require adjustments to the Company's accounting. In accordance with SAB 118, adjustments, if any, will be recorded in 2018. At December 31, 2017 , the Company did not identify any effects of the TCJA for which they were not able to either complete the required analysis or make a reasonable estimate. Additionally, PSE filed an accounting petition on December 29, 2017 requesting deferred accounting treatment for impacts of tax reform. For additional information, see Note 7, "Regulation and Rates" to the consolidated financial statements included in Item 1 of this report. Stranded Tax Effects in AOCI In February 2018, the FASB issued ASU 2018-02, " Income Statement—Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income " . The amendments in this update allow reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the TCJA and will improve the usefulness of information reported to financial statement users. This amendment is effective for fiscal years beginning after December 15, 2018, including interim periods within those years. Early adoption is permitted, including adoption in any interim period for reporting periods for which financial statements have not yet been issued. The Company early adopted ASU 2018-02 as of January 1, 2018 with a reclassification from accumulated other comprehensive income to retained earnings in the amount of a $5.2 million increase for Puget Energy related to pension and post-retirement plans and a $27.3 million increase for PSE, comprised of $26.2 million related to pension and post-retirement plans, and $1.1 million related to interest rate swaps. Retirement Benefits In March 2017, the FASB issued ASU 2017-07, " Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost ". The amendments require that an employer report the service cost component in the same line items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost (which include interest costs, expected return on plan assets, amortization of prior service cost or credits and actuarial gains and losses) are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The line item used in the income statement to present the other components of net benefit cost must be disclosed. Additionally, the service cost component of net benefit cost is the only eligible cost for capitalization. This amendment is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company adopted ASU 2017-07 during the first quarter of fiscal year 2018 by applying the amendments related to income statement activity retrospectively, and balance sheet activity prospectively. For additional information, see Note 6, "Retirement Benefits" to the consolidated financial statements included in Item 1 of this report. 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. 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 adopted ASU 2016-15 as of January 1, 2018 with the standard only impacting the classification of debt extinguishment costs as financing outflows. 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. The Company has adopted ASU 2016-18 as of January 1, 2018 by moving the presentation of restricted cash in the statement of cash flows to net cash flows of total cash, cash equivalents, and restricted cash. The following tables provide a reconciliation of cash, cash equivalents and restricted cash reported within the statements of cash flows: Puget Sound Energy Three Months Ended March 31, (Dollars in Thousands) 2018 2017 Cash and cash equivalents $ 11,226 $ 16,038 Restricted cash 13,747 9,698 Total cash, cash equivalents and restricted cash shown in the statement of cash flows $ 24,973 $ 25,736 Puget Energy Three Months Ended March 31, (Dollars in Thousands) 2018 2017 Cash and cash equivalents $ 12,056 $ 16,857 Restricted cash 13,747 9,698 Total cash, cash equivalents and restricted cash shown in the statement of cash flows $ 25,803 $ 26,555 Amounts included in restricted cash primarily represent funds required to be set aside for contractual obligations related to transmission and generation facilities. Revenue Recognition In May 2014, the FASB issued ASU No. 2014-09, " Revenue from Contracts with Customers (Topic 606) ". Accounting Standards Update (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. This Company implemented this standard as of January 1, 2018 using the modified retrospective method of adoption. As a result of implementation of this standard, the Company made no cumulative adjustments to revenue for contracts with customers open as of January 1, 2018 . As of March 31, 2018 , the Company's revenue is 95.6% comprised of contracts with customers from rate-regulated sales of electricity and natural gas to retail customers where revenue is recognized over time as delivered. Pursuant to the new standard, the Company has added enhanced quantitative and qualitative disclosure for revenue from contracts with customers and revenue outside the scope of the standard, in Note 3, "Revenue" to the consolidated financial statements included in Item 1 of this report. Accounting Standards Issued but Not Yet Adopted Lease Accounting In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)" . The FASB issued this ASU to increase transparency and comparability among organizations by recognizing right-of-use (ROU) lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. To meet that objective, the FASB is amending the FASB Accounting Standards Codification and creating Topic 842, Leases. 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. The income statement recognition is similar to existing lease accounting and is based on lease classification. Under the new guidance, lessor accounting is largely unchanged. In January 2018, the FASB issued ASU 2018-01, "Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842" . In connection with the FASB’s transition support efforts, the amendments in this update provide an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the current leases guidance in Topic 840. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 upon adoption of Topic 842. Land easements (also commonly referred to as rights of way) represent the right to use, access, or cross another entity’s land for a specified purpose. The Company plans to elect this practical expedient, and will evaluate new and modified land easements as of the first quarter of fiscal year 2019. 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 will adopt ASU 2016-02 during the first quarter of fiscal year 2019 and expects the adoption of the standard will result in recognition of right-of-use assets and liabilities that have not previously been recorded, which will have a material impact on the consolidated balance sheets. |
Revenue (Notes)
Revenue (Notes) | 3 Months Ended |
Mar. 31, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Revenue from Contract with Customer [Text Block] | Revenue The following table presents disaggregated revenue from contracts with customers, and other revenue by major source: Puget Energy and Puget Sound Energy (Dollars in Thousands) Three Months Ended March 31, Revenue from contracts with customers: 2018 Electric retail $ 630,806 Natural gas retail 334,033 Other 42,434 Total revenue from contracts with customers 1,007,273 Alternative revenue programs (15,081 ) Other non-customer revenue 45,816 Total operating revenue $ 1,038,008 Revenue at PSE is recognized when performance obligations under the terms of a contract or tariff with our customers are satisfied. Performance obligations are satisfied generally through performance of our obligation over time or with transfer of control of electric power, natural gas, and other revenue from contracts with customers. Revenue is measured as the amount of consideration expected to be received in exchange for transferring goods and services. Electric and Natural Gas Retail Revenue Electric and natural gas retail revenue consists of tariff based sales of electricity and natural gas to PSE's customers. For tariff contracts, PSE has elected the portfolio approach practical expedient to apply the revenue from contracts with customers model to groups of contracts. The Company determined that the portfolio approach will not differ from considering each contract or performance obligation separately. Electric and natural gas tariff contracts include the performance obligation of standing ready to perform electric and natural gas services. The electricity and natural gas the customer chooses to consume is considered an option and is recognized over time using the output method when the customer simultaneously consumes the electricity or natural gas. PSE has elected the right to invoice practical expedient for unbilled retail revenue, as the obligation of standing ready to perform electric service and for the consumption of electricity and natural gas at market value implies a right to consideration for performance completed to date. The Company believes that tariff prices approved by the Washington Utility and Transportation Commission (Washington Commission) represent stand-alone selling prices for the performance obligations under ASC 606. PSE collects Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes and presents the taxes on a gross basis, as PSE was determined to be the taxpayer for excise and municipal taxes. Other Revenue from Contracts with Customers Other revenue from contracts with customers is primarily comprised of electric transmission, natural gas transportation, biogas, and wholesale revenue sold on an intra-month basis. Electric Transmission and Natural Gas Transportation Transmission and transportation tariff contracts include the performance obligation to transmit and transport electricity or natural gas. Transfer of control and recognition of revenue occurs over time as the customer simultaneously receives the transmission and transportation services. Measurement of satisfaction of this performance obligation is determined using the output method. Similar to retail revenue, the Company utilizes the right to invoice practical expedient as PSE’s right to consideration is tied directly to the value of power and gas transmitted and transported each month. The price is based on the tariff rates that were approved by the Washington Commission or the Federal Energy Regulatory Commission (FERC) and therefore corresponds directly to the value to the customer for performance completed to date. Biogas Biogas is a renewable natural gas fuel that PSE purchases and sells along with the renewable green attributes derived from the renewable natural gas. Biogas contracts include the performance obligations of biogas and renewable credit delivery upon PSE receiving produced biogas from its supplier. Transfer of control and recognition of revenue occurs at a point in time as biogas is considered a storable commodity and may not be consumed as it is delivered. Wholesale Wholesale revenue at PSE includes sales of electric power and non-core natural gas to other utilities or marketers. Wholesale revenue contracts include the performance obligation of physical electric power or natural gas. There are typically no added fixed or variable amounts on top of the established rate for power or natural gas and contracts always have a stated, fixed quantity of power or natural gas delivered. Transfer of control and recognition of revenue occurs at a point in time when the customer takes physical possession of electric power or natural gas. Non-core gas consists of natural gas supply in excess of natural gas used for generation, sold to third parties to mitigate the costs of firm transportation and storage capacity for its core natural gas customers. PSE reports non-core gas sold net of costs as PSE does not take control of the natural gas but is merely an agent within the market that connects a seller to a purchaser. Other Revenue In accordance with ASC 606, PSE excludes revenue not collected from contracts with customers, as well as revenue that falls under other accounting guidance. |
Accounting for Derivative Instr
Accounting for Derivative Instruments and Hedging Activities | 3 Months Ended |
Mar. 31, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Accounting for Derivative Instruments and Hedging Activities | Accounting for Derivative Instruments and Hedging Activities PSE employs various energy portfolio optimization strategies but is not in the business of assuming risk for the purpose of realizing speculative trading revenue. The nature of serving regulated electric customers with its portfolio of owned and contracted electric generation resources exposes PSE and its customers to some volumetric and commodity price risks within the sharing mechanism of the power cost adjustment (PCA). Therefore, wholesale market transactions and PSE's related hedging strategies are focused on reducing costs and risks where feasible, thus reducing volatility of costs in the portfolio. In order to manage its exposure to the variability in future cash flows for forecasted energy transactions, PSE utilizes a programmatic hedging strategy which extends out three years. PSE's hedging strategy includes a risk-responsive component for the core natural gas portfolio, which utilizes quantitative risk-based measures with defined objectives to balance both portfolio risk and hedge costs. PSE's energy risk portfolio management function monitors and manages these risks using analytical models and tools. In order to manage risks effectively, PSE enters into forward physical electric and natural gas purchase and sale agreements, fixed-for-floating swap contracts, and commodity call/put options. Currently, the Company does not apply cash flow hedge accounting and therefore records all mark-to-market gains or losses through earnings. The Company manages its interest rate risk through the issuance of mostly fixed-rate debt with varied maturities. The Company utilizes internal cash from operations, borrowings under its commercial paper program and its credit facilities to meet short-term funding needs. The Company may enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts. The following table presents the volumes, fair values and classification of the Company's derivative instruments recorded on the balance sheets: Puget Energy and Puget Sound Energy At March 31, 2018 At December 31, 2017 (Dollars in Thousands) Volumes Assets 1 Liabilities 2 Volumes Assets 1 Liabilities 2 Electric portfolio derivatives * $ 13,150 $ 47,813 * $ 13,391 $ 49,050 Natural gas derivatives (MMBtus) 3 309.1 million 14,011 36,267 332.1 million 11,014 37,044 Total derivative contracts $ 27,161 $ 84,080 $ 24,405 $ 86,094 Current $ 23,718 $ 67,513 $ 22,247 $ 64,859 Long-term 3,443 16,567 2,158 21,235 Total derivative contracts $ 27,161 $ 84,080 $ 24,405 $ 86,094 _______________ 1 Balance sheet classification: Current and Long-term Unrealized gain on derivative instruments. 2 Balance sheet classification: Current and Long-term Unrealized loss on derivative instruments. 3 All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the purchased gas adjustment (PGA) mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers. * Electric portfolio derivatives consist of electric generation fuel of 163.8 million One Million British Thermal Units (MMBtu) and purchased electricity of 3.9 million Megawatt Hours (MWhs) at March 31, 2018 , and 166.8 million MMBtus and 2.9 million MWhs at December 31, 2017 . It is the Company's policy to record all derivative transactions on a gross basis at the contract level without offsetting assets or liabilities. The Company generally enters into transactions using the following master agreements: WSPP, Inc. (WSPP) agreements, which standardize physical power contracts; International Swaps and Derivatives Association (ISDA) agreements, which standardize financial natural gas and electric contracts; and North American Energy Standards Board (NAESB) agreements, which standardize physical natural gas contracts. The Company believes that such agreements reduce credit risk exposure because such agreements provide for the netting and offsetting of monthly payments as well as the right of set-off in the event of counterparty default. The set-off provision can be used as a final settlement of accounts which extinguishes the mutual debts owed between the parties in exchange for a new net amount. For further details regarding the fair value of derivative instruments, see Note 5, "Fair Value Measurements," to the consolidated financial statements included in Item 1 of this report. The following tables present the potential effect of netting arrangements, including rights of set-off associated with the Company's derivative assets and liabilities: Puget Energy and Puget Sound Energy At March 31, 2018 Gross Amount Recognized in the Statement of Financial Position 1 Gross Amounts Offset in the Statement of Financial Position Net of Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position (Dollars in Thousands) Commodity Contracts Cash Collateral Received/Posted Net Amount Assets: Energy derivative contracts $ 27,161 $ — $ 27,161 $ (19,254 ) $ — $ 7,907 Liabilities: Energy derivative contracts 84,080 — 84,080 (19,254 ) (3,943 ) 60,883 Puget Energy and Puget Sound Energy At December 31, 2017 Gross Amount Recognized in the Statement of Financial Position 1 Gross Amounts Offset in the Statement of Financial Position Net of Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position (Dollars in Thousands) Commodity Contracts Cash Collateral Received/Posted Net Amount Assets: Energy derivative contracts $ 24,405 $ — $ 24,405 $ (17,940 ) $ — $ 6,465 Liabilities: Energy derivative contracts 86,094 — 86,094 (17,940 ) (353 ) 67,801 _______________ 1 All derivative contract deals are executed under ISDA, NAESB and WSPP master netting agreements with right of set-off. The following table presents the effect and classification of the realized and unrealized gains (losses) of the Company's derivatives recorded on the statements of income: Puget Energy and Three Months Ended March 31, (Dollars in Thousands) Classification 2018 2017 Interest rate contracts 1 : Non-hedged interest rate swap (expense) income $ — $ 28 Gas for Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net 2,312 (16,136 ) Realized Electric generation fuel (7,676 ) (5,198 ) Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net (1,316 ) (3,152 ) Realized Purchased electricity (2,389 ) (6,155 ) Total gain (loss) recognized in income on derivatives $ (9,069 ) $ (30,613 ) _______________ 1 Interest rate swap contracts are only held at Puget Energy, and matured January 2017. The Company is exposed to credit risk primarily through buying and selling electricity and natural gas to serve its customers. Credit risk is the potential loss resulting from a counterparty's non-performance under an agreement. The Company manages credit risk with policies and procedures for, among other things, counterparty credit analysis, exposure measurement, and exposure monitoring and mitigation. The Company monitors counterparties for significant swings in credit default swap rates, credit rating changes by external rating agencies, ownership changes or financial distress. Where deemed appropriate, the Company may request collateral or other security from its counterparties to mitigate potential credit default losses. Criteria employed in this decision include, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure. It is possible that volatility in energy commodity prices could cause the Company to have material credit risk exposure with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. However, as of March 31, 2018 , approximately 95.2% of the Company's energy portfolio exposure, excluding normal purchase normal sale (NPNS) transactions, was with counterparties that are rated investment grade by rating agencies and 4.8% are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated by the major rating agencies. The Company computes credit reserves at a master agreement level by counterparty. The Company considers external credit ratings and market factors in the determination of reserves, such as credit default swaps and bond spreads. The Company recognizes that external ratings may not always reflect how a market participant perceives a counterparty's risk of default. The Company uses both default factors published by Standard & Poor's and factors derived through analysis of market risk which reflect the application of an industry standard recovery rate. The Company selects a default factor by counterparty at an aggregate master agreement level based on a weighted average default tenor for that counterparty's deals. The default tenor is determined by weighting the fair value and contract tenors for all deals for each counterparty to derive an average value. The default factor used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels. The Company applies the counterparty's default factor to compute credit reserves for counterparties that are in a net asset position. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. Credit reserves are netted against the unrealized gain (loss) positions. As of March 31, 2018 , the Company was in a net liability position with the majority of its counterparties, so 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. PSE also transacts power futures contracts on the Intercontinental Exchange (ICE) platform, which requires the daily posting of margin calls as collateral through a futures and clearing agent. As of March 31, 2018 , PSE had cash posted as collateral of $7.0 million related to contracts executed on this platform. As additional contracts are executed on this exchange, the amount of collateral to be posted will increase, subject to PSE’s established limit. PSE also has a $1.0 million letter of credit posted as collateral as a condition of transacting on a physical energy exchange and clearing house in Canada. PSE did not trigger any collateral requirements with any of its counterparties nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades during the three months ended March 31, 2018 . The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral the Company could be required to post: Puget Energy and Puget Sound Energy (Dollars in Thousands) At March 31, 2018 At December 31, 2017 Fair Value 1 Posted Contingent Fair Value 1 Posted Contingent Contingent Feature Liability Collateral Collateral Liability Collateral Collateral Credit rating 2 $ 2,698 $ — $ 2,698 $ 3,187 $ — $ 3,187 Requested credit for adequate assurance 33,316 — — 37,374 — — Forward value of contract 3 3,943 6,989 — 353 2,639 — Total $ 39,957 $ 6,989 $ 2,698 $ 40,914 $ 2,639 $ 3,187 _______________ 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 | 3 Months Ended |
Mar. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Fair Value Measurements ASC 820 established a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy categorizes the inputs into three levels with the highest priority given to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority given to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows: Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities. Equity securities that are also classified as cash equivalents are considered Level 1 if there are unadjusted quoted prices in active markets for identical assets or liabilities. Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded derivatives such as over-the-counter forwards and options. Level 3 - Pricing inputs include significant inputs that have little or no observability as of the reporting date. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. Financial assets and liabilities measured at fair value are classified in their entirety in the appropriate fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The Company primarily determines fair value measurements classified as Level 2 or Level 3 using a combination of the income and market valuation approaches. The process of determining the fair values is the responsibility of the derivative accounting department which reports to the Controller and Principal Accounting Officer. Inputs used to estimate the fair value of forwards, swaps and options include market-price curves, contract terms and prices, credit-risk adjustments, and discount factors. Additionally, for options, the Black-Scholes option valuation model and implied market volatility curves are used. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs as substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. On a daily basis, the Company obtains quoted forward prices for the electric and natural gas markets from an independent external pricing service. The Company considers its electric and natural gas contracts as Level 2 derivative instruments as such contracts are commonly traded as over-the-counter forwards with indirectly observable price quotes. However, certain energy derivative instruments with maturity dates falling outside the range of observable price quotes are classified as Level 3 in the fair value hierarchy. Management's assessment is based on the trading activity in real-time and forward electric and natural gas markets. Each quarter, the Company confirms the validity of pricing-service quoted prices used to value Level 2 commodity contracts with the actual prices of commodity contracts entered into during the most recent quarter. Assets and Liabilities with Estimated Fair Value The carrying values of cash and cash equivalents, restricted cash, and short-term debt as reported on the balance sheet are reasonable estimates of their fair value due to the short-term nature of these instruments and are classified as Level 1 in the fair value hierarchy. The carrying value of other investments totaling $48.6 million and $48.5 million at March 31, 2018 and December 31, 2017 , 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 was estimated using the discounted cash flow method with the U.S. Treasury yields and the Company's credit spreads as inputs, interpolating to the maturity date of each issue. The carrying values and estimated fair values were as follows: Puget Energy At March 31, 2018 At December 31, 2017 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Liabilities: Junior subordinated notes 2 $ 56,553 $ 53,319 $ 250,000 $ 238,935 Long-term debt (fixed-rate), net of discount 1 2 5,108,337 6,193,821 5,105,329 6,520,515 Long-term debt (variable-rate) 2 115,779 115,779 102,600 102,600 Total liabilities $ 5,280,669 $ 6,362,919 $ 5,457,929 $ 6,862,050 Puget Sound Energy At March 31, 2018 At December 31, 2017 (Dollars in Thousands) Level Carrying Fair Carrying Fair Liabilities: Junior subordinated notes 2 $ 56,553 $ 53,319 $ 250,000 $ 238,935 Long-term debt (fixed-rate), net of discount 2 2 3,500,331 4,291,452 3,499,911 4,550,130 Total liabilities $ 3,556,884 $ 4,344,771 $ 3,749,911 $ 4,789,065 _______________ 1 The carrying value includes debt issuances costs of $27.0 million and $27.9 million for March 31, 2018 and December 31, 2017 , respectively, which are not included in fair value. 2 The carrying value includes debt issuances costs of $24.2 million and $24.6 million for March 31, 2018 and December 31, 2017 , respectively, which are not included in fair value. Assets and Liabilities Measured at Fair Value on a Recurring Basis The following table presents the Company's financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis: Puget Energy and Fair Value Fair Value Puget Sound Energy At March 31, 2018 At December 31, 2017 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Assets: Electric derivative instruments $ 8,483 $ 4,667 $ 13,150 $ 9,866 $ 3,525 $ 13,391 Natural gas derivative instruments 5,992 8,019 14,011 6,973 4,041 11,014 Total assets $ 14,475 $ 12,686 $ 27,161 $ 16,839 $ 7,566 $ 24,405 Liabilities: Electric derivative instruments $ 44,332 $ 3,481 $ 47,813 $ 46,623 $ 2,427 $ 49,050 Natural gas derivative instruments 33,344 2,923 36,267 34,926 2,118 37,044 Total liabilities $ 77,676 $ 6,404 $ 84,080 $ 81,549 $ 4,545 $ 86,094 The following table presents the Company's reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy: Puget Energy and Puget Sound Energy Three Months Ended March 31, (Dollars in Thousands) 2018 2017 Level 3 Roll-Forward Net Asset/(Liability) Electric Natural Gas Total Electric Natural Gas Total Balance at beginning of period $ 1,098 $ 1,923 $ 3,021 $ 972 $ 625 $ 1,597 Changes during period: Realized and unrealized energy derivatives: Included in earnings 1 1,619 — 1,619 706 — 706 Included in regulatory assets / liabilities — 4,976 4,976 — 2,458 2,458 Settlements (503 ) (1,803 ) (2,306 ) (1,330 ) (1,329 ) (2,659 ) Transferred into Level 3 (1,837 ) — (1,837 ) 2,189 (554 ) 1,635 Transferred out of Level 3 809 — 809 1,251 552 1,803 Balance at end of period $ 1,186 $ 5,096 $ 6,282 $ 3,788 $ 1,752 $ 5,540 ______________ 1 Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $2.0 million and $1.8 million for the three months ended March 31, 2018 and 2017 . 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 tables. The Company did not have any transfers between Level 1 and Level 2 during the reported periods. 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 forward 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. The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of March 31, 2018 : Puget Energy and Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Average Electric $ 4,667 $ 3,481 Discounted cash flow Power prices (per MWh) $ 11.60 $ 29.48 $ 22.74 Natural gas $ 8,019 $ 2,923 Discounted cash flow Natural gas prices (per MMBtu) $ 0.90 $ 2.88 $ 1.61 _______________ 1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions. The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of December 31, 2017 : Puget Energy and Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Average Electric $ 3,525 $ 2,427 Discounted cash flow Power prices (per MWh) $ 7.02 $ 28.94 $ 18.61 Natural gas $ 4,041 $ 2,118 Discounted cash flow Natural gas prices (per MMBtu) $ 1.22 $ 2.80 $ 1.54 _______________ 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 March 31, 2018 and December 31, 2017 , a hypothetical 10.0% 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 $0.6 million and $0.9 million , respectively. Long-Lived Assets Measured at Fair Value on a Nonrecurring Basis Puget Energy records the fair value of its intangible assets in accordance with ASC 360, “Property, Plant, and Equipment,” (ASC 360). The fair value assigned to the power contracts was determined using an income approach comparing the contract rate to the market rate for power over the remaining period of the contracts incorporating non-performance risk. Management also incorporated certain assumptions related to quantities and market presentation that it believes market participants would make in the valuation. The fair value of the power contracts is amortized as the contracts settle. ASC 360 requires long-lived assets to be tested for 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. As of March 31, 2018 , Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets. The Wells Hydro contract was determined to be impaired due to a decrease in forward prices for this contract of 39.0% from December 31, 2017 , causing an impairment of $1.9 million . The following table presents the impairment recorded to the Company's intangible asset contracts, with corresponding reductions to the regulatory liability: Puget Energy (Dollars in Thousands) Valuation Date Contract Name Carrying Value Fair Value Write Down March 31, 2018 Wells Hydro $ 4,302 $ 2,395 $ 1,907 The valuations were measured using a discounted cash flow, income-based valuation methodology. Significant inputs included forward electricity prices and power contract pricing which provided future net cash flow estimates classified as Level 3 within the fair value hierarchy. A less significant input is the discount rate reflective of PSE's cost of capital used in the valuation. The following table presents the significant unobservable inputs used in estimating the impaired long-term power purchase contracts' fair value: Puget Energy Valuation Date Unobservable Input Low High Average March 31, 2018 Power prices (per MWh) $9.69 $25.30 $17.50 Power contract costs per quarter (in thousands) 4,126 4,126 4,126 |
Retirement Benefits
Retirement Benefits | 3 Months Ended |
Mar. 31, 2018 | |
Retirement Benefits [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 January 1, 2014, for non-represented employees, and December 12, 2014 for employees represented by the IBEW,participants will receive annual pay credits of 4.0% each year in the defined benefit pension or 401k plan account. They will also receive interest credits like other participants in the cash balance pension formula of the pension plan, which are at least 1.0% 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. 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. In March 2017, the FASB issued ASU 2017-07, requiring that an employer report the service cost component in the same line items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost (which include interest costs, expected return on plan assets, amortization of prior service cost or credits and actuarial gains and losses) are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The Company has included in the consolidated statements of income: (i) the components of service cost within utility operations and maintenance for PSE and within non-utility expense and other for Puget Energy, and (ii) all non-service cost components in other income. The following tables summarize the Company’s net periodic benefit cost for the three months ended March 31, 2018 and 2017 : Puget Energy Qualified SERP Other Three Months Ended March 31, (Dollars in Thousands) 2018 2017 2018 2017 2018 2017 Components of net periodic benefit cost: Service cost $ 5,425 $ 5,018 $ 212 $ 228 $ 17 $ 20 Interest cost 6,780 7,099 530 571 110 121 Expected return on plan assets (12,559 ) (11,951 ) — — (117 ) (115 ) Amortization of prior service cost (495 ) (495 ) 11 11 — — Amortization of net loss (gain) 462 — 394 269 (86 ) (113 ) Net periodic benefit cost $ (387 ) $ (329 ) $ 1,147 $ 1,079 $ (76 ) $ (87 ) Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits Three Months Ended March 31, (Dollars in Thousands) 2018 2017 2018 2017 2018 2017 Components of net periodic benefit cost: Service cost $ 5,425 $ 5,018 $ 212 $ 228 $ 17 $ 20 Interest cost 6,780 7,099 530 571 110 121 Expected return on plan assets (12,569 ) (11,970 ) — — (117 ) (115 ) Amortization of prior service cost (393 ) (393 ) 11 11 — — Amortization of net loss (gain) 3,630 3,429 517 392 (142 ) (173 ) Net periodic benefit cost $ 2,873 $ 3,183 $ 1,270 $ 1,202 $ (132 ) $ (147 ) The following table summarizes the Company’s change in benefit obligation for the periods ended March 31, 2018 and December 31, 2017 : Puget Energy and Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits Three Months Ended Year Three Months Ended Year Three Months Ended Year (Dollars in Thousands) March 31, December 31, March 31, December 31, March 31, December 31, Change in benefit obligation: Benefit obligation at beginning of period $ 700,481 $ 652,607 $ 55,754 $ 51,734 $ 11,454 $ 11,194 Service cost 5,425 20,081 212 913 17 72 Interest cost 6,780 28,373 530 2,285 110 500 Actuarial loss (gain) — 40,945 — 2,722 — 725 Benefits paid (10,650 ) (40,594 ) (592 ) (1,900 ) (279 ) (1,137 ) Medicare part D subsidy received — — — — — 100 Administrative Expense — (931 ) — — — — Benefit obligation at end of period $ 702,036 $ 700,481 $ 55,904 $ 55,754 $ 11,302 $ 11,454 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, 2018 are expected to be at least $18.0 million , $5.5 million and $0.3 million , respectively. During the three months ended March 31, 2018 , the Company contributed $4.5 million and $0.6 million to fund the qualified pension plan and SERP, respectively. The Company contributed an immaterial amount to fund the other postretirement plans. |
Regulation and Rates
Regulation and Rates | 3 Months Ended |
Mar. 31, 2018 | |
Regulation and Rates [Abstract] | |
Regulation and Rates | Regulation and Rates General Rate Case Filing In January 2017, PSE filed its general rate case (GRC) with the Washington Commission. The GRC filing included a required plan to address Colstrip Units 1 and 2 closures, requested that electric energy supply fixed costs be included in PSE's decoupling mechanism, and contained requests for two new mechanisms to address regulatory lag. The Washington Commission entered a final order accepting the multi-party settlement agreement and determined the contested issues in the case on December 5, 2017 and new rates became effective December 19, 2017. The settlement agreement provides for a weighted cost of capital of 7.6% or 6.55% after-tax, and a capital structure of 48.5% in common equity with a return on equity of 9.5% . The settlement also resulted in a combined electric tariff change that resulted in a net increase of $20.2 million , or 0.9% , annually, and a combined natural gas tariff change that resulted in a net decrease of $35.5 million , or 3.8% , annually. The GRC also repurposed the benefit for PTCs and hydro-related treasury grants to fund and recover decommissioning and remediation costs for Colstrip Units 1 and 2. As the Company monetizes PTCs, which are PTCs used on the filed tax returns, it adjusts revenues and records the benefit as an offset to its reserve for Colstrip Units 1 and 2 decommissioning and remediation costs. For further details regarding the 2017 GRC filing, see Note 3, "Regulation and Rates" to the consolidated financial statements included in Item 8 of the Company’s Form 10-K for the period ended December 31, 2017. Decoupling Filings While fluctuations in weather conditions will continue to affect PSE's billed revenue and energy supply expenses from month to month, PSE's decoupling mechanisms assist in mitigating the impact of weather on operating revenue and net income. Since July 2013, the Washington Commission has allowed PSE to record a monthly adjustment to its electric and natural gas operating revenues related to electric transmission and distribution, natural gas operations and general administrative costs from most residential, commercial and industrial customers to mitigate the effects of abnormal weather, conservation impacts and changes in usage patterns per customer. As a result, these electric and natural gas revenues are recovered on a per customer basis regardless of actual consumption levels. PSE's energy supply costs, which are part of the PCA and PGA mechanisms, are not included in the decoupling mechanism. The revenue recorded under the decoupling mechanisms will be affected by customer growth and not actual consumption. Following each calendar year, PSE will recover from, or refund to, customers the difference between allowed decoupling revenue and the corresponding actual revenue during the following May to April time period. During the rate plan, which ended in December 2017, the allowed decoupling revenue per customer for the recovery of delivery system costs increased by 3.0% for the electric customers and 2.2% for the natural gas customers on January 1 of each year. On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 GRC to extend the decoupling mechanism with some changes to the methodology that took effect on December 19, 2017. Electric and natural gas delivery revenues will continue to be recovered on a per customer basis and electric fixed production energy costs will now be decoupled and recovered on the basis of a fixed monthly amount. The allowed decoupling revenue for electric and natural gas customers will no longer increase annually each January 1 as occurred prior to December 19, 2017. Approved revenue per customer costs can only be changed in a GRC or ERF. Approved electric fixed production energy costs can only be changed in a GRC or power cost only rate case. Other changes to the decoupling methodology approved by the Washington Commission include regrouping of electric and natural gas non-residential customers and the exclusion of certain electric schedules from the decoupling mechanism going forward. The rate test which limits the amount of revenues PSE can collect in its annual filings increased from 3.0% to 5.0% for natural gas customers but will remain at 3.0% for electric customers. The decoupling mechanism will be reviewed again in PSE’s first rate case filed in or after 2021, or in a separate proceeding, if appropriate. There is a 3.0% cap for electric and 5.0% cap for natural gas on annual decoupling increases noted above. PSE performed an analysis as of March 31, 2018 to determine if electric and natural gas decoupling revenue deferrals would be collected from customers within 24 months of the annual period, per ASC 980-605. If not, for GAAP purposes only, PSE will need to record a reserve against the decoupling revenue and regulatory asset balance. Once the revenue is forecasted to be collected within 24 months, the reserve can be reversed. The analysis indicated all deferred revenue for electric and natural gas will be collected within 24 months of the annual period; therefore, there were no adjustments to 2017 or 2018 decoupling revenue other than to record the previously unrecognized decoupling deferrals of $20.8 million at December 31, 2017. Electric Regulation and Rates Storm Damage Deferral Accounting The Washington Commission issued a GRC order that defined deferrable storm events and provided that costs in excess of the annual cost threshold may be deferred for qualifying storm damage costs that meet the modified Institute of Electrical and Electronics Engineers outage criteria for system average interruption duration index. For the three months ended March 31, 2018 , PSE incurred $5.7 million in storm-related electric transmission and distribution system restoration costs, of which no amount was deferred to a regulatory asset. This compares to $26.4 million incurred in storm-related electric transmission and distribution system restoration costs for the three months ended March 31, 2017, of which $8.8 million was deferred to a regulatory asset. Under the December 5, 2017 Washington Commission order regarding PSE’s GRC, the following changes to PSE’s storm deferral mechanism were approved: (i) the cumulative annual cost threshold for deferral of storms under the mechanism increased from $8.0 million to $10.0 million effective January 1, 2018; and (ii) qualifying events where the total qualifying cost is less than $0.5 million will not qualify for deferral and these costs will also not count toward the $10.0 million annual cost threshold. Washington Commission Tax Deferral Filing The TCJA was signed into law in December 2017. As a result of this change, PSE remeasured its deferred tax balances under the new corporate tax rate. PSE filed an accounting petition on December 29, 2017 requesting deferred accounting treatment for the impacts of tax reform. The deferral accounting treatment results in the tax rate change being captured in the deferred income tax balance with an offset to the regulatory liability for deferred income taxes. Additionally, on March 30, 2018, PSE filed for a rate change for electric and natural gas customers associated with TCJA to reflect the decrease in the federal corporate income tax rate from 35.0% to 21.0%. The filing did not address excess deferred taxes or the deferred balance associated with the over-collection of income tax expense of $27.4 million for the period January 1 through April 30, 2018 (the time period that encompasses the effective date of the TCJA through May 1, 2018, the effective date of the rate change). The $27.4 million tax over-collection decreased PSE's revenue and increased the regulatory liability for a refund to customers. PSE’s proposal in the filing is to address both the excess deferred taxes and the deferred balance associated with the over-collection of income tax expense in PSE’s accounting petition. The overall impact of the rate change, based on the annual period from May 2018 through April 2019, is a revenue decrease of $72.9 million , or 3.5% for electric and $23.6 million , or 3.0% for natural gas. |
Commitments and Contingencies
Commitments and Contingencies | 3 Months Ended |
Mar. 31, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | (8) Commitment and Contingencies 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. 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 that was signed by all Colstrip owners, Colstrip 1 and 2 owners, PSE and Talen Energy, agreed to retire the two oldest units (Units 1 and 2) no later than July 1, 2022. The Washington Commission allows full recovery in rates of the net book value (NBV) at retirement and related decommissioning costs consistent with prior precedents. Depreciation rates were updated in the GRC effective December 19, 2017, where PSE's depreciation increased for Colstrip Units 1 and 2 to recover plant costs to the expected shutdown date. The increase in depreciation caused the Colstrip Units 1 and 2 regulatory asset to be reduced to $127.8 million and $127.6 million as of March 31, 2018 and December 31, 2017 , respectively. However, the full scope of decommissioning activities and costs may vary from the estimates that are available at this time. The GRC also repurposed PTCs and hydro-related treasury grants to fund and recover decommissioning and remediation costs for Colstrip Units 1 and 2. Additionally, PSE will accelerate the depreciation of Colstrip Units 3 and 4, per the terms of the GRC settlement, to December 31, 2027. 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 on September 20, 2016. On March 28, 2017, pipeline safety regulators and PSE reached a settlement in response to the complaint. As part of the agreement, PSE agreed to pay a penalty of $1.5 million , and is currently implementing a comprehensive inspection and remediation program. However, litigation is still pending regarding damage and personal injury claims. Other Commitments and Contingencies There have been no material changes to the contractual obligations and consolidated commercial commitments disclosed in the Company's Annual Report on Form 10-K for the year ended December 31, 2017 . |
Summary of Consolidation Poli16
Summary of Consolidation Policy (Policies) | 3 Months Ended |
Mar. 31, 2018 | |
Accounting Policies [Abstract] | |
Significant Accounting Policies | Summary of Consolidation Policy Basis of Presentation Puget Energy is an energy services holding company that owns Puget Sound Energy (PSE). PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering approximately 6,000 square miles, primarily in the Puget Sound region. Puget Energy also has a wholly-owned non-regulated subsidiary, Puget LNG, LLC (Puget LNG), which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma LNG facility, currently under construction. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that occur under PSE and are allocated to Puget LNG are related party transactions by nature. As of March 31, 2018 , Puget LNG has incurred $124.4 million in construction work in progress and operating costs related to Puget LNG’s portion of the Tacoma LNG facility. The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries. PSE’s consolidated financial statements include the accounts of PSE and its subsidiary. Puget Energy and PSE are collectively referred to herein as “the Company”. The consolidated financial statements are presented after elimination of all significant intercompany items and transactions. PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any Accounting Standards Codification (ASC) 805, “Business Combinations” (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. Tacoma LNG Facility The Tacoma LNG facility is intended to provide peak-shaving services to PSE’s natural gas customers. By storing surplus natural gas, PSE is able to meet the requirements of peak consumption later during different seasons. LNG will also provide fuel to transportation customers, particularly in the marine market. On January 24, 2018, the Puget Sound Clean Air Agency determined a Supplemental Environmental Impact Statement is necessary in order to rule on the air quality permit for the facility. As a result of requiring a Supplemental Environmental Impact Statement, the Company's construction schedule may be impacted depending on the Puget Sound Clean Air Agency's timing and decision on the air quality permit. If delayed, the construction schedule and costs may be adversely impacted. Pursuant to an order by the Washington Commission, PSE will be allocated approximately 43.0% of common capital and operating costs, consistent with the regulated portion of the Tacoma LNG facility. The remaining 57.0% of common capital and operating costs of the Tacoma LNG facility will be allocated to Puget LNG. For Puget Energy, $124.3 million in construction work in progress related to Puget LNG’s portion of the Tacoma LNG facility is reported in the “Other property and investments” financial statement line item. For PSE, construction work in progress of $102.6 million related to PSE’s portion of the Tacoma LNG facility is reported in the “Utility plant - Natural gas plant” line item, as PSE is a regulated entity. |
Revenue (Tables)
Revenue (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Disaggregation of Revenue | The following table presents disaggregated revenue from contracts with customers, and other revenue by major source: Puget Energy and Puget Sound Energy (Dollars in Thousands) Three Months Ended March 31, Revenue from contracts with customers: 2018 Electric retail $ 630,806 Natural gas retail 334,033 Other 42,434 Total revenue from contracts with customers 1,007,273 Alternative revenue programs (15,081 ) Other non-customer revenue 45,816 Total operating revenue $ 1,038,008 |
Accounting for Derivative Ins18
Accounting for Derivative Instruments and Hedging Activities (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Derivative [Line Items] | |
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value | The following table presents the volumes, fair values and classification of the Company's derivative instruments recorded on the balance sheets: Puget Energy and Puget Sound Energy At March 31, 2018 At December 31, 2017 (Dollars in Thousands) Volumes Assets 1 Liabilities 2 Volumes Assets 1 Liabilities 2 Electric portfolio derivatives * $ 13,150 $ 47,813 * $ 13,391 $ 49,050 Natural gas derivatives (MMBtus) 3 309.1 million 14,011 36,267 332.1 million 11,014 37,044 Total derivative contracts $ 27,161 $ 84,080 $ 24,405 $ 86,094 Current $ 23,718 $ 67,513 $ 22,247 $ 64,859 Long-term 3,443 16,567 2,158 21,235 Total derivative contracts $ 27,161 $ 84,080 $ 24,405 $ 86,094 _______________ 1 Balance sheet classification: Current and Long-term Unrealized gain on derivative instruments. 2 Balance sheet classification: Current and Long-term Unrealized loss on derivative instruments. 3 All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the purchased gas adjustment (PGA) mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers. * Electric portfolio derivatives consist of electric generation fuel of 163.8 million One Million British Thermal Units (MMBtu) and purchased electricity of 3.9 million Megawatt Hours (MWhs) at March 31, 2018 , and 166.8 million MMBtus and 2.9 million MWhs at December 31, 2017 . |
Offsetting Assets and Liabilities | The following tables present the potential effect of netting arrangements, including rights of set-off associated with the Company's derivative assets and liabilities: Puget Energy and Puget Sound Energy At March 31, 2018 Gross Amount Recognized in the Statement of Financial Position 1 Gross Amounts Offset in the Statement of Financial Position Net of Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position (Dollars in Thousands) Commodity Contracts Cash Collateral Received/Posted Net Amount Assets: Energy derivative contracts $ 27,161 $ — $ 27,161 $ (19,254 ) $ — $ 7,907 Liabilities: Energy derivative contracts 84,080 — 84,080 (19,254 ) (3,943 ) 60,883 Puget Energy and Puget Sound Energy At December 31, 2017 Gross Amount Recognized in the Statement of Financial Position 1 Gross Amounts Offset in the Statement of Financial Position Net of Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position (Dollars in Thousands) Commodity Contracts Cash Collateral Received/Posted Net Amount Assets: Energy derivative contracts $ 24,405 $ — $ 24,405 $ (17,940 ) $ — $ 6,465 Liabilities: Energy derivative contracts 86,094 — 86,094 (17,940 ) (353 ) 67,801 _______________ 1 All derivative contract deals are executed under ISDA, NAESB and WSPP master netting agreements with right of set-off. |
Schedule of Credit Risk Related Contingent Features | Puget Energy and Puget Sound Energy (Dollars in Thousands) At March 31, 2018 At December 31, 2017 Fair Value 1 Posted Contingent Fair Value 1 Posted Contingent Contingent Feature Liability Collateral Collateral Liability Collateral Collateral Credit rating 2 $ 2,698 $ — $ 2,698 $ 3,187 $ — $ 3,187 Requested credit for adequate assurance 33,316 — — 37,374 — — Forward value of contract 3 3,943 6,989 — 353 2,639 — Total $ 39,957 $ 6,989 $ 2,698 $ 40,914 $ 2,639 $ 3,187 _______________ 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. |
Parent Company [Member] | |
Derivative [Line Items] | |
Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance | The following table presents the effect and classification of the realized and unrealized gains (losses) of the Company's derivatives recorded on the statements of income: Puget Energy and Three Months Ended March 31, (Dollars in Thousands) Classification 2018 2017 Interest rate contracts 1 : Non-hedged interest rate swap (expense) income $ — $ 28 Gas for Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net 2,312 (16,136 ) Realized Electric generation fuel (7,676 ) (5,198 ) Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net (1,316 ) (3,152 ) Realized Purchased electricity (2,389 ) (6,155 ) Total gain (loss) recognized in income on derivatives $ (9,069 ) $ (30,613 ) |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |
Schedule of Impaired Intangible Assets | The Wells Hydro contract was determined to be impaired due to a decrease in forward prices for this contract of 39.0% from December 31, 2017 , causing an impairment of $1.9 million . The following table presents the impairment recorded to the Company's intangible asset contracts, with corresponding reductions to the regulatory liability: Puget Energy (Dollars in Thousands) Valuation Date Contract Name Carrying Value Fair Value Write Down March 31, 2018 Wells Hydro $ 4,302 $ 2,395 $ 1,907 |
Fair Value Inputs, Liabilities, Quantitative Information | The fair value of the junior subordinated and long-term notes was estimated using the discounted cash flow method with the U.S. Treasury yields and the Company's credit spreads as inputs, interpolating to the maturity date of each issue. The carrying values and estimated fair values were as follows: Puget Energy At March 31, 2018 At December 31, 2017 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Liabilities: Junior subordinated notes 2 $ 56,553 $ 53,319 $ 250,000 $ 238,935 Long-term debt (fixed-rate), net of discount 1 2 5,108,337 6,193,821 5,105,329 6,520,515 Long-term debt (variable-rate) 2 115,779 115,779 102,600 102,600 Total liabilities $ 5,280,669 $ 6,362,919 $ 5,457,929 $ 6,862,050 Puget Sound Energy At March 31, 2018 At December 31, 2017 (Dollars in Thousands) Level Carrying Fair Carrying Fair Liabilities: Junior subordinated notes 2 $ 56,553 $ 53,319 $ 250,000 $ 238,935 Long-term debt (fixed-rate), net of discount 2 2 3,500,331 4,291,452 3,499,911 4,550,130 Total liabilities $ 3,556,884 $ 4,344,771 $ 3,749,911 $ 4,789,065 _______________ 1 The carrying value includes debt issuances costs of $27.0 million and $27.9 million for March 31, 2018 and December 31, 2017 , respectively, which are not included in fair value. 2 The carrying value includes debt issuances costs of $24.2 million and $24.6 million for March 31, 2018 and December 31, 2017 , respectively, which are not included in fair value. |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation | Puget Energy and Puget Sound Energy Three Months Ended March 31, (Dollars in Thousands) 2018 2017 Level 3 Roll-Forward Net Asset/(Liability) Electric Natural Gas Total Electric Natural Gas Total Balance at beginning of period $ 1,098 $ 1,923 $ 3,021 $ 972 $ 625 $ 1,597 Changes during period: Realized and unrealized energy derivatives: Included in earnings 1 1,619 — 1,619 706 — 706 Included in regulatory assets / liabilities — 4,976 4,976 — 2,458 2,458 Settlements (503 ) (1,803 ) (2,306 ) (1,330 ) (1,329 ) (2,659 ) Transferred into Level 3 (1,837 ) — (1,837 ) 2,189 (554 ) 1,635 Transferred out of Level 3 809 — 809 1,251 552 1,803 Balance at end of period $ 1,186 $ 5,096 $ 6,282 $ 3,788 $ 1,752 $ 5,540 ______________ 1 Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $2.0 million and $1.8 million for the three months ended March 31, 2018 and 2017 . |
Fair Value Inputs, Assets and Liabilities, Quantitative Information | The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of March 31, 2018 : Puget Energy and Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Average Electric $ 4,667 $ 3,481 Discounted cash flow Power prices (per MWh) $ 11.60 $ 29.48 $ 22.74 Natural gas $ 8,019 $ 2,923 Discounted cash flow Natural gas prices (per MMBtu) $ 0.90 $ 2.88 $ 1.61 _______________ 1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions. The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of December 31, 2017 : Puget Energy and Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Average Electric $ 3,525 $ 2,427 Discounted cash flow Power prices (per MWh) $ 7.02 $ 28.94 $ 18.61 Natural gas $ 4,041 $ 2,118 Discounted cash flow Natural gas prices (per MMBtu) $ 1.22 $ 2.80 $ 1.54 _______________ 1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions. The following table presents the significant unobservable inputs used in estimating the impaired long-term power purchase contracts' fair value: Puget Energy Valuation Date Unobservable Input Low High Average March 31, 2018 Power prices (per MWh) $9.69 $25.30 $17.50 Power contract costs per quarter (in thousands) 4,126 4,126 4,126 |
Parent Company [Member] | |
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 table presents the Company's financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis: |
Subsidiaries [Member] | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis | Puget Energy and Fair Value Fair Value Puget Sound Energy At March 31, 2018 At December 31, 2017 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Assets: Electric derivative instruments $ 8,483 $ 4,667 $ 13,150 $ 9,866 $ 3,525 $ 13,391 Natural gas derivative instruments 5,992 8,019 14,011 6,973 4,041 11,014 Total assets $ 14,475 $ 12,686 $ 27,161 $ 16,839 $ 7,566 $ 24,405 Liabilities: Electric derivative instruments $ 44,332 $ 3,481 $ 47,813 $ 46,623 $ 2,427 $ 49,050 Natural gas derivative instruments 33,344 2,923 36,267 34,926 2,118 37,044 Total liabilities $ 77,676 $ 6,404 $ 84,080 $ 81,549 $ 4,545 $ 86,094 |
Retirement Benefits (Tables)
Retirement Benefits (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Schedule of Changes in Projected Benefit Obligations | The following table summarizes the Company’s change in benefit obligation for the periods ended March 31, 2018 and December 31, 2017 : Puget Energy and Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits Three Months Ended Year Three Months Ended Year Three Months Ended Year (Dollars in Thousands) March 31, December 31, March 31, December 31, March 31, December 31, Change in benefit obligation: Benefit obligation at beginning of period $ 700,481 $ 652,607 $ 55,754 $ 51,734 $ 11,454 $ 11,194 Service cost 5,425 20,081 212 913 17 72 Interest cost 6,780 28,373 530 2,285 110 500 Actuarial loss (gain) — 40,945 — 2,722 — 725 Benefits paid (10,650 ) (40,594 ) (592 ) (1,900 ) (279 ) (1,137 ) Medicare part D subsidy received — — — — — 100 Administrative Expense — (931 ) — — — — Benefit obligation at end of period $ 702,036 $ 700,481 $ 55,904 $ 55,754 $ 11,302 $ 11,454 |
Parent Company [Member] | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Schedule of Net Benefit Costs | The following tables summarize the Company’s net periodic benefit cost for the three months ended March 31, 2018 and 2017 : Puget Energy Qualified SERP Other Three Months Ended March 31, (Dollars in Thousands) 2018 2017 2018 2017 2018 2017 Components of net periodic benefit cost: Service cost $ 5,425 $ 5,018 $ 212 $ 228 $ 17 $ 20 Interest cost 6,780 7,099 530 571 110 121 Expected return on plan assets (12,559 ) (11,951 ) — — (117 ) (115 ) Amortization of prior service cost (495 ) (495 ) 11 11 — — Amortization of net loss (gain) 462 — 394 269 (86 ) (113 ) Net periodic benefit cost $ (387 ) $ (329 ) $ 1,147 $ 1,079 $ (76 ) $ (87 ) |
Subsidiaries [Member] | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Schedule of Net Benefit Costs | Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits Three Months Ended March 31, (Dollars in Thousands) 2018 2017 2018 2017 2018 2017 Components of net periodic benefit cost: Service cost $ 5,425 $ 5,018 $ 212 $ 228 $ 17 $ 20 Interest cost 6,780 7,099 530 571 110 121 Expected return on plan assets (12,569 ) (11,970 ) — — (117 ) (115 ) Amortization of prior service cost (393 ) (393 ) 11 11 — — Amortization of net loss (gain) 3,630 3,429 517 392 (142 ) (173 ) Net periodic benefit cost $ 2,873 $ 3,183 $ 1,270 $ 1,202 $ (132 ) $ (147 ) |
Summary of Consolidation Poli21
Summary of Consolidation Policy (Details) $ in Millions | Mar. 31, 2018USD ($)mi² |
Subsidiaries [Member] | |
Summary of Consolidation Policy | |
Area of Service Territory (in sqmi) | mi² | 6,000 |
Subsidiaries [Member] | Tacoma LNG [Member] | |
Summary of Consolidation Policy | |
Jointly Owned Non-Utility Plant Share | 43.00% |
Construction in Progress, Gross | $ 102.6 |
Puget LNG [Member] | |
Summary of Consolidation Policy | |
Construction in Progress and O&M Expenses | $ 124.4 |
Jointly Owned Non-Utility Plant Share | 57.00% |
Construction in Progress, Gross | $ 124.3 |
New Accounting Pronouncements S
New Accounting Pronouncements Stranded Taxes in AOCI (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
strandedtaxesinAOCI [Line Items] | ||
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings | $ 5,230 | $ 0 |
Subsidiaries [Member] | ||
strandedtaxesinAOCI [Line Items] | ||
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings | 27,333 | $ 0 |
Other Comprehensive Income (Loss) Reclassification of Stranded Taxes to RE for Pension Plans | 26,200 | |
Other Comprehensive Income (Loss) Reclassification of Stranded Taxes to RE for Interest Rate Swaps | $ 1,100 |
New Accounting Pronouncements R
New Accounting Pronouncements Restricted Cash (Details) - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 | Mar. 31, 2017 |
Restricted Cash and Cash Equivalents Items [Line Items] | |||
Cash and cash equivalents | $ 12,056 | $ 26,616 | $ 16,857 |
Restricted cash | 13,747 | 10,145 | 9,698 |
Total cash, cash equivalents and restricted cash shown in the statement of cash flows | 25,803 | 26,555 | |
Subsidiaries [Member] | |||
Restricted Cash and Cash Equivalents Items [Line Items] | |||
Cash and cash equivalents | 11,226 | 25,864 | 16,038 |
Restricted cash | 13,747 | $ 10,145 | 9,698 |
Total cash, cash equivalents and restricted cash shown in the statement of cash flows | $ 24,973 | $ 25,736 |
New Accounting Pronouncements24
New Accounting Pronouncements Revenue Recognition (Details) | Mar. 31, 2018 |
Revenue from Contract with Customer [Abstract] | |
Contracts with Customers from Rate-Regulated Sales of Electricity and Natural Gas | 95.60% |
Revenue (Details)
Revenue (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Disaggregation of Revenue [Line Items] | ||
Regulated Operating Revenue, Other | $ 8,038 | $ 8,183 |
Revenues | 1,038,008 | 1,077,232 |
606ElectricRetailRevenue [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from Contract with Customer, Including Assessed Tax | 630,806 | |
606NaturalGasRetailRevenue [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from Contract with Customer, Including Assessed Tax | 334,033 | |
Other Revenue From Contracts with Customers [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from Contract with Customer, Including Assessed Tax | 42,434 | |
Revenue from Contract with Customer [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from Contract with Customer, Including Assessed Tax | 1,007,273 | |
Decoupling over-collection [Domain] | ||
Disaggregation of Revenue [Line Items] | ||
Regulated Operating Revenue, Other | (15,081) | |
Other Non-606 Revenue [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Regulated Operating Revenue, Other | 45,816 | |
Subsidiaries [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Regulated Operating Revenue, Other | 8,038 | 8,183 |
Revenues | $ 1,038,008 | $ 1,077,232 |
Accounting for Derivative Ins26
Accounting for Derivative Instruments and Hedging Activities Derivative Activity and Notional Amounts (Details) MWh in Millions, MMBTU in Millions | 3 Months Ended | |
Mar. 31, 2018MWhMMBTU | Dec. 31, 2017MWhMMBTU | |
Natural Gas Derivatives [Member] | Not Designated as Hedging Instrument [Member] | ||
Derivative [Line Items] | ||
Derivative, Notional amount, Nonmonetary | 309.1 | 332.1 |
Electric generation fuel [Member] | Not Designated as Hedging Instrument [Member] | ||
Derivative [Line Items] | ||
Derivative, Notional amount, Nonmonetary | 163.8 | 166.8 |
Purchased Electricity [Member] | Not Designated as Hedging Instrument [Member] | ||
Derivative [Line Items] | ||
Derivative, Notional amount, Nonmonetary | MWh | 3.9 | 2.9 |
Subsidiaries [Member] | ||
Derivative [Line Items] | ||
Hedging strategy number of years extended | 3 years |
Accounting for Derivative Ins27
Accounting for Derivative Instruments and Hedging Activities Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 |
Derivative [Line Items] | ||
Unrealized gain on derivative instruments | $ 23,718 | $ 22,247 |
Assets, Long-term | 3,443 | 2,158 |
Derivative Liability, Current | 67,513 | 64,859 |
Unrealized loss on derivative instruments | 16,567 | 21,235 |
Subsidiaries [Member] | ||
Derivative [Line Items] | ||
Unrealized gain on derivative instruments | 23,718 | 22,247 |
Assets, Long-term | 3,443 | 2,158 |
Derivative Liability, Current | 67,513 | 64,859 |
Unrealized loss on derivative instruments | 16,567 | 21,235 |
Commodity Contract [Member] | ||
Derivative [Line Items] | ||
Assets | 27,161 | 24,405 |
Derivative Liability | $ 84,080 | $ 86,094 |
Accounting for Derivative Ins28
Accounting for Derivative Instruments and Hedging Activities Net Amount of Derivatives Reported in the Statement of Financial Position (Details) $ in Thousands, MMBTU in Millions | Mar. 31, 2018USD ($)MMBTU | Dec. 31, 2017USD ($)MMBTU | |
Liabilities: | |||
Derivative Asset, Current | $ 23,718 | $ 22,247 | |
Derivative Liability, Current | 67,513 | 64,859 | |
Derivative Asset, Noncurrent | 3,443 | 2,158 | |
Derivative Liability, Noncurrent | 16,567 | 21,235 | |
Commodity Contract [Member] | |||
Assets: | |||
Gross Amount Recognized in the Statement of Financial Position | 27,161 | [1] | 24,405 |
Gross Amounts Offset in the Statement of Financial Position | 0 | 0 | |
Net of Amounts Presented in the Statement of Financial Position | 27,161 | 24,405 | |
Commodity Contracts | (19,254) | (17,940) | |
Cash Collateral Received | 0 | 0 | |
Net Amount | 7,907 | 6,465 | |
Liabilities: | |||
Gross Amount Recognized in the Statement of Financial Position | 84,080 | [1] | 86,094 |
Gross Amounts Offset in the Statement of Financial Position | 0 | 0 | |
Net of Amounts Presented in the Statement of Financial Position | 84,080 | 86,094 | |
Commodity Contracts | (19,254) | (17,940) | |
Cash Collateral Posted | (3,943) | (353) | |
Net Amount | 60,883 | 67,801 | |
Subsidiaries [Member] | |||
Liabilities: | |||
Derivative Asset, Current | 23,718 | 22,247 | |
Derivative Liability, Current | 67,513 | 64,859 | |
Derivative Asset, Noncurrent | 3,443 | 2,158 | |
Derivative Liability, Noncurrent | 16,567 | 21,235 | |
Not Designated as Hedging Instrument [Member] | |||
Assets: | |||
Net of Amounts Presented in the Statement of Financial Position | 27,161 | 24,405 | |
Liabilities: | |||
Net of Amounts Presented in the Statement of Financial Position | 84,080 | 86,094 | |
Not Designated as Hedging Instrument [Member] | Electric Portfolio [Member] | |||
Assets: | |||
Net of Amounts Presented in the Statement of Financial Position | 13,150 | 13,391 | |
Liabilities: | |||
Net of Amounts Presented in the Statement of Financial Position | $ 47,813 | $ 49,050 | |
Not Designated as Hedging Instrument [Member] | Natural Gas Derivatives [Member] | |||
Derivative [Line Items] | |||
Derivative, Nonmonetary Notional Amount | MMBTU | 309.1 | 332.1 | |
Not Designated as Hedging Instrument [Member] | Natural Gas Portfolio [Member] | |||
Assets: | |||
Net of Amounts Presented in the Statement of Financial Position | $ 14,011 | $ 11,014 | |
Liabilities: | |||
Net of Amounts Presented in the Statement of Financial Position | 36,267 | 37,044 | |
Not Designated as Hedging Instrument [Member] | Parent Company [Member] | |||
Liabilities: | |||
Derivative Asset, Current | 23,718 | 22,247 | |
Derivative Liability, Current | 67,513 | 64,859 | |
Derivative Asset, Noncurrent | 3,443 | 2,158 | |
Derivative Liability, Noncurrent | $ 16,567 | $ 21,235 | |
[1] | 1 All derivative contract deals are executed under ISDA, NAESB and WSPP master netting agreements with right of set-off. |
Accounting for Derivative Ins29
Accounting for Derivative Instruments and Hedging Activities Recognized in Statement of Income (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Derivative Instruments, (Loss) Gain [Line Items] | ||
Unrealized (gain) loss on derivative instruments | $ (996) | $ 19,288 |
Not Designated as Hedging Instrument [Member] | ||
Derivative Instruments, (Loss) Gain [Line Items] | ||
Unrealized (gain) loss on derivative instruments | 9,069 | 30,613 |
Not Designated as Hedging Instrument [Member] | Other Income (Deductions) [Member] | Interest Expense [Member] | ||
Derivative Instruments, (Loss) Gain [Line Items] | ||
Unrealized (gain) loss on derivative instruments | 0 | (28) |
Not Designated as Hedging Instrument [Member] | Electric generation fuel [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net [Member] | ||
Derivative Instruments, (Loss) Gain [Line Items] | ||
Unrealized (gain) loss on derivative instruments | (2,312) | 16,136 |
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Electric generation fuel [Member] | ||
Derivative Instruments, (Loss) Gain [Line Items] | ||
Unrealized (gain) loss on derivative instruments | 7,676 | 5,198 |
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Purchased Electricity [Member] | ||
Derivative Instruments, (Loss) Gain [Line Items] | ||
Unrealized (gain) loss on derivative instruments | 2,389 | 6,155 |
Not Designated as Hedging Instrument [Member] | Electric [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net [Member] | ||
Derivative Instruments, (Loss) Gain [Line Items] | ||
Unrealized (gain) loss on derivative instruments | $ 1,316 | $ 3,152 |
Accounting for Derivative Ins30
Accounting for Derivative Instruments and Hedging Activities Contractual Contingent Liability (Details) - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 | |
External Credit Rating, Investment Grade [Member] | |||
Derivative [Line Items] | |||
Derivative, Credit Risk Exposure, Percentage | 95.20% | ||
External Credit Rating, Non Investment Grade [Member] | |||
Derivative [Line Items] | |||
Derivative, Credit Risk Exposure, Percentage | 4.80% | ||
Electric Portfolio [Member] | |||
Derivative [Line Items] | |||
Fair Value Liability | [1] | $ 39,957 | $ 40,914 |
Posted Collateral | 6,989 | 2,639 | |
Additional Collateral, Aggregate Fair Value | 2,698 | 3,187 | |
Credit Rating [Member] | |||
Derivative [Line Items] | |||
Posted Collateral | [2] | 7,000 | |
Credit Rating [Member] | Electric Portfolio [Member] | |||
Derivative [Line Items] | |||
Fair Value Liability | [1],[2] | 2,698 | 3,187 |
Posted Collateral | [2] | 0 | 0 |
Additional Collateral, Aggregate Fair Value | [2] | 2,698 | 3,187 |
Credit Rating [Member] | Natural Gas Portfolio [Member] | |||
Derivative [Line Items] | |||
Posted Collateral | [2] | 1,000 | |
Requested Credit for Adequate Assurance [Member] | Electric Portfolio [Member] | |||
Derivative [Line Items] | |||
Fair Value Liability | [1] | 33,316 | 37,374 |
Posted Collateral | 0 | 0 | |
Additional Collateral, Aggregate Fair Value | 0 | 0 | |
Forward Value of Contract [Member] | Electric Portfolio [Member] | |||
Derivative [Line Items] | |||
Fair Value Liability | [1],[3] | 3,943 | 353 |
Posted Collateral | [3] | 6,989 | 2,639 |
Additional Collateral, Aggregate Fair Value | [3] | $ 0 | $ 0 |
[1] | 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] | 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] | 3 Collateral requirements may vary, based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds. |
Fair Value Measurements Debt at
Fair Value Measurements Debt at at Carrying and Fair Value (Details) - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 | |
Liabilities: | |||
Total long-term debt | $ 5,080,669 | $ 5,257,929 | |
Subsidiaries [Member] | |||
Liabilities: | |||
Total long-term debt | 3,356,884 | 3,549,911 | |
Discounted cash flow [Member] | Subsidiaries [Member] | Carrying Value [Member] | |||
Liabilities: | |||
Total long-term debt | 3,556,884 | 3,749,911 | |
Discounted cash flow [Member] | Subsidiaries [Member] | Carrying Value [Member] | Level 2 [Member] | |||
Liabilities: | |||
Junior subordinated notes | 56,553 | 250,000 | |
Long-term debt (fixed-rate), net of discount | [1] | 3,500,331 | 3,499,911 |
Debt issuance costs | [1] | 24,200 | 24,600 |
Discounted cash flow [Member] | Subsidiaries [Member] | Fair Value [Member] | |||
Liabilities: | |||
Total long-term debt | 4,344,771 | 4,789,065 | |
Discounted cash flow [Member] | Subsidiaries [Member] | Fair Value [Member] | Level 2 [Member] | |||
Liabilities: | |||
Junior subordinated notes | 53,319 | 238,935 | |
Long-term debt (fixed-rate), net of discount | [1] | $ 4,291,452 | $ 4,550,130 |
[1] | 1 The carrying value includes debt issuances costs of $27.0 million and $27.9 million for March 31, 2018 and December 31, 2017, respectively, which are not included in fair value. |
Fair Value Measurements Assets
Fair Value Measurements Assets and Liabilities (Details) - USD ($) $ in Thousands | 3 Months Ended | ||||
Mar. 31, 2018 | Mar. 31, 2017 | Dec. 31, 2017 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Long-term Debt, Excluding Current Maturities | $ 5,080,669 | $ 5,257,929 | |||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||||
Balance at beginning of period | 3,021 | $ 1,597 | |||
Included in earnings | [1] | 1,619 | 706 | ||
Included in regulatory assets/liabilities | 4,976 | 2,458 | |||
Settlements | (2,306) | (2,659) | |||
Transferred into Level 3 | (1,837) | 1,635 | |||
Transferred out of Level 3 | 809 | 1,803 | |||
Balance at end of period | 6,282 | 5,540 | |||
Electric Portfolio [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Unrealized Gain (Loss) on Derivatives and Commodity Contracts | 2,000 | 1,800 | |||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||||
Balance at beginning of period | 1,098 | 972 | |||
Included in earnings | [1] | 1,619 | 706 | ||
Included in regulatory assets/liabilities | 0 | 0 | |||
Settlements | (503) | (1,330) | |||
Transferred into Level 3 | (1,837) | 2,189 | |||
Transferred out of Level 3 | 809 | 1,251 | |||
Balance at end of period | 1,186 | 3,788 | |||
Natural Gas Portfolio [Member] | |||||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||||
Balance at beginning of period | 1,923 | 625 | |||
Included in earnings | [1] | 0 | 0 | ||
Included in regulatory assets/liabilities | 4,976 | 2,458 | |||
Settlements | (1,803) | (1,329) | |||
Transferred into Level 3 | 0 | (554) | |||
Transferred out of Level 3 | 0 | 552 | |||
Balance at end of period | 5,096 | $ 1,752 | |||
Subsidiaries [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Long-term Debt, Excluding Current Maturities | 3,356,884 | 3,549,911 | |||
Fair Value, Measurements, Recurring [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets | 27,161 | 24,405 | |||
Derivative Liability | 84,080 | 86,094 | |||
Fair Value, Measurements, Recurring [Member] | Electric Portfolio [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets | 13,150 | 13,391 | |||
Derivative Liability | 47,813 | 49,050 | |||
Fair Value, Measurements, Recurring [Member] | Natural Gas Portfolio [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets | 14,011 | 11,014 | |||
Derivative Liability | 36,267 | 37,044 | |||
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets | 14,475 | 16,839 | |||
Derivative Liability | 77,676 | 81,549 | |||
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Electric Portfolio [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets | 8,483 | 9,866 | |||
Derivative Liability | 44,332 | 46,623 | |||
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Natural Gas Portfolio [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets | 5,992 | 6,973 | |||
Derivative Liability | 33,344 | 34,926 | |||
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets | 12,686 | 7,566 | |||
Derivative Liability | 6,404 | 4,545 | |||
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Electric Portfolio [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets | 4,667 | 3,525 | [2] | ||
Derivative Liability | 3,481 | 2,427 | [2] | ||
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Natural Gas Portfolio [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative Assets | 8,019 | 4,041 | [2] | ||
Derivative Liability | 2,923 | 2,118 | [2] | ||
Carrying Value [Member] | Level 2 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Investments, Fair Value Disclosure | 48,600 | 48,500 | |||
Income Approach Valuation Technique [Member] | Carrying Value [Member] | Parent Company [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Long-term Debt, Excluding Current Maturities | 5,280,669 | 5,457,929 | |||
Income Approach Valuation Technique [Member] | Carrying Value [Member] | Parent Company [Member] | Level 2 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Subordinated Debt Obligations, Fair Value Disclosure | 56,553 | 250,000 | |||
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure | [3] | 5,108,337 | 5,105,329 | ||
Long-term Debt, Variable Rate, Net of Discount, Fair Value Disclosure | [3] | 115,779 | 102,600 | ||
Unamortized Debt Issuance Expense | [3] | 27,000 | 27,900 | ||
Income Approach Valuation Technique [Member] | Carrying Value [Member] | Subsidiaries [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Long-term Debt, Excluding Current Maturities | 3,556,884 | 3,749,911 | |||
Income Approach Valuation Technique [Member] | Carrying Value [Member] | Subsidiaries [Member] | Level 2 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Subordinated Debt Obligations, Fair Value Disclosure | 56,553 | 250,000 | |||
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure | [3] | 3,500,331 | 3,499,911 | ||
Unamortized Debt Issuance Expense | [3] | 24,200 | 24,600 | ||
Income Approach Valuation Technique [Member] | Total [Member] | Parent Company [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Long-term Debt, Excluding Current Maturities | 6,362,919 | 6,862,050 | |||
Income Approach Valuation Technique [Member] | Total [Member] | Parent Company [Member] | Level 2 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Subordinated Debt Obligations, Fair Value Disclosure | 53,319 | 238,935 | |||
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure | [3] | 6,193,821 | 6,520,515 | ||
Long-term Debt, Variable Rate, Net of Discount, Fair Value Disclosure | [3] | 115,779 | 102,600 | ||
Income Approach Valuation Technique [Member] | Total [Member] | Subsidiaries [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Long-term Debt, Excluding Current Maturities | 4,344,771 | 4,789,065 | |||
Income Approach Valuation Technique [Member] | Total [Member] | Subsidiaries [Member] | Level 2 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Subordinated Debt Obligations, Fair Value Disclosure | 53,319 | 238,935 | |||
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure | [3] | $ 4,291,452 | $ 4,550,130 | ||
[1] | 1 Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $2.0 million and $1.8 million for the three months ended March 31, 2018 and 2017. | ||||
[2] | 1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions. | ||||
[3] | 1 The carrying value includes debt issuances costs of $27.0 million and $27.9 million for March 31, 2018 and December 31, 2017, respectively, which are not included in fair value. |
Fair Value Measurements Valuati
Fair Value Measurements Valuation Techniques for Measurement with Unobservable Inputs (Details) | 3 Months Ended | 12 Months Ended |
Mar. 31, 2018USD ($)$ / MMBTU$ / MWh | Dec. 31, 2017USD ($)$ / MMBTU$ / MWh | |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Fair Value measurement, sensitivity analysis, hypothetical increase or decrease of market prices, result on fair value | 10.00% | |
Fair Value Measurements, Sensitivity Analysis, Hypothetical Increase or Decrease of Market Prices, Result on Fair Value | $ 600,000 | $ 900,000 |
Fair Value Inputs, Comparability Adjustments | 39.00% | |
Fair Value, Measurements, Recurring [Member] | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Derivative Assets | $ 27,161,000 | 24,405,000 |
Derivative Liability | $ 84,080,000 | $ 86,094,000 |
Electric Portfolio [Member] | Discounted cash flow [Member] | Low [Member] | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Price (per MWh) | $ / MWh | 11.60 | 7.02 |
Electric Portfolio [Member] | Discounted cash flow [Member] | High [Member] | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Price (per MWh) | $ / MWh | 29.48 | 28.94 |
Electric Portfolio [Member] | Discounted cash flow [Member] | Weighted Average [Member] | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Price (per MWh) | $ / MWh | 22.74 | 18.61 |
Electric Portfolio [Member] | Fair Value, Measurements, Recurring [Member] | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Derivative Assets | $ 13,150,000 | $ 13,391,000 |
Derivative Liability | $ 47,813,000 | $ 49,050,000 |
Natural Gas Portfolio [Member] | Discounted cash flow [Member] | Low [Member] | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Price (per MMBtu) | $ / MMBTU | 0.90 | 1.22 |
Natural Gas Portfolio [Member] | Discounted cash flow [Member] | High [Member] | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Price (per MMBtu) | $ / MMBTU | 2.88 | 2.80 |
Natural Gas Portfolio [Member] | Discounted cash flow [Member] | Weighted Average [Member] | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Price (per MMBtu) | $ / MMBTU | 1.61 | 1.54 |
Natural Gas Portfolio [Member] | Fair Value, Measurements, Recurring [Member] | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Derivative Assets | $ 14,011,000 | $ 11,014,000 |
Derivative Liability | 36,267,000 | 37,044,000 |
Commodity Contract [Member] | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Derivative Assets | 27,161,000 | 24,405,000 |
Derivative Liability | 84,080,000 | $ 86,094,000 |
Wells Project [Member] | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Finite-Lived Intangible Assets, Net | 4,302,000 | |
Impairment of Intangible Assets (Excluding Goodwill) | 1,907,000 | |
Wells Project [Member] | Carrying Value [Member] | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Finite-lived Intangible Assets, Fair Value Disclosure | $ 2,395,000 | |
Wells Project [Member] | Discounted cash flow [Member] | Low [Member] | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Price (per MWh) | $ / MWh | 9.69 | |
Fair Value Inputs, Power Contract Costs | $ 4,126 | |
Wells Project [Member] | Discounted cash flow [Member] | High [Member] | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Price (per MWh) | $ / MWh | 25.30 | |
Fair Value Inputs, Power Contract Costs | $ 4,126 | |
Wells Project [Member] | Discounted cash flow [Member] | Weighted Average [Member] | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Price (per MWh) | $ / MWh | 17.50 | |
Fair Value Inputs, Power Contract Costs | $ 4,126 |
Retirement Benefits Net Periodi
Retirement Benefits Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2018 | Sep. 30, 2016 | Dec. 31, 2016 | |
Qualified Pension Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Contributions by Employer | $ 4,500 | ||
Components of net periodic benefit cost: | |||
Service cost | 5,425 | $ 20,081 | |
Interest cost | 6,780 | 28,373 | |
Supplemental Employee Retirement Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Contributions by Employer | 600 | ||
Components of net periodic benefit cost: | |||
Service cost | 212 | 913 | |
Interest cost | 530 | 2,285 | |
Other Benefit [Member] | |||
Components of net periodic benefit cost: | |||
Service cost | 17 | 72 | |
Interest cost | 110 | $ 500 | |
Parent Company [Member] | Qualified Pension Benefits [Member] | |||
Components of net periodic benefit cost: | |||
Service cost | 5,425 | $ 5,018 | |
Interest cost | 6,780 | 7,099 | |
Expected return on plan assets | (12,559) | (11,951) | |
Amortization of prior service cost | (495) | (495) | |
Amortization of net loss (gain) | 462 | 0 | |
Net periodic benefit cost | (387) | (329) | |
Parent Company [Member] | Supplemental Employee Retirement Plan [Member] | |||
Components of net periodic benefit cost: | |||
Service cost | 212 | 228 | |
Interest cost | 530 | 571 | |
Expected return on plan assets | 0 | 0 | |
Amortization of prior service cost | 11 | 11 | |
Amortization of net loss (gain) | 394 | 269 | |
Net periodic benefit cost | 1,147 | 1,079 | |
Parent Company [Member] | Other Benefit [Member] | |||
Components of net periodic benefit cost: | |||
Service cost | 17 | 20 | |
Interest cost | 110 | 121 | |
Expected return on plan assets | (117) | (115) | |
Amortization of prior service cost | 0 | 0 | |
Amortization of net loss (gain) | (86) | (113) | |
Net periodic benefit cost | (76) | (87) | |
Subsidiaries [Member] | Qualified Pension Benefits [Member] | |||
Components of net periodic benefit cost: | |||
Service cost | 5,425 | 5,018 | |
Interest cost | 6,780 | 7,099 | |
Expected return on plan assets | (12,569) | (11,970) | |
Amortization of prior service cost | (393) | (393) | |
Amortization of net loss (gain) | 3,630 | 3,429 | |
Net periodic benefit cost | 2,873 | 3,183 | |
Subsidiaries [Member] | Supplemental Employee Retirement Plan [Member] | |||
Components of net periodic benefit cost: | |||
Service cost | 212 | 228 | |
Interest cost | 530 | 571 | |
Expected return on plan assets | 0 | 0 | |
Amortization of prior service cost | 11 | 11 | |
Amortization of net loss (gain) | 517 | 392 | |
Net periodic benefit cost | 1,270 | 1,202 | |
Subsidiaries [Member] | Other Benefit [Member] | |||
Components of net periodic benefit cost: | |||
Service cost | 17 | 20 | |
Interest cost | 110 | 121 | |
Expected return on plan assets | (117) | (115) | |
Amortization of prior service cost | 0 | 0 | |
Amortization of net loss (gain) | (142) | (173) | |
Net periodic benefit cost | $ (132) | $ (147) |
Retirement Benefits Change in N
Retirement Benefits Change in Net Benefit Obligation (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended |
Mar. 31, 2018 | Dec. 31, 2016 | |
Qualified Pension Benefits [Member] | ||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | ||
Benefit obligation at beginning of period | $ 652,607 | |
Service cost | $ 5,425 | 20,081 |
Interest cost | 6,780 | 28,373 |
Actuarial loss/(gain) | 0 | 40,945 |
Benefits paid | (10,650) | (40,594) |
Medicare part D subsidiary received | 0 | 0 |
Administrative Expense | 0 | (931) |
Benefit obligation at end of period | 702,036 | 700,481 |
Supplemental Employee Retirement Plan [Member] | ||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | ||
Benefit obligation at beginning of period | 51,734 | |
Service cost | 212 | 913 |
Interest cost | 530 | 2,285 |
Actuarial loss/(gain) | 0 | 2,722 |
Benefits paid | (592) | (1,900) |
Medicare part D subsidiary received | 0 | 0 |
Administrative Expense | 0 | 0 |
Benefit obligation at end of period | 55,904 | 55,754 |
Other Benefit [Member] | ||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | ||
Benefit obligation at beginning of period | 11,194 | |
Service cost | 17 | 72 |
Interest cost | 110 | 500 |
Actuarial loss/(gain) | 0 | 725 |
Benefits paid | (279) | (1,137) |
Medicare part D subsidiary received | 0 | 100 |
Administrative Expense | 0 | 0 |
Benefit obligation at end of period | $ 11,302 | $ 11,454 |
Retirement Benefits Activity (D
Retirement Benefits Activity (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2018 | Dec. 31, 2018 | |
Qualified Pension Benefits [Member] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Plan Assets, Contributions by Employer | $ 4.5 | |
Supplemental Employee Retirement Plan [Member] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Plan Assets, Contributions by Employer | $ 0.6 | |
Subsidiaries [Member] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Contribution Plan, Employer Additional Contribution of Base Pay, Percentage | 4.00% | |
Defined Contribution Plan, Employer Matching Contribution, Percent | 1.00% | |
Scenario, Forecast [Member] | Qualified Pension Benefits [Member] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Aggregate expected contributions | $ 18 | |
Scenario, Forecast [Member] | Supplemental Employee Retirement Plan [Member] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Aggregate expected contributions | 5.5 | |
Scenario, Forecast [Member] | Other Benefit [Member] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Aggregate expected contributions | $ 0.3 |
Regulation and Rates (Details)
Regulation and Rates (Details) $ in Thousands | Dec. 29, 2017USD ($) | Dec. 19, 2017USD ($) | Jan. 13, 2017 | Jan. 01, 2017 | Mar. 31, 2018USD ($) | Mar. 31, 2017USD ($) | Apr. 30, 2018USD ($) | Dec. 31, 2017USD ($) | Jan. 01, 2018USD ($) | Dec. 31, 2016USD ($) |
Regulatory Assets [Line Items] | ||||||||||
Income tax (benefit) expense | $ 11,803 | $ 62,543 | $ 27,400 | |||||||
Subsidiaries [Member] | ||||||||||
Regulatory Assets [Line Items] | ||||||||||
Public Utilities, Rate Case, Deferred Storm Costs Threshold | $ 10,000 | |||||||||
Public Utilities, Rate Case, Deferred Storm Qualifying Costs | 500 | |||||||||
Income tax (benefit) expense | 21,691 | 71,798 | ||||||||
Subsidiaries [Member] | Electric [Member] | ||||||||||
Regulatory Assets [Line Items] | ||||||||||
Storm Damage Costs Incurred During Period | 5,700 | 26,400 | ||||||||
Storm Damage Costs Deferred During Period | 0 | $ 8,800 | ||||||||
Public Utilities, Rate Case, Deferred Storm Costs Threshold | $ 8,000 | |||||||||
Decoupling Mechanism [Member] | ||||||||||
Regulatory Assets [Line Items] | ||||||||||
Deferred Revenue, Revenue Recognized | $ 20,800 | |||||||||
Decoupling Mechanism [Member] | Subsidiaries [Member] | Natural Gas [Member] | ||||||||||
Regulatory Assets [Line Items] | ||||||||||
Public Utilities, Approved Rate Increase (Decrease), Percentage | 2.20% | |||||||||
Decoupling Mechanism [Member] | Subsidiaries [Member] | Electric [Member] | ||||||||||
Regulatory Assets [Line Items] | ||||||||||
Public Utilities, Approved Rate Increase (Decrease), Percentage | 3.00% | |||||||||
Decoupling Mechanism [Member] | Maximum [Member] | Natural Gas [Member] | ||||||||||
Regulatory Assets [Line Items] | ||||||||||
Public Utilities, Approved Rate Increase (Decrease), Percentage | 5.00% | |||||||||
Decoupling Mechanism [Member] | Maximum [Member] | Subsidiaries [Member] | ||||||||||
Regulatory Assets [Line Items] | ||||||||||
Public Utilities, Approved Rate Increase (Decrease), Percentage | 3.00% | |||||||||
Decoupling Mechanism [Member] | Maximum [Member] | Subsidiaries [Member] | Natural Gas [Member] | ||||||||||
Regulatory Assets [Line Items] | ||||||||||
Public Utilities, Approved Rate Increase (Decrease), Percentage | 3.00% | |||||||||
General Rate Case [Member] | Subsidiaries [Member] | ||||||||||
Regulatory Assets [Line Items] | ||||||||||
Number of new mechanisms | 2 | |||||||||
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities | 7.60% | |||||||||
Regulated Utility, After-tax Allowed Rate of Return on Net Regulatory Assets and Liabilities | 6.55% | |||||||||
Public Utilities, Requested Equity Capital Structure, Percentage | 48.50% | |||||||||
Public Utilities, Requested Return on Equity, Percentage | 9.50% | |||||||||
General Rate Case [Member] | Subsidiaries [Member] | Natural Gas [Member] | ||||||||||
Regulatory Assets [Line Items] | ||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount | $ (35,500) | |||||||||
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage | (3.80%) | |||||||||
General Rate Case [Member] | Subsidiaries [Member] | Electric [Member] | ||||||||||
Regulatory Assets [Line Items] | ||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount | $ 20,200 | |||||||||
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage | 0.90% | |||||||||
Tax Cuts and Jobs Act [Member] | Subsidiaries [Member] | Natural Gas [Member] | ||||||||||
Regulatory Assets [Line Items] | ||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount | $ (23,600) | |||||||||
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage | (3.00%) | |||||||||
Tax Cuts and Jobs Act [Member] | Subsidiaries [Member] | Electric [Member] | ||||||||||
Regulatory Assets [Line Items] | ||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount | $ (72,900) | |||||||||
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage | (3.50%) | |||||||||
Colstrip Regulatory Asset [Domain] | ||||||||||
Regulatory Assets [Line Items] | ||||||||||
Regulatory Assets | $ 127,800 | $ 127,600 |
Commitments and Contingencies (
Commitments and Contingencies (Details) $ in Millions | Mar. 28, 2017USD ($) | Mar. 31, 2018USD ($) | Dec. 31, 2016USD ($) |
Loss Contingencies [Line Items] | |||
Loss Contingency, Damages Awarded, Value | $ 1.5 | ||
Colstrip Units 3 and 4 [Member] | |||
Loss Contingencies [Line Items] | |||
Ownership interest (percent) | 25.00% | ||
Colstrip Units 1 and 2 [Member] | |||
Loss Contingencies [Line Items] | |||
Ownership interest (percent) | 50.00% | ||
Jointly Owned Utility Plant | 2 | ||
Colstrip Regulatory Asset [Domain] | |||
Loss Contingencies [Line Items] | |||
Regulatory Assets | $ 127.8 | $ 127.6 |