Cover Page
Cover Page - USD ($) | 12 Months Ended | ||
Dec. 31, 2019 | Feb. 21, 2020 | Jun. 28, 2019 | |
Cover page. | |||
Entity Registrant Name | NORTHERN STATES POWER CO | ||
Entity Central Index Key | 0001123852 | ||
Current Fiscal Year End Date | --12-31 | ||
Document Fiscal Year Focus | 2019 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
Document Type | 10-K | ||
Document Annual Report | true | ||
Document Period End Date | Dec. 31, 2019 | ||
Document Transition Report | false | ||
Entity File Number | 001-31387 | ||
Entity Tax Identification Number | 41-1967505 | ||
Entity Incorporation, State or Country Code | MN | ||
Entity Address, Address Line One | 414 Nicollet Mall | ||
Entity Address, City or Town | Minneapolis | ||
Entity Address, State or Province | MN | ||
Entity Address, Postal Zip Code | 55401 | ||
City Area Code | (612) | ||
Local Phone Number | 330-5500 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Interactive Data Current | Yes | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false | ||
Entity Shell Company | false | ||
Entity Public Float | $ 0 | ||
Entity Common Stock, Shares Outstanding | 1,000,000 |
CONSOLIDATED STATEMENTS OF INCO
CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Operating revenues | |||
Regulated and Unregulated Operating Revenue | $ 5,111.8 | $ 5,121.9 | $ 5,102 |
Operating expenses | |||
Cost of natural Gas Sold and Transported | 327.2 | 345.1 | 301.8 |
Cost of sales — other | 23.2 | 19.7 | 18.1 |
Operating and maintenance expenses | 1,203.1 | 1,223.3 | 1,198.3 |
Conservation program expenses | 119.7 | 118 | 120.1 |
Depreciation and amortization | 791.3 | 741.6 | 700.6 |
Taxes (other than income taxes) | 260.1 | 256.6 | 253.5 |
Total operating expenses | 4,324.9 | 4,405.4 | 4,219.3 |
Operating income | 786.9 | 716.5 | 882.7 |
Interest charges and financing costs | |||
Interest charges — includes other financing costs of $7.4, $7.4 and $7.3 respectively | 233.3 | 226.8 | 228.4 |
Public Utilities, Allowance For Funds Used During Construction, Capitalized Cost Of Debt | (12.4) | (12.5) | (15.1) |
Total interest charges and financing costs | 220.9 | 214.3 | 213.3 |
Other income, net | (0.8) | (6.5) | (9.1) |
Allowance for funds used during construction — equity | 24.8 | 23.8 | 29.5 |
Income before income taxes | 590 | 519.5 | 689.8 |
Income taxes | 47.4 | 27.2 | 199.7 |
Net income | 542.6 | 492.3 | 490.1 |
Electricity, US Regulated | |||
Operating expenses | |||
Cost of Goods and Services Sold | 1,600.3 | 1,701.1 | 1,626.9 |
Natural Gas, US Regulated | |||
Operating revenues | |||
Total operating revenues | 571.3 | 583.1 | 531.9 |
Product and Service, Other [Member] | |||
Operating revenues | |||
Total operating revenues | 33.9 | 30.8 | 28.4 |
Related Party Transaction, Electric Domestic Regulated Revenue [Member] | |||
Operating revenues | |||
Total operating revenues | 457.4 | 473.7 | 490.2 |
Non-Related Party Transaction, Electric Domestic Regulated Revenue [Member] | Electricity, US Regulated | |||
Operating revenues | |||
Total operating revenues | $ 4,049.2 | $ 4,034.3 | $ 4,051.5 |
CONSOLIDATED STATEMENTS OF IN_2
CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Interest charges and financing costs | |||
Other financing costs | $ 7.4 | $ 7.4 | $ 7.3 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Comprehensive income: | |||
Net income | $ 542.6 | $ 492.3 | $ 490.1 |
Defined pension and other postretirement benefits: | |||
Net pension and retiree medical (loss) gain arising during the period, net of tax of $(0.1), $0.3 and $(0.4), respectively | (0.4) | 0.6 | (0.5) |
Reclassification of loss to net income, net of tax of $0.1, $0.1 and $0.1, respectively | 0.2 | 0.2 | 0.1 |
Derivative instruments: | |||
Net fair value increase, net of tax of $0 | 0 | 0 | 0.1 |
Reclassification of loss to net income, net of tax of $0.3, $0.3 and $0.6, respectively | 0.8 | 0.7 | 0.9 |
Net fair value decrease, net of tax of $0 | 0 | (0.1) | 0 |
Other comprehensive income | 0.6 | 1.4 | 0.6 |
Comprehensive income | $ 543.2 | $ 493.7 | $ 490.7 |
CONSOLIDATED STATEMENTS OF CO_2
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Pension and retiree medical benefits: | |||
Net pension and retiree medical benefit gains arising during the period, tax | $ 300 | $ (400) | $ (500) |
Amortization of losses included in net periodic benefit cost, tax | 100 | 100 | 0 |
Derivative instruments: | |||
Net fair value (decrease) increase, tax | 0 | 0 | 0 |
Reclassification of losses to net income, tax | 300 | 600 | 600 |
Income taxes | 47,400 | 27,200 | 199,700 |
Other Comprehensive Income (Loss), Securities, Available-for-Sale, Unrealized Holding Gain (Loss) Arising During Period, Tax | 0 | 0 | $ 0 |
Gains and Losses on Cash Flow Hedges | Amounts Reclassified from Accumulated Other Comprehensive Loss | |||
Derivative instruments: | |||
Net fair value (decrease) increase, tax | 0 | 0 | |
Income taxes | 300 | 300 | |
Reclassification from AOCI, Current Period, Tax | 0 | 0 | |
Defined Benefit Pension and Postretirement Items | Amounts Reclassified from Accumulated Other Comprehensive Loss | |||
Derivative instruments: | |||
Net fair value (decrease) increase, tax | (100) | 300 | |
Income taxes | 0 | 0 | |
Reclassification from AOCI, Current Period, Tax | $ 100 | $ 100 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Operating activities | |||
Net income | $ 542.6 | $ 492.3 | $ 490.1 |
Adjustments to reconcile net income to cash provided by operating activities: | |||
Depreciation and amortization | 798.3 | 748.1 | 707 |
Nuclear fuel amortization | 119 | 121.9 | 114.4 |
Deferred income taxes | (39) | 41.3 | 193.2 |
Allowance for equity funds used during construction | (24.8) | (23.8) | (29.5) |
Provision for bad debts | 13 | 16.2 | 15.7 |
Net realized and unrealized hedging and derivative transactions | 18.5 | 27 | (2.8) |
Changes in operating assets and liabilities: | |||
Accounts receivable | 15 | (42.7) | (29.8) |
Accrued unbilled revenues | 19.6 | 7.4 | (18.1) |
Inventories | (28.7) | (21.4) | 7.6 |
Other current assets | (3.3) | 94.4 | (25.3) |
Accounts payable | (12.5) | 10.5 | 46.5 |
Net regulatory assets and liabilities | (139.7) | 182.3 | (36.4) |
Other current liabilities | (11.7) | (64) | (71.8) |
Pension and other employee benefit obligations | (48.5) | (75.8) | (56.7) |
Other, net | (48.9) | (31.5) | (31.3) |
Net cash provided by operating activities | 1,168.9 | 1,482.2 | 1,272.8 |
Investing activities | |||
Utility capital/construction expenditures | (1,416.9) | (1,149.7) | (987.2) |
Purchases of investment securities | (995.1) | (852.9) | (1,690.5) |
Proceeds from the sale of investment securities | 975 | 832.6 | 1,668.9 |
Investments in utility money pool arrangement | (219) | (805) | (122) |
Repayments from utility money pool arrangement | 219 | 805 | 122 |
Other, net | (3.1) | (3.5) | (3.5) |
Net cash used in investing activities | (1,440.1) | (1,173.5) | (1,012.3) |
Financing activities | |||
(Repayments of) proceeds from short-term borrowings, net | (120) | 130 | (65) |
Borrowings under utility money pool arrangement | 696 | 479 | 838 |
Repayments under utility money pool arrangement | (696) | (564) | (753) |
Proceeds from issuance of long-term debt | 579.8 | 0 | 585.2 |
Repayments of long-term debt, including reacquisition premiums | 0 | 0 | (507.9) |
Capital contributions from parent | 354.3 | 108.8 | 145 |
Dividends paid to parent | (466.6) | (456.3) | (506.6) |
Net cash provided by (used in) financing activities | 347.5 | (302.5) | (264.3) |
Net change in cash, cash equivalents and restricted cash | 76.3 | 6.2 | (3.8) |
Cash, cash equivalents and restricted cash at beginning of period | 50 | 43.8 | 47.6 |
Cash, cash equivalents and restricted cash at end of period | 126.3 | 50 | 43.8 |
Supplemental disclosure of cash flow information: | |||
Cash paid for interest (net of amounts capitalized) | (208.9) | (207.4) | (214.2) |
Cash (paid) received for income taxes, net | 104.5 | (89) | 70.9 |
Supplemental disclosure of non-cash investing transactions: | |||
Accrued property, plant and equipment additions | 94.5 | 92.5 | 93.1 |
Inventory transfers to plant, property and equipment | 23.5 | 60.8 | 17.3 |
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability | 628.5 | 0 | 0 |
Allowances for equity funds used during construction | $ 24.8 | $ 23.8 | $ 29.5 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | |
Current assets | |||
Cash and cash equivalents | $ 126.3 | $ 50 | |
Accounts receivable, net | 359.8 | 380.9 | |
Accounts receivable from affiliates | 43.8 | 11 | |
Accrued unbilled revenues | 250.7 | 270.3 | |
Inventories | 304.8 | 299.4 | |
Regulatory assets | 320.1 | 280.3 | |
Derivative instruments | 32.5 | 25.8 | |
Prepayments and other | 31.5 | 28.9 | |
Total current assets | 1,469.5 | 1,346.6 | |
Property, plant and equipment | 14,244 | 13,541.7 | |
Other assets | |||
Nuclear decommissioning fund and other investments | 2,495.2 | 2,107.2 | |
Regulatory assets | 1,125 | 1,454.1 | |
Derivative instruments | 9.2 | 17 | |
Operating Lease, Right-of-Use Asset | 563.8 | 0 | |
Other | 9.7 | 3.3 | |
Total other assets | 4,202.9 | 3,581.6 | |
Total assets | 19,916.4 | 18,469.9 | |
Current liabilities | |||
Long-term Debt, Current Maturities | 300 | 0 | |
Short-term debt | 30 | 150 | |
Accounts payable | 388 | 393.6 | |
Accounts payable to affiliates | 76 | 109.7 | |
Regulatory liabilities | [1] | 141 | 262.4 |
Taxes accrued | 232.1 | 230.1 | |
Accrued interest | 72.2 | 67.2 | |
Dividends payable to parent | 94.3 | 82.7 | |
Derivative instruments | 25 | 16.5 | |
Customer Deposits, Current | 46.4 | 53.7 | |
Operating Lease, Liability, Current | 79.9 | 0 | |
Other | 154.9 | 154.8 | |
Total current liabilities | 1,639.8 | 1,520.7 | |
Deferred credits and other liabilities | |||
Deferred income taxes | 1,779.1 | 1,682.4 | |
Deferred investment tax credits | 19.7 | 21.1 | |
Regulatory liabilities | [1] | 1,937.1 | 1,984.7 |
Asset retirement obligations | 2,280.3 | 2,177.9 | |
Derivative instruments | 110.2 | 112.2 | |
Pension and employee benefit obligations | 235.9 | 305.1 | |
Operating Lease, Liability, Noncurrent | 525.7 | 0 | |
Other | 85.5 | 155.5 | |
Total deferred credits and other liabilities | 6,973.5 | 6,438.9 | |
Capitalization | |||
Long-term debt | 5,221.3 | 4,937.2 | |
Common stock — 5,000,000 shares authorized of $0.01 par value; 1,000,000 shares outstanding at Dec. 31, 2019 and 2018, respectively | 0 | 0 | |
Additional paid in capital | 4,067.9 | 3,624.2 | |
Retained earnings | 2,036.4 | 1,972 | |
Accumulated other comprehensive loss | (22.5) | (23.1) | |
Total common stockholder’s equity | 6,081.8 | 5,573.1 | |
Total liabilities and equity | $ 19,916.4 | $ 18,469.9 | |
[1] | Revenue subject for refund of $23.8 million and $12.5 million for 2019 and 2018, respectively, is included in other current liabilities. |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares | Dec. 31, 2019 | Dec. 31, 2018 |
Capitalization | ||
Common stock, shares authorized (in shares) | 5,000,000 | 5,000,000 |
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares outstanding (in shares) | 1,000,000 | 1,000,000 |
CONSOLIDATED STATEMENTS OF COMM
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY - USD ($) $ in Millions | Total | Common stock | Additional Paid In Capital | Retained Earnings | AOCI Attributable to Parent |
Beginning balance at Dec. 31, 2016 | $ 5,355.6 | $ 0 | $ 3,435.1 | $ 1,941.3 | $ (20.8) |
Balance (in shares) at Dec. 31, 2016 | 1,000,000 | ||||
Increase (Decrease) in Stockholder's Equity | |||||
Net income | 490.1 | 490.1 | |||
Other comprehensive income (loss) | 0.6 | 0.6 | |||
Common dividends declared to parent | (515.8) | (515.8) | |||
Contribution of capital by parent | 145.1 | 145.1 | |||
Adoption of ASU No. 2018-02 (a) | 4.3 | (4.3) | |||
Ending balance at Dec. 31, 2017 | 5,475.6 | $ 0 | 3,580.2 | 1,919.9 | (24.5) |
Balance (in shares) at Dec. 31, 2017 | 1,000,000 | ||||
Increase (Decrease) in Stockholder's Equity | |||||
Net income | 492.3 | 492.3 | |||
Other comprehensive income (loss) | 1.4 | 1.4 | |||
Common dividends declared to parent | (440.2) | (440.2) | |||
Contribution of capital by parent | 44 | 44 | |||
Ending balance at Dec. 31, 2018 | $ 5,573.1 | $ 0 | 3,624.2 | 1,972 | (23.1) |
Balance (in shares) at Dec. 31, 2018 | 1,000,000 | 1,000,000 | |||
Increase (Decrease) in Stockholder's Equity | |||||
Net income | $ 542.6 | 542.6 | |||
Other comprehensive income (loss) | 0.6 | 0.6 | |||
Common dividends declared to parent | (478.2) | (478.2) | |||
Contribution of capital by parent | 443.7 | 443.7 | |||
Ending balance at Dec. 31, 2019 | $ 6,081.8 | $ 0 | $ 4,067.9 | $ 2,036.4 | $ (22.5) |
Balance (in shares) at Dec. 31, 2019 | 1,000,000 | 1,000,000 |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2019 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | neral — NSP-Minnesota is engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and in the regulated purchase, transportation, distribution and sale of natural gas. NSP-Minnesota’s consolidated financial statements include its wholly-owned subsidiaries. In the consolidation process, all intercompany transactions and balances are eliminated. NSP-Minnesota has investments in certain plants and transmission facilities jointly owned with nonaffiliated utilities. NSP-Minnesota’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets and NSP-Minnesota’s proportionate share of the operating costs associated with these facilities is included in its consolidated statements of income. NSP-Minnesota’s consolidated financial statements are presented in accordance with GAAP. All of NSP-Minnesota’s underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions. Certain amounts in the 2018 and 2017 consolidated financial statements or notes have been reclassified to conform to the 2019 presentation for comparative purposes; however, such reclassifications did not affect net income, total assets, liabilities, equity or cash flows. NSP-Minnesota has evaluated events occurring after Dec. 31, 2019 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. Use of Estimates — NSP-Minnesota uses estimates based on the best information available in recording transactions and balances resulting from business operations. Estimates are used on items such as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. Recorded estimates are revised when better information becomes available or actual amounts can be determined. Revisions can affect operating results. Regulatory Accounting — NSP-Minnesota accounts for income and expense items in accordance with accounting guidance for regulated operations. Under this guidance: • Certain costs, which would otherwise be charged to expense or other comprehensive income, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and • Certain credits, which would otherwise be reflected as income or other comprehensive income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred. Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process. If changes in the regulatory environment occur, NSP-Minnesota may no longer be eligible to apply this accounting treatment, and may be required to eliminate regulatory assets and liabilities from its balance sheet. Such changes could have a material effect on NSP-Minnesota’s results of operations, financial condition and cash flows. See Note 4 for further information. Income Taxes — NSP-Minnesota accounts for income taxes using the asset and liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. NSP-Minnesota defers income taxes for all temporary differences between pretax financial and taxable income and between the book and tax bases of assets and liabilities. NSP-Minnesota uses rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the period that includes the enactment date. The effects of NSP-Minnesota’s tax rate changes are generally subject to a normalization method of accounting. Therefore, the revaluation of most of its net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability, which will be refundable to utility customers over the remaining life of the related assets. A tax rate increase would result in the establishment of a similar regulatory asset. Reversal of certain temporary differences are accounted for as current income tax expense due to the effects of past regulatory practices, when deferred taxes were not required to be recorded due to the use of flow through accounting for ratemaking purposes. Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of regulatory assets and liabilities related to income taxes. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. NSP-Minnesota follows the applicable accounting guidance to measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns. NSP-Minnesota recognizes a tax position in its consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position. Recognition of changes in uncertain tax positions are reflected as a component of income tax expense. NSP-Minnesota reports interest and penalties related to income taxes within the other income and interest charges in the consolidated statements of income. Xcel Energy Inc. and its subsidiaries, including NSP-Minnesota, file consolidated federal income tax returns as well as consolidated or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to its subsidiaries based on separate company computations. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with consolidated state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries. See Note 7 for further information. Property, Plant and Equipment and Depreciation in Regulated Operations — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property. Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary. NSP-Minnesota records depreciation expense using the straight-line method over the plant’s useful life. Actuarial life studies are performed and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.7% for 2019, 3.6% for 2018 and 3.6% for 2017. See Note 3 for further information. AROs — NSP-Minnesota accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion, and the capitalized costs are depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO. NSP-Minnesota also recovers through rates certain future plant removal costs in addition to AROs. The accumulated removal costs for these obligations are reflected in the consolidated balance sheets as a regulatory liability. See Note 10 for further information. Nuclear Decommissioning — Nuclear decommissioning studies that estimate NSP-Minnesota’s costs of decommissioning its nuclear power plants are performed at least every three years and submitted to the state commissions for approval. For ratemaking purposes, NSP-Minnesota recovers regulator-approved decommissioning costs of its nuclear power plants over each facility’s expected service life, typically based on the triennial decommissioning studies. The studies consider estimated future costs of decommissioning and the market value of investments in trust funds and recommend annual funding amounts. Amounts collected in rates are deposited in the trust funds. For financial reporting purposes, NSP-Minnesota accounts for nuclear decommissioning as an ARO. Restricted funds for the payment of future decommissioning expenditures for NSP-Minnesota’s nuclear facilities are included in nuclear decommissioning fund and other assets on the consolidated balance sheets. See Notes 8 and 10 for further information. Benefit Plans and Other Postretirement Benefits — NSP-Minnesota maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans requires management to make various assumptions and estimates. Certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are deferred as regulatory assets and liabilities, rather than recorded as other comprehensive income, based on regulatory recovery mechanisms. See Note 9 for further information. Environmental Costs — Environmental costs are recorded when it is probable NSP-Minnesota is liable for remediation costs and the liability can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant. Estimated remediation costs are regularly adjusted as estimates are revised and remediation proceeds. If other participating potentially responsible parties exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for NSP-Minnesota’s expected share of the cost. Future costs of restoring sites are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability. See Note 10 for further information. Revenue from Contracts with Customers — Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. NSP-Minnesota recognizes revenue that corresponds to the price of the energy delivered to the customer. The measurement of energy sales to customers is generally based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recognized. NSP-Minnesota does not recognize a separate financing component of its collections from customers as contract terms are short-term in nature. NSP-Minnesota presents its revenues net of any excise or sales taxes or fees. NSP-Minnesota recognizes sales to both native load and other end use customers on a gross basis in electric revenues and cost of sales. Revenues and charges for short term wholesale sales of excess energy transacted through RTOs are also recorded on a gross basis. Other RTO revenues and charges are recorded on a net basis in cost of sales. NSP-Minnesota has various rate-adjustment mechanisms that provide for the recovery of natural gas, electric fuel and purchased energy costs. Cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred. When applicable, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets. See Note 6 for further information. Cash and Cash Equivalents — NSP-Minnesota considers investments in instruments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. NSP-Minnesota establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers. As of Dec. 31, 2019 and 2018, the allowance for bad debts was $23.0 million and $23.5 million , respectively. Inventory — Inventory is recorded at average cost and consisted of the following: (Millions of Dollars) Dec. 31, 2019 Dec. 31, 2018 Inventories Materials and supplies $ 175.6 $ 176.3 Fuel 103.2 88.5 Natural gas 26.0 34.6 Total inventories $ 304.8 $ 299.4 Fair Value Measurements — NSP-Minnesota presents cash equivalents, interest rate derivatives, commodity derivatives and nuclear decommissioning fund assets at estimated fair values in its consolidated financial statements. Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted NAVs. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used to establish fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price, NSP-Minnesota may use quoted prices for similar contracts or internally prepared valuation models to determine fair value. For the pension and postretirement plan assets and nuclear decommissioning fund, published trading data and pricing models, generally using the most observable inputs available, are utilized to estimate fair value for each security. See Notes 8 and 9 for further information. Derivative Instruments — NSP-Minnesota uses derivative instruments in connection with its interest rate, utility commodity price, vehicle fuel price and commodity trading activities, including forward contracts, futures, swaps and options. Any derivative instruments not qualifying for the normal purchases and normal sales exception are recorded on the consolidated balance sheets at fair value as derivative instruments. Classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues; hedging transactions for vehicle fuel costs are recorded as a component of capital projects and O&M costs; and interest rate hedging transactions are recorded as a component of interest expense. Normal Purchases and Normal Sales — NSP-Minnesota enters into contracts for purchases and sales of commodities for use in its operations. At inception, contracts are evaluated to determine whether a derivative exists and/or whether an instrument may be exempted from derivative accounting if designated as a normal purchase or normal sale. See Note 8 for further information. Commodity Trading Operations — All applicable gains and losses related to commodity trading activities are shown on a net basis in electric operating revenues in the consolidated statements of income. Commodity trading activities are not associated with energy produced from NSP-Minnesota’s generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms. See Note 8 for further information. Other Utility Items AFUDC — AFUDC represents the cost of capital used to finance utility construction activity. AFUDC is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in NSP-Minnesota’s rate base for establishing utility rates. Alternative Revenue — Certain rate rider mechanisms (including decoupling and CIP programs) qualify as alternative revenue programs. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate. When certain criteria are met, including expected collection within 24 months , revenue is recognized equal to the revenue requirement, which may include incentives and return on rate base items. Billing amounts are revised periodically for differences between total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers. See Note 6 for further information. Conservation Programs — Costs incurred for CIP programs are deferred if it is probable future revenue will recover the incurred cost. Revenues recognized for incentive programs for the recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the year they are earned. Regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers. Emission Allowances — Emission allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emission allowances and sales of these allowances are included in electric revenues. Nuclear Refueling Outage Costs — NSP-Minnesota uses a deferral and amortization method for nuclear refueling costs. This method amortizes costs over the period between refueling outages consistent with rate recovery. RECs — Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. Sales of RECs are recorded in electric revenues on a gross basis. The cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense. |
Accounting Pronouncements
Accounting Pronouncements | 12 Months Ended |
Dec. 31, 2019 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
Accounting Pronouncements | Recently Issued Credit Losses — In 2016, the FASB issued Financial Instruments - Credit Losses, Topic 326 (ASC Topic 326), which changes how entities account for losses on receivables and certain other assets. The guidance requires use of a current expected credit loss model, which may result in earlier recognition of credit losses than under previous accounting standards. ASC Topic 326 is effective for interim and annual periods beginning on or after Dec. 15, 2019, and will be applied using a modified-retrospective approach, with a cumulative-effect adjustment to retained earnings as of Jan. 1, 2020. NSP-Minnesota expects the impact of adoption of the new standard to include first-time recognition of expected credit losses (i.e., bad debt expense) on unbilled revenues, with the initial allowance established at Jan. 1, 2020 charged to retained earnings. Recognition of this allowance and other impacts of adoption are expected to be immaterial to the consolidated financial statements. Recently Adopted Leases — In 2016, the FASB issued Leases , Topic 842 (ASC Topic 842) , which provides new accounting and disclosure guidance for leasing activities, most significantly requiring that operating leases be recognized on the balance sheet. NSP-Minnesota adopted the guidance on Jan. 1, 2019 utilizing the package of transition practical expedients provided by the new standard, including carrying forward prior conclusions on whether agreements existing before the adoption date contain leases and whether existing leases are operating or finance leases; ASC Topic 842 refers to capital leases as finance leases. Specifically for land easement contracts, NSP-Minnesota has elected the practical expedient provided by ASU No. 2018-01 Leases: Land Easement Practical Expedient for Transition to Topic 842 , and as a result, only those easement contracts entered on or after Jan. 1, 2019 will be evaluated to determine if lease treatment is appropriate. NSP-Minnesota also utilized the transition practical expedient offered by ASU No. 2018-11 Leases: Targeted Improvements to implement the standard on a prospective basis. As a result, reporting periods in the consolidated financial statements beginning Jan. 1, 2019 reflect the implementation of ASC Topic 842, while prior periods continue to be reported in accordance with Leases, Topic 840 (ASC Topic 840) . Other than first-time recognition of operating leases on its consolidated balance sheet, the implementation of ASC Topic 842 did not have a significant impact on NSP-Minnesota’s consolidated financial statements. Adoption resulted in recognition of approximately $0.5 billion of operating lease ROU assets and current/noncurrent operating lease liabilities. See Note 10 for leasing disclosures. |
Property Plant and Equipment Pr
Property Plant and Equipment Property Plant and Equipment | 12 Months Ended |
Dec. 31, 2019 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment Disclosure | Major classes of property, plant and equipment (Millions of Dollars) Dec. 31, 2019 Dec. 31, 2018 Property, plant and equipment Electric plant $ 18,519.5 $ 17,749.3 Natural gas plant 1,562.9 1,475.5 Common and other property 886.7 803.1 CWIP 846.3 615.1 Total property, plant and equipment 21,815.4 20,643.0 Less accumulated depreciation (7,945.3 ) (7,454.8 ) Nuclear fuel 2,909.8 2,770.4 Less accumulated amortization (2,535.9 ) (2,416.9 ) Property, plant and equipment, net $ 14,244.0 $ 13,541.7 Joint Ownership of Generation and Transmission Facilities Jointly owned assets as of Dec. 31, 2019 : (Millions of Dollars) Plant in Service Accumulated Depreciation CWIP Percent Owned Electric generation: Sherco Unit 3 $ 603.0 $ 426.3 $ 3.8 59 % Sherco common facilities 144.7 102.7 1.9 80 Sherco substation 4.8 3.5 — 59 Electric transmission: CapX2020 972.5 91.6 2.2 51 Grand Meadow 10.7 2.6 — 50 Total $ 1,735.7 $ 626.7 $ 7.9 NSP-Minnesota’s share of operating expenses and construction expenditures is included in the applicable utility accounts. Respective owners are responsible for providing their own financing. |
Regulatory Assets and Liabiliti
Regulatory Assets and Liabilities | 12 Months Ended |
Dec. 31, 2019 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Regulatory Assets and Liabilities | gulatory assets and liabilities are created for amounts that regulators may allow to be collected or may require to be paid back to customers in future electric and natural gas rates. NSP-Minnesota would be required to recognize the write-off of regulatory assets and liabilities in net income or other comprehensive income if changes in the utility industry no longer allow for the application of regulatory accounting guidance under GAAP. Components of regulatory assets: (Millions of Dollars) See Note(s) Remaining Amortization Period Dec. 31, 2019 Dec. 31, 2018 Regulatory Assets Current Noncurrent Current Noncurrent Pension and retiree medical obligations 9 Various $ 27.5 $ 377.7 $ 28.1 $ 424.3 Excess deferred taxes — TCJA 7 Various 10.4 132.2 — 153.3 Net AROs (a) 1, 10 Plant lives — 117.9 — 323.4 Recoverable deferred taxes on AFUDC recorded in plant Plant lives — 114.8 — 117.6 Benson biomass PPA termination and asset purchase Ten years 9.4 72.7 9.8 85.8 Contract valuation adjustments (b) 1, 8 Term of related contract 15.5 62.1 14.1 76.0 Laurentian biomass PPA termination Five years 19.2 53.9 18.1 73.3 PI extended power update Sixteen years 3.1 52.6 3.1 55.8 Purchased power contracts costs Term of related contract 2.7 36.5 2.8 36.6 Nuclear refueling outage costs 1 One to two years 43.3 16.9 36.3 13.5 Sales true-up and revenue decoupling One to two years 53.8 16.3 38.3 6.7 Losses on reacquired debt Term of related debt 1.7 13.8 2.1 15.5 Conservation programs (c) 1 One to two years 18.1 13.5 34.5 21.1 Environmental remediation costs 1, 10 Pending future rate cases 1.3 11.8 1.3 14.3 Deferred purchased natural gas and electric energy costs One to three years 6.2 5.7 5.6 12.6 State commission adjustments Plant lives — 3.4 — 3.4 Renewable resources and environmental initiatives One to two years 72.2 0.6 39.2 0.4 Gas pipeline inspection and remediation costs Less than one year 26.2 — 27.4 — Other Various 9.5 22.6 19.6 20.5 Total regulatory assets $ 320.1 $ 1,125.0 $ 280.3 $ 1,454.1 (a) Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments. (b) Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. (c) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. Components of regulatory liabilities: (Millions of Dollars) See Note(s) Remaining Amortization Period Dec. 31, 2019 Dec. 31, 2018 Regulatory Liabilities Current Noncurrent Current Noncurrent Deferred income tax adjustments and TCJA refunds (a) 7 Various $ 12.8 $ 1,388.9 $ 153.7 $ 1,465.1 Plant removal costs 1, 10 Plant lives — 520.3 — 484.6 ITC deferrals (b) 1 Various — 8.3 — 8.9 DOE Settlement Less than one year 27.0 — 13.0 — Deferred electric energy costs Less than one year 24.2 — 22.8 — Contract valuation adjustments (c) 1, 8 Less than one year 7.8 — 10.4 — Renewable resources and environmental initiatives Less than one year — — 8.8 — Other Various 69.2 19.6 53.7 26.1 Total regulatory liabilities (d) $ 141.0 $ 1,937.1 $ 262.4 $ 1,984.7 (a) Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA. (b) Includes impact of lower federal tax rate due to the TCJA. (c) Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. (d) Revenue subject for refund of $23.8 million and $12.5 million for 2019 and 2018, respectively, is included in other current liabilities. At Dec. 31, 2019 and 2018 , NSP-Minnesota’s regulatory assets not earning a return primarily included the unfunded portion of pension and retiree medical obligations, net AROs and Laurentian biomass PPA termination costs/obligations. In addition, regulatory assets included $235.1 million and $190.2 million at Dec. 31, 2019 and 2018, respectively, of past expenditures not earning a return. Amounts primarily related to sales true-up and revenue decoupling, purchased natural gas and electric energy costs, various renewable resources and certain environmental initiatives. |
Borrowings and Other Financing
Borrowings and Other Financing Instruments | 12 Months Ended |
Dec. 31, 2019 | |
Debt Disclosure [Abstract] | |
Borrowings and Other Financing Instruments | ort-Term Borrowings NSP-Minnesota meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility and the money pool. Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc. Money pool borrowings for NSP-Minnesota were as follows: (Millions of Dollars, Except Interest Rates) Three Months Ended Dec. 31, 2019 Year Ended Dec. 31 2019 2018 2017 Borrowing limit $ 250 $ 250 $ 250 $ 250 Amount outstanding at period end — — — 85 Average amount outstanding 34 32 17 25 Maximum amount outstanding 119 250 143 142 Weighted average interest rate, computed on a daily basis 1.67 % 2.05 % 1.96 % 1.14 % Weighted average interest rate at period end N/A N/A N/A 1.18 Commercial Paper — Commercial paper outstanding for NSP-Minnesota was as follows: (Millions of Dollars, Except Interest Rates) Three Months Ended Dec. 31, 2019 Year Ended Dec. 31 2019 2018 2017 Borrowing limit $ 500 $ 500 $ 500 $ 500 Amount outstanding at period end 30 30 150 20 Average amount outstanding 2 71 38 62 Maximum amount outstanding 30 317 198 237 Weighted average interest rate, computed on a daily basis 2.05 % 2.59 % 2.08 % 1.10 % Weighted average interest rate at end of period 2.05 2.05 2.97 1.93 Letters of Credit — NSP-Minnesota uses letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2019 and 2018 , there were $10 million and $37 million of letters of credit outstanding, respectively, under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees. Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, NSP-Minnesota must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an amount exceeding available capacity under this credit facility. The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. Amended Credit Agreement — In June 2019, NSP-Minnesota entered into an amended five-year credit agreement with a syndicate of banks. The amended credit agreements have substantially the same terms and conditions as the prior credit agreements with the exception of the maturity, which was extended from June 2021 to June 2024. Features of NSP-Minnesota’s credit facility: Debt-to-Total Capitalization Ratio (a) Amount Facility May Be Increased (millions) Additional Periods for Which a One-Year Extension May Be Requested (b) 2019 2018 48 % 48 % $ 100 2 (a) The credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65% . (b) All extension requests are subject to majority bank group approval. The credit facility has a cross-default provision that NSP-Minnesota will be in default on its borrowings under the facility if it or any of its subsidiaries whose total assets exceed 15% of NSP-Minnesota’s consolidated total assets, default on indebtedness in an aggregate principal amount exceeding $75 million . If NSP-Minnesota does not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2019 , NSP-Minnesota was in compliance with all financial covenants on its debt agreements. NSP-Minnesota had the following committed credit facilities available as of Dec. 31, 2019 (in millions): Credit Facility (a) Drawn (b) Available $ 500 $ 40 $ 460 (a) This credit facility matures in June 2024 . (b) Includes outstanding commercial paper and letters of credit. All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. NSP-Minnesota had no direct advances on the facility outstanding at Dec. 31, 2019 and 2018 . Bilateral Credit Agreement In March 2019, NSP-Minnesota entered into a one-year uncommitted bilateral credit agreement. This facility is limited in use to support letters of credit. As of Dec. 31, 2019 , NSP-Minnesota’s outstanding letters of credit under the Bilateral Credit Agreement were as follows (in millions): Limit Amount Used Available $ 75 $ 22 $ 53 Long-Term Borrowings and Other Financing Instruments Generally, all property of NSP-Minnesota is subject to the lien of its first mortgage indenture. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses for refinanced debt are deferred and amortized over the life of the new issuance. Long term debt obligations for NSP-Minnesota as of Dec. 31 (millions of dollars): Financing Instrument Interest Rate Maturity Date 2019 2018 First mortgage bonds 2.20 % Aug. 15, 2020 $ 300 $ 300 First mortgage bonds 2.15 % Aug. 15, 2022 300 300 First mortgage bonds 2.60 % May 15, 2023 400 400 First mortgage bonds 7.13 % July 1, 2025 250 250 First mortgage bonds 6.50 % March 1, 2028 150 150 First mortgage bonds 5.25 % July 15, 2035 250 250 First mortgage bonds 6.25 % June 1, 2036 400 400 First mortgage bonds 6.20 % July 1, 2037 350 350 First mortgage bonds 5.35 % Nov. 1, 2039 300 300 First mortgage bonds 4.85 % Aug. 15, 2040 250 250 First mortgage bonds 3.40 % Aug. 15, 2042 500 500 First mortgage bonds 4.13 % May 15, 2044 300 300 First mortgage bonds 4.00 % Aug. 15, 2045 300 300 First mortgage bonds 3.60 % May 15, 2046 350 350 First mortgage bonds 3.60 % Sept. 15, 2047 600 600 First mortgage bonds (a) 2.90 % March 1, 2050 600 — Unamortized discount (31 ) (21 ) Unamortized debt issuance cost (48 ) (42 ) Current maturities (300 ) — Total long-term debt $ 5,221 $ 4,937 (a) 2019 financing Maturities of long-term debt are as follows: (Millions of Dollars) 2020 $ 300 2021 — 2022 300 2023 400 2024 — Deferred Financing Costs — Deferred financing costs of approximately $48 million and $42 million , net of amortization, are presented as a deduction from the carrying amount of long-term debt at Dec. 31, 2019 and 2018 , respectively. Dividend Restrictions — NSP-Minnesota’s dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital accounts. Dividend payments are solely to be paid from retained earnings. NSP-Minnesota’s state regulatory commissions additionally impose dividend limitations, which are more restrictive than those imposed by the FERC. Requirements and actuals as of Dec. 31, 2019 : Equity to Total Capitalization Ratio - Required Range Equity to Total Capitalization Ratio - Actual Low High 2019 47.1 % 57.5 % 52.3 % Unrestricted Retained Earnings Total Capitalization Limit on Total Capitalization $ 1.1 billion $ 11.6 billion $ 12.7 billion |
Revenues
Revenues | 12 Months Ended |
Dec. 31, 2019 | |
Revenue from Contract with Customer [Abstract] | |
Revenues | Revenue is classified by the type of goods/services rendered and market/customer type. NSP-Minnesota’s operating revenues consisted of the following: Year Ended Dec. 31, 2019 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 1,280.2 $ 303.0 $ 30.1 $ 1,613.3 C&I 2,054.3 228.6 — 2,282.9 Other 32.9 — 3.8 36.7 Total retail 3,367.4 531.6 33.9 3,932.9 Wholesale 210.1 — — 210.1 Transmission 216.0 — — 216.0 Interchange 458.7 — — 458.7 Other 11.9 9.8 — 21.7 Total revenue from contracts with customers 4,264.1 541.4 33.9 4,839.4 Alternative revenue and other 242.5 29.9 — 272.4 Total revenues $ 4,506.6 $ 571.3 $ 33.9 $ 5,111.8 Year Ended Dec. 31, 2018 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 1,308.4 $ 308.8 $ 27.2 $ 1,644.4 C&I 2,052.1 239.3 0.2 2,291.6 Other 36.5 — 3.4 39.9 Total retail 3,397.0 548.1 30.8 3,975.9 Wholesale 189.2 — — 189.2 Transmission 238.1 — — 238.1 Interchange 473.7 — — 473.7 Other 28.3 11.7 — 40.0 Total revenue from contracts with customers 4,326.3 559.8 30.8 4,916.9 Alternative revenue and other 181.7 23.3 — 205.0 Total revenues $ 4,508.0 $ 583.1 $ 30.8 $ 5,121.9 |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Federal Tax Reform — In 2017, the TCJA was signed into law. The key provisions impacting Xcel Energy (which includes NSP-Minnesota), generally beginning in 2018, included: • Corporate federal tax rate reduction from 35% to 21% ; • Normalization of resulting plant-related excess deferred taxes; • Elimination of the corporate alternative minimum tax; • Continued interest expense deductibility and discontinued bonus depreciation for regulated public utilities; • Limitations on certain executive compensation deductions; • Limitations on certain deductions for NOLs arising after Dec. 31, 2017 (limited to 80% of taxable income); • Repeal of the section 199 manufacturing deduction; and • Reduced deductions for meals and entertainment as well as state and local lobbying. Xcel Energy estimated the effects of the TCJA, which have been reflected in the consolidated financial statements. Reductions in deferred tax assets and liabilities due to a decrease in corporate federal tax rates typically result in a net tax benefit. However, the impacts are primarily recognized as regulatory liabilities refundable to utility customers as a result of IRS requirements and past regulatory treatment. Estimated impacts of the new tax law for NSP-Minnesota in December 2017 included: • $1.1 billion ( $1.5 billion grossed-up for tax) of reclassifications of plant-related excess deferred taxes to regulatory liabilities upon valuation at the new 21% federal rate. The regulatory liabilities will be amortized consistent with IRS normalization requirements, resulting in customer refunds over the average remaining life of the related property; • $133 million and $56 million of reclassifications (grossed-up for tax) of excess deferred taxes for non-plant related deferred tax assets and liabilities, respectively, to regulatory assets and liabilities; and • $19 million of total estimated income tax expense related to the federal tax reform implementation, and a $5 million reduction to net income related to the allocation of Xcel Energy Services Inc.’s tax rate change on its deferred taxes. Xcel Energy accounted for the state tax impacts of federal tax reform based on enacted state tax laws. Any future state tax law changes related to the TCJA will be accounted for in the periods state laws are enacted. Federal Audit — NSP-Minnesota is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. Statute of limitations applicable to Xcel Energy’s consolidated federal income tax returns expire as follows: Tax Year(s) Expiration 2009 - 2013 June 2020 2014 - 2016 September 2020 In 2015, the IRS commenced an examination of tax years 2012 and 2013 . In 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s NOL and ETR. Xcel Energy filed a protest with the IRS. As of Dec. 31, 2019, the case has been forwarded to the Office of Appeals and Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is unknown. In 2018, the IRS began an audit of tax years 2014 - 2016 . As of Dec. 31, 2019 no adjustments have been proposed. State Audits — NSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2019, NSP-Minnesota’s earliest open tax year subject to examination by state taxing authorities under applicable statutes of limitations is 2009 . There are currently no state income tax audits in progress. Unrecognized Tax Benefits — Unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain, but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment to the taxing authority to an earlier period. Unrecognized tax benefits - permanent vs temporary: (Millions of Dollars) Dec. 31, 2019 Dec. 31, 2018 Unrecognized tax benefit — Permanent tax positions $ 14.8 $ 11.6 Unrecognized tax benefit — Temporary tax positions 4.9 5.3 Total unrecognized tax benefit $ 19.7 $ 16.9 Changes in unrecognized tax benefits: (Millions of Dollars) 2019 2018 2017 Balance at Jan. 1 $ 16.9 $ 18.1 $ 60.8 Additions based on tax positions related to the current year 2.6 2.0 2.7 Reductions based on tax positions related to the current year (0.5 ) (0.3 ) (1.7 ) Additions for tax positions of prior years 0.7 0.6 5.7 Reductions for tax positions of prior years — (1.1 ) (49.4 ) Settlements with taxing authorities — (2.4 ) — Balance at Dec. 31 $ 19.7 $ 16.9 $ 18.1 Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards: (Millions of Dollars) Dec. 31, 2019 Dec. 31, 2018 NOL and tax credit carryforwards $ (16.3 ) $ (12.7 ) Net deferred tax liability associated with the unrecognized tax benefit amounts and related NOLs and tax credits carryforwards were $11.3 million and $7.3 million at Dec. 31, 2019 and Dec. 31, 2018, respectively. As the IRS Appeals and federal audit progress and state audits resume, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $13.7 million in the next 12 months. Payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. Interest payable related to unrecognized tax benefits: (Millions of Dollars) 2019 2018 2017 Payable for interest related to unrecognized tax benefits at Jan. 1 $ (1.2 ) $ (0.9 ) $ (2.0 ) Interest (expense) income related to unrecognized tax benefits (0.4 ) (0.3 ) 1.1 Payable for interest related to unrecognized tax benefits at Dec. 31 $ (1.6 ) $ (1.2 ) $ (0.9 ) No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2019, 2018, or 2017. Other Income Tax Matters — NOL amounts represent the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows: (Millions of Dollars) 2019 2018 Federal tax credit carryforwards $ 449.0 $ 379.4 State NOL carryforwards 133.0 221.2 Valuation allowances for state NOL carryforwards (0.5 ) (0.8 ) State tax credit carryforwards, net of federal detriment (a) 77.5 87.9 Valuation allowances for state credit carryforwards, net of federal benefit (b) (65.9 ) (78.5 ) (a) State tax credit carryforwards are net of federal detriment of $20.6 million and $23.4 million as of Dec. 31, 2019 and 2018, respectively. (b) Valuation allowances for state tax credit carryforwards were net of federal benefit of $17.5 million and $20.9 million as of Dec. 31, 2019 and 2018, respectively. Federal carryforward periods expire between 2023 and 2039 and state carryforward periods expire between 2020 and 2035 . Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. Effective income tax rate for years ended Dec. 31: 2019 2018 (a) 2017 (a) Federal statutory rate 21.0 % 21.0 % 35.0 % State income tax on pretax income, net of federal tax effect 7.1 7.1 5.8 Increases (decreases) in tax from: Wind PTCs (11.8 ) (13.6 ) (11.4 ) Plant regulatory differences (b) (7.4 ) (8.8 ) (0.3 ) Other tax credits, net of NOL & tax credit allowances (1.5 ) (1.1 ) (1.0 ) Change in unrecognized tax benefits 0.5 0.1 (1.6 ) Tax reform — — 2.7 Other, net 0.1 0.5 (0.2 ) Effective income tax rate 8.0 % 5.2 % 29.0 % (a) Prior periods have been reclassified to conform to current year presentation. (b) Regulatory differences for income tax primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit of excess deferred credits are offset by corresponding revenue reductions. Components of income tax expense for years ended Dec. 31: (Millions of Dollars) 2019 2018 2017 Current federal tax expense (benefit) $ 80.7 $ (16.8 ) $ 29.6 Current state tax expense 7.9 5.2 14.7 Current change in unrecognized tax benefit (0.8 ) (1.1 ) (36.2 ) Deferred federal tax (benefit) expense (86.2 ) (2.4 ) 121.6 Deferred state tax expense 43.2 42.1 46.7 Deferred change in unrecognized tax expense 4.0 1.6 24.9 Deferred ITCs (1.4 ) (1.4 ) (1.6 ) Total income tax expense $ 47.4 $ 27.2 $ 199.7 Components of deferred income tax expense as of Dec. 31: (Millions of Dollars) 2019 2018 2017 Deferred tax expense (benefit) excluding items below $ 96.7 $ 70.1 (1,176.4 ) Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities (135.4 ) (28.2 ) 1,369.9 Tax expense allocated to other comprehensive income, net of adoption of ASU No. 2018-02, and other (0.3 ) (0.6 ) (0.3 ) Deferred tax expense $ (39.0 ) $ 41.3 $ 193.2 Components of the net deferred tax liability as of Dec. 31: (Millions of Dollars) 2019 2018 (a) Deferred tax liabilities: Differences between book and tax bases of property $ 2,361.0 $ 2,257.6 Regulatory assets 257.4 260.8 Operating lease assets 169.6 — Pension expense 68.4 64.7 Other 10.2 9.1 Total deferred tax liabilities $ 2,866.6 $ 2,592.2 Deferred tax assets: Tax credit carryforward $ 526.5 $ 467.3 Regulatory Liabilities 364.9 380.5 Operating lease liabilities 169.6 — NOL and tax credit valuation allowances (66.0 ) (78.6 ) Other employee benefits 37.5 38.6 Rate refund 11.0 49.7 NOL carryforward 10.4 17.9 Deferred investment tax credits 5.9 6.4 Other 27.7 28.0 Total deferred tax assets $ 1,087.5 $ 909.8 Net deferred tax liability $ 1,779.1 $ 1,682.4 (a) Prior periods have been reclassified to conform to current year presentation. |
Fair Value of Financial Assets
Fair Value of Financial Assets and Liabilities | 12 Months Ended |
Dec. 31, 2019 | |
Fair Value Disclosures [Abstract] | |
Fair Value of Financial Assets and Liabilities | Fair Value Measurements The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. • Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices; • Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs; and • Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation. Specific valuation methods include: Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted NAV. Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds are measured using NAVs. The investments in commingled funds may be redeemed for NAV with proper notice. Private equity commingled fund investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate commingled funds investments may be redeemed with proper notice, however, may be delayed or discounted as a result of fund illiquidity. Investments in debt securities — Fair values for debt securities are determined by a third-party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities. Interest rate derivatives — The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts. Commodity derivatives — The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When contractual settlements relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification. Electric commodity derivatives held by NSP-Minnesota include transmission congestion instruments, generally referred to as FTRs. FTRs purchased from a RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path. The value of an FTR is derived from, and designed to offset, the cost of transmission congestion. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR. If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Given the limited observability of important inputs to the value of FTRs between auction processes, including expected plant operating schedules and retail and wholesale demand, fair value measurements for FTRs have been assigned a Level 3. Non-trading monthly FTR settlements are included in fuel and purchased energy cost recovery mechanisms, and therefore changes in the fair value of the yet to be settled portions of most FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of NSP-Minnesota’s FTRs relative to its electric utility operations, the numerous unobservable quantitative inputs pertinent to the value of FTRs are immaterial to the consolidated financial statements of NSP-Minnesota. Non-Derivative Fair Value Measurements Nuclear Decommissioning Fund — The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning these facilities. The fund contains cash equivalents, debt securities, equity securities and other investments. NSP-Minnesota uses the MPUC approved asset allocation for the escrow and investment targets by asset class for both the escrow and qualified trust. NSP-Minnesota recognizes the costs of funding the decommissioning over the lives of the nuclear plants, assuming rate recovery of all costs. Realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund are deferred as a component of the regulatory asset. Unrealized gains for the nuclear decommissioning fund were $705.5 million and $450.1 million as of Dec. 31, 2019 and 2018 , respectively, and unrealized losses were $5.9 million and $44.8 million as of Dec. 31, 2019 and 2018 , respectively. Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund: Dec. 31, 2019 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total Nuclear decommissioning fund (a) Cash equivalents $ 33.4 $ 33.4 $ — $ — $ — $ 33.4 Commingled funds 732.8 — — — 934.9 934.9 Debt securities 489.2 — 495.2 12.7 — 507.9 Equity securities 484.6 962.0 1.4 — — 963.4 Total $ 1,740.0 $ 995.4 $ 496.6 $ 12.7 $ 934.9 $ 2,439.6 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $55.6 million of rabbi trust assets and miscellaneous investments. Dec. 31, 2018 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total Nuclear decommissioning fund (a) Cash equivalents $ 24.3 $ 24.3 $ — $ — $ — $ 24.3 Commingled funds 758.1 79.2 — — 819.1 898.3 Debt securities 465.6 — 435.6 — — 435.6 Equity securities 401.4 696.5 — — — 696.5 Total $ 1,649.4 $ 800.0 $ 435.6 $ — $ 819.1 $ 2,054.7 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $52.5 million of rabbi trust assets and miscellaneous investments. For the years ended Dec. 31, 2019 and 2018 , there were immaterial Level 3 nuclear decommissioning fund investments or transfer of amounts between levels. Contractual maturity dates of debt securities in the nuclear decommissioning fund as of Dec. 31, 2019 : Final Contractual Maturity (Millions of Dollars) Due in 1 Year or Less Due in 1 to 5 Years Due in 5 to 10 Years Due after 10 Years Total Debt securities $ (6.8 ) $ 110.5 $ 246.1 $ 158.1 $ 507.9 Rabbi Trusts NSP-Minnesota has established a rabbi trust to provide partial funding for future deferred compensation plan distributions. Cost and fair value of assets held in rabbi trusts: Dec. 31, 2019 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Total Rabbi Trusts (a) Cash equivalents $ 1.2 $ 1.2 $ — $ — $ 1.2 Mutual funds 11.4 13.1 — — 13.1 Total $ 12.6 $ 14.3 $ — $ — $ 14.3 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet. Dec. 31, 2018 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Total Rabbi Trusts (a) Cash equivalents $ 0.4 $ 0.4 $ — $ — $ 0.4 Mutual funds 10.8 10.7 — — 10.7 Total $ 11.2 $ 11.1 $ — $ — $ 11.1 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet. Derivative Fair Value Measurements NSP-Minnesota enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices. Interest Rate Derivatives — NSP-Minnesota enters into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes. As of Dec. 31, 2019 , accumulated other comprehensive losses related to interest rate derivatives included $0.8 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings. Wholesale and Commodity Trading Risk — NSP-Minnesota conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. NSP-Minnesota is allowed to conduct these activities within guidelines and limitations as approved by its risk management committee, comprised of management personnel not directly involved in activities governed by this policy. Commodity Derivatives — NSP-Minnesota enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale, FTRs, vehicle fuel, and weather derivatives. As of Dec. 31, 2019 , NSP-Minnesota had no commodity derivative contracts designated as cash flow hedges. NSP-Minnesota may enter into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, but may not be designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. Immaterial amounts to income related to the ineffectiveness of cash flow hedges were recorded for the years ended Dec. 31, 2019 and 2018 . As of Dec. 31, 2019 , there were immaterial net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses or related amounts expected to be reclassified into earnings during the next 12 months. NSP-Minnesota enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of amounts credited to customers under margin-sharing mechanisms. Gross notional amounts of commodity forwards, options and FTRs at Dec. 31: (Amounts in Millions) (a) (b) 2019 2018 MWh of electricity 79.1 56.8 MMBtu of natural gas 77.8 42.7 (a) Amounts are not reflective of net positions in the underlying commodities. (b) Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise. Consideration of Credit Risk and Concentrations — NSP-Minnesota continuously monitors the creditworthiness of counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets. NSP-Minnesota employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. NSP-Minnesota’s most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities. As of Dec. 31, 2019 , eight of NSP-Minnesota’s 10 most significant counterparties for these activities, comprising $54.2 million or 68% of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings. Two of the 10 most significant counterparties, comprising $15.8 million or 20% of this credit exposure, were not rated by these external agencies, but based on NSP-Minnesota’s internal analysis, had credit quality consistent with investment grade. Nine of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities. Qualifying Cash Flow Hedges — Financial impact of qualifying interest rate and vehicle fuel cash flow hedges on NSP-Minnesota’s accumulated other comprehensive loss, included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income: (Millions of Dollars) 2019 2018 2017 Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 $ (20.2 ) $ (20.9 ) $ (18.2 ) After-tax net unrealized gains related to derivatives accounted for as hedges — — 0.1 After-tax net realized losses on derivative transactions reclassified into earnings 0.8 0.7 0.9 Adoption of ASU. 2018-02 (a) — — (3.7 ) Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 $ (19.4 ) $ (20.2 ) $ (20.9 ) (a) In 2017, NSP-Minnesota implemented ASU No. 2018-02 related to TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings. Impact of derivative activity: Pre-Tax Fair Value (Millions of Dollars) Accumulated Other Comprehensive Loss Regulatory (Assets) and Liabilities Year Ended Dec. 31, 2019 Other derivative instruments Electric commodity $ — $ 1.5 Natural gas commodity — (2.9 ) Total $ — $ (1.4 ) Year Ended Dec. 31, 2018 Other derivative instruments Electric commodity $ — $ (5.5 ) Natural gas commodity — 1.8 Total $ — $ (3.7 ) Year Ended Dec. 31, 2017 Derivatives designated as cash flow hedges Vehicle fuel and other commodity $ 0.1 $ — Total $ 0.1 $ — Other derivative instruments Electric commodity — 9.3 Natural gas commodity — (1.9 ) Total $ — $ 7.4 Pre-Tax (Gains) Losses Pre-Tax Gains (Losses) (Millions of Dollars) Accumulated Other Comprehensive Loss Regulatory Year Ended Dec. 31, 2019 Derivatives designated as cash flow hedges Interest rate $ 1.1 (a) $ — $ — Total $ 1.1 $ — $ — Other derivative instruments Commodity trading $ — $ — $ (0.7 ) (c) Electric commodity — 0.8 (d) — Natural gas commodity — 0.9 (e) (2.5 ) (e) Total $ — $ 1.7 $ (3.2 ) Year Ended Dec. 31, 2018 Derivatives designated as cash flow hedges Interest rate $ 1.1 (a) $ — $ — Vehicle fuel and other commodity (0.1 ) (b) — — Total $ 1.0 $ — $ — Other derivative instruments Commodity trading $ — $ — $ 10.9 (c) Electric commodity — 3.3 (d) — Natural gas commodity — (1.9 ) (e) (1.3 ) (e) Total $ — $ 1.4 $ 9.6 Year Ended Dec. 31, 2017 Derivatives designated as cash flow hedges Interest rate $ 1.5 (a) $ — $ — Total $ 1.5 $ — $ — Other derivative instruments Commodity trading $ — $ — $ 9.4 (c) Electric commodity — (13.8 ) (d) — Natural gas commodity — 1.0 (e) (1.2 ) (e) Total $ — $ (12.8 ) $ 8.2 (a) Amounts are recorded to interest charges. (b) Amounts are recorded to O&M expenses. (c) Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate. (d) Amounts are recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate. (e) Amounts are recorded to cost of natural gas sold and transported. These derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms, and reclassified out of income as regulatory assets and liabilities, as appropriate. NSP-Minnesota had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2019 , 2018 and 2017 . Credit Related Contingent Features — Contract provisions for derivative instruments that NSP-Minnesota enters into, including those accounted for as normal purchase-normal sale contracts and therefore not reflected on the consolidated balance sheets, may require the posting of collateral or settlement of the contracts for various reasons, including if NSP-Minnesota’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies, or for cross-default contractual provisions if there was a failure under other financing arrangements related to payment terms or other covenants. As of Dec. 31, 2019 and 2018 , there were $7.1 million and no derivative instruments in a liability position with such underlying contract provisions, respectfully. Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that NSP-Minnesota’s ability to fulfill its contractual obligations is reasonably expected to be impaired. NSP-Minnesota had no collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 2019 and 2018 . Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2019 and 2018 : Dec. 31, 2019 Dec. 31, 2018 Fair Value Fair Value Netting (a) Fair Value Fair Value Netting (a) (Millions of Dollars) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Current derivative assets Other derivative instruments: Commodity trading $ 1.6 $ 39.5 $ 23.6 $ 64.7 $ (42.1 ) $ 22.6 $ 1.1 $ 27.1 $ 2.2 $ 30.4 $ (16.0 ) $ 14.4 Electric commodity — — 8.7 8.7 (0.9 ) 7.8 — — 10.5 10.5 (0.1 ) 10.4 Natural gas commodity — 2.1 — 2.1 — 2.1 — 1.0 — 1.0 — 1.0 Total current derivative assets $ 1.6 $ 41.6 $ 32.3 $ 75.5 $ (43.0 ) 32.5 $ 1.1 $ 28.1 $ 12.7 $ 41.9 $ (16.1 ) 25.8 PPAs (b) — — Current derivative instruments $ 32.5 $ 25.8 Noncurrent derivative assets Other derivative instruments: Commodity trading $ 8.5 $ 29.4 $ 6.0 $ 43.9 $ (34.8 ) $ 9.1 $ — $ 25.3 $ 5.0 $ 30.3 $ (13.4 ) $ 16.9 Total noncurrent derivative assets $ 8.5 $ 29.4 $ 6.0 $ 43.9 $ (34.8 ) 9.1 $ — $ 25.3 $ 5.0 $ 30.3 $ (13.4 ) 16.9 PPAs (b) 0.1 0.1 Noncurrent derivative instruments $ 9.2 $ 17.0 Dec. 31, 2019 Dec. 31, 2018 Fair Value Fair Value Netting (a) Fair Value Fair Value Netting (a) (Millions of Dollars) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Current derivative liabilities Other derivative instruments: Commodity trading $ 2.2 $ 42.1 $ 15.0 $ 59.3 $ (49.8 ) $ 9.5 $ 1.4 $ 23.9 $ 1.7 $ 27.0 $ (24.5 ) $ 2.5 Electric commodity — — 1.0 1.0 (1.0 ) — — — 0.1 0.1 (0.1 ) — Natural gas commodity — 1.7 — 1.7 — 1.7 — — — — — — Total current derivative liabilities $ 2.2 $ 43.8 $ 16.0 $ 62.0 $ (50.8 ) 11.2 $ 1.4 $ 23.9 $ 1.8 $ 27.1 $ (24.6 ) 2.5 PPAs (b) 13.8 14.0 Current derivative instruments $ 25.0 $ 16.5 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ 2.0 $ 32.3 $ 17.0 $ 51.3 $ (3.3 ) $ 48.0 $ 0.1 $ 16.0 $ 1.6 $ 17.7 $ 17.9 $ 35.6 Total noncurrent derivative liabilities $ 2.0 $ 32.3 $ 17.0 $ 51.3 $ (3.3 ) 48.0 $ 0.1 $ 16.0 $ 1.6 $ 17.7 $ 17.9 35.6 PPAs (b) 62.2 76.6 Noncurrent derivative instruments $ 110.2 $ 112.2 (a) NSP-Minnesota nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2019 and 2018 . At both Dec. 31, 2019 and 2018 , derivative assets and liabilities include $31.5 million of obligations to return cash collateral, respectively. At Dec. 31, 2019 and 2018 , derivative assets and liabilities include the rights to reclaim cash collateral of $7.9 million and $8.7 million , respectively. The counterparty netting excludes settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. (b) During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. Changes in Level 3 commodity derivatives for the years ended Dec. 31, 2019 , 2018 and 2017 : Year Ended Dec. 31 (Millions of Dollars) 2019 2018 2017 Balance at Jan. 1 $ 14.3 $ 22.6 $ 15.3 Purchases 16.7 26.4 40.6 Settlements (27.5 ) (17.2 ) (41.7 ) Net transactions recorded during the period: Gains (losses) recognized in earnings (a) 3.2 (1.5 ) 5.5 Net (losses) gains recognized as regulatory assets and liabilities (1.4 ) (16.0 ) 2.9 Balance at Dec. 31 $ 5.3 $ 14.3 $ 22.6 (a) Amounts relate to commodity derivatives held at the end of the period. NSP-Minnesota recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the years ended 2017 - 2019 . Fair Value of Long-Term Debt As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value: 2019 2018 (Millions of Dollars) Carrying Fair Value Carrying Fair Value Long-term debt, including current portion $ 5,521.3 $ 6,296.5 $ 4,937.2 $ 5,230.9 Fair value of NSP-Minnesota’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. Fair value estimates are based on information available to management as of Dec. 31, 2019 and 2018 , and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2. |
Benefit Plans and Other Postret
Benefit Plans and Other Postretirement Benefits | 12 Months Ended |
Dec. 31, 2019 | |
Retirement Benefits [Abstract] | |
Benefit Plans and Other Postretirement Benefits | Xcel Energy, which includes NSP-Minnesota, has several noncontributory, defined benefit pension plans that cover almost all employees. Generally, benefits are based on a combination of years of service and average pay. Xcel Energy’s and NSP-Minnesota’s policy is to fully fund into an external trust the actuarially determined pension costs subject to the limitations of applicable employee benefit and tax laws. In addition to the qualified pension plans, Xcel Energy maintains a SERP and a nonqualified pension plan. The SERP is maintained for certain executives that were participants in the plan in 2008, when the SERP was closed to new participants. The nonqualified pension plan provides benefits for compensation that is in excess of the limits applicable to the qualified pension plans, with distributions funded by Xcel Energy’s consolidated operating cash flows. Obligations of the SERP and nonqualified plan as of Dec. 31, 2019 and 2018 were $39 million and $33 million , respectively, of which $4 million was attributable to NSP-Minnesota in both years. In 2019 and 2018, Xcel Energy recognized net benefit cost for the SERP and nonqualified plans of $4 million , of which $1 million was attributable to NSP-Minnesota in both years. Xcel Energy and NSP-Minnesota base the investment-return assumption on expected long-term performance for each of the asset classes in its pension and postretirement health care portfolios. For pension assets, Xcel Energy and NSP-Minnesota consider the historical returns achieved by their asset portfolio over the past 20 years or longer period, as well as the long-term projected return levels. Xcel Energy and NSP-Minnesota continually review their pension assumptions. Pension cost determination assumes a forecasted mix of investment types over the long-term. • Investment returns in 2019 were above the assumed level of 7.10% ; • Investment returns in 2018 were below the assumed level of 7.10% ; • Investment returns in 2017 were above the assumed level of 7.10% ; and • In 2020, NSP-Minnesota’s expected investment-return assumption is 7.10% . Pension plan and postretirement benefit assets are invested in a portfolio according to Xcel Energy’s and NSP-Minnesota’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the asset allocation given the long-term risk, return, correlation and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by the assets in any year. State agencies also have issued guidelines to the funding of postretirement benefit costs. Xcel Energy’s ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios. Plan Assets For each of the fair value hierarchy levels, NSP-Minnesota’s pension plan assets measured at fair value: Dec. 31, 2019 (a) Dec. 31, 2018 (a) (Millions of Dollars) Level 1 Level 2 Level 3 Measured at NAV Total Level 1 Level 2 Level 3 Measured at NAV Total Cash equivalents $ 40.9 $ — $ — $ — $ 40.9 $ 31.8 $ — $ — $ — $ 31.8 Commingled funds 360.3 — — 270.3 630.6 241.0 — — 271.2 512.2 Debt securities — 155.5 1.1 — 156.6 — 143.7 — — 143.7 Equity securities 22.6 — — — 22.6 29.3 — — — 29.3 Other (31.5 ) 1.2 — (5.2 ) (35.5 ) 0.5 1.3 — (8.2 ) (6.4 ) Total $ 392.3 $ 156.7 $ 1.1 $ 265.1 $ 815.2 $ 302.6 $ 145.0 $ — $ 263.0 $ 710.6 (a) See Note 8 for further information on fair value measurement inputs and methods. For each of the fair value hierarchy levels, NSP-Minnesota’s postretirement benefit plan assets that were measured at fair value: Dec. 31, 2019 (a) Dec. 31, 2018 (a) (Millions of Dollars) Level 1 Level 2 Level 3 Measured at NAV Total Level 1 Level 2 Level 3 Measured at NAV Total Cash equivalents $ 0.1 $ — $ — $ — $ 0.1 $ 0.1 $ — $ — $ — $ 0.1 Insurance contracts — 0.3 — — 0.3 — 0.3 — — 0.3 Commingled funds 0.4 — — 0.5 0.9 0.8 — — 0.2 1.0 Debt securities — 1.3 — — 1.3 — 1.0 — — 1.0 Equity securities — — — — — — — — — — Total $ 0.5 $ 1.6 $ — $ 0.5 $ 2.6 $ 0.9 $ 1.3 $ — $ 0.2 $ 2.4 (a) See Note 8 for further information on fair value measurement inputs and methods. Immaterial assets were transferred in or out of Level 3 for 2019. No assets were transferred in or out of Level 3 for 2018. Funded Status — Comparisons of the actuarially computed benefit obligation, changes in plan assets and funded status of the pension and postretirement health care plans for NSP-Minnesota are as follows: Pension Benefits Postretirement Benefits (Millions of Dollars) 2019 2018 2019 2018 Change in Benefit Obligation: Obligation at Jan. 1 $ 907.0 $ 1,035.1 $ 76.0 $ 88.8 Service cost 25.4 28.0 0.1 0.2 Interest cost 37.1 35.2 3.2 3.1 Plan amendments 1.0 — — — Actuarial loss (gain) 61.7 (50.8 ) 3.8 (9.0 ) Plan participants’ contributions — — 0.3 0.4 Benefit payments (a) (90.0 ) (140.5 ) (7.9 ) (7.5 ) Obligation at Dec. 31 $ 942.2 $ 907.0 $ 75.5 $ 76.0 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 710.6 $ 824.5 $ 2.4 $ 6.5 Actual return on plan assets 147.8 (36.5 ) — — Employer contributions 46.8 63.1 7.7 3.0 Plan participants’ contributions — — 0.3 0.4 Benefit payments (90.0 ) (140.5 ) (7.8 ) (7.5 ) Fair value of plan assets at Dec. 31 $ 815.2 $ 710.6 $ 2.6 $ 2.4 Funded status of plans at Dec. 31 $ (127.0 ) $ (196.4 ) $ (72.9 ) $ (73.6 ) Amounts recognized in the Consolidated Balance Sheet at Dec. 31: Current assets (liabilities) $ — $ — $ (4.3 ) $ (4.8 ) Noncurrent assets (liabilities) (127.0 ) (196.4 ) (68.6 ) (68.8 ) Net amounts recognized $ (127.0 ) $ (196.4 ) $ (72.9 ) $ (73.6 ) (a) Includes approximately $105 million of lump-sum benefit payments used in the determination of a settlement charge in 2018. Significant Assumptions Used to Measure Benefit Obligations: Discount rate for year-end valuation 3.49 % 4.31 % 3.47 % 4.32 % Expected average long-term increase in compensation level 3.75 % 3.75 % N/A N/A Mortality table Pri-2012 RP-2014 Pri-2012 RP-2014 Health care costs trend rate — initial: Pre-65 N/A N/A 6.00 % 6.50 % Health care costs trend rate — initial: Post-65 N/A N/A 5.10 % 5.30 % Ultimate trend assumption — initial: Pre-65 N/A N/A 4.50 % 4.50 % Ultimate trend assumption — initial: Post-65 N/A N/A 4.50 % 4.50 % Years until ultimate trend is reached N/A N/A 3 4 The accumulated benefit obligation for the pension plan was $872 million and $845 million as of Dec. 31, 2019 and 2018, respectively. Net Periodic Benefit Cost — Net periodic benefit cost other than the service cost component is included in other income in the consolidated statement of income. Components of net periodic benefit cost and the amounts recognized in other comprehensive income and regulatory assets and liabilities are as follows: Pension Benefits Postretirement Benefits (Millions of Dollars) 2019 2018 2017 2019 2018 2017 Service cost $ 25.4 $ 28.0 $ 27.8 $ 0.1 $ 0.2 $ 0.1 Interest cost 37.1 35.2 40.7 3.2 3.1 3.4 Expected return on plan assets (54.3 ) (58.2 ) (60.1 ) (0.1 ) (0.4 ) (0.2 ) Amortization of prior service cost (0.1 ) (0.1 ) 1.1 (3.0 ) (3.0 ) (3.0 ) Amortization of net loss 30.2 38.5 39.6 1.5 2.4 2.0 Settlement charge (a) — 48.8 48.2 — — — Net periodic pension cost 38.3 92.2 97.3 1.7 2.3 2.3 Costs not recognized due to effects of regulation (5.2 ) (66.0 ) (72.2 ) — — — Net benefit cost recognized for financial reporting $ 33.1 $ 26.2 $ 25.1 $ 1.7 $ 2.3 $ 2.3 Significant Assumptions Used to Measure Costs: Discount rate 4.31 % 3.63 % 4.13 % 4.32 % 3.62 % 4.13 % Expected average long-term increase in compensation level 3.75 3.75 3.75 — — — Expected average long-term rate of return on assets 7.10 7.10 7.10 4.50 5.30 5.80 (a) A settlement charge is required when the amount of lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2018 and 2017, as a result of lump-sum distributions during the 2018 and 2017 plan years, NSP-Minnesota recorded a total pension settlement charge of $48.8 million in 2018 and $48.2 million in 2017 , which was not recognized due to the effects of regulation. Pension Benefits Postretirement Benefits (Millions of Dollars) 2019 2018 2019 2018 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss $ 440.0 $ 502.0 $ 36.8 $ 34.3 Prior service credit (0.2 ) (1.2 ) (9.4 ) (12.4 ) Total $ 439.8 $ 500.8 $ 27.4 $ 21.9 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates: Current regulatory assets $ 29.3 $ 35.5 $ — $ — Noncurrent regulatory assets 410.5 465.3 25.6 20.5 Deferred income taxes — — 0.5 0.4 Net-of-tax accumulated other comprehensive income — — 1.3 1.0 Total $ 439.8 $ 500.8 $ 27.4 $ 21.9 Measurement date Dec. 31, 2019 Dec. 31, 2018 Dec. 31, 2019 Dec. 31, 2018 Cash Flows — Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. Required contributions were made in 2017 - 2020 to meet minimum funding requirements. Total voluntary and required pension funding contributions across all four of Xcel Energy’s pension plans were as follows: • $150 million in January 2020, of which $44 million is attributable to NSP-Minnesota; • $154 million in 2019, of which $47 million was attributable to NSP-Minnesota; • $150 million in 2018, of which $63 million was attributable to NSP-Minnesota; and • $162 million in 2017, of which $61 million was attributable to NSP-Minnesota. The postretirement health care plans have no funding requirements other than fulfilling benefit payment obligations, when claims are presented and approved. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities. Voluntary postretirement funding contributions: • $10 million in January 2020, of which $7 million is attributable to NSP-Minnesota; • $15 million in 2019, of which $8 million , was attributable to NSP-Minnesota; • $11 million in 2018, of which $3 million was attributable to NSP-Minnesota; and • $20 million in 2017, of which $10 million was attributable to NSP-Minnesota. Target asset allocations: Pension Benefits Postretirement Benefits 2019 2018 2019 2018 Domestic and international equity securities 37 % 37 % 15 % 18 % Long-duration fixed income and interest rate swap securities 30 28 — — Short-to-intermediate fixed income securities 14 18 72 70 Alternative investments 17 15 9 8 Cash 2 2 4 4 Total 100 % 100 % 100 % 100 % Plan Amendments —The Xcel Energy Pension Plan, which includes NSP-Minnesota, and Xcel Energy Inc. Nonbargaining Pension Plan (South) were amended in 2017 to reduce supplemental benefits for non-bargaining participants as well as to allow the transfer of a portion of non-qualified pension obligations into the qualified plans. In 2019, the Pension Protection Act measurement concept was extended beyond 2019 for NSP bargaining terminations and retirements to Dec. 31, 2022. In 2019, there were no plan amendments made which affected the postretirement benefit obligation. Projected Benefit Payments NSP-Minnesota’s projected benefit payments: (Millions of Dollars) Projected Pension Benefit Payments Gross Projected Postretirement Health Care Benefit Payments Expected Medicare Part D Subsidies Net Projected Postretirement Health Care Benefit Payments 2020 $ 89.9 $ 6.9 $ — $ 6.9 2021 82.4 6.6 — 6.6 2022 80.8 6.2 — 6.2 2023 78.5 5.9 — 5.9 2024 74.1 5.6 — 5.6 2025-2029 326.7 23.6 — 23.6 Defined Contribution Plans Xcel Energy, which includes NSP-Minnesota, maintains 401(k) and other defined contribution plans that cover most employees. The expense to these plans for NSP-Minnesota was approximately $12 million in 2019 , 2018 and in 2017 , respectively. Multiemployer Plans NSP-Minnesota contributes to several union multiemployer pension and other postretirement benefit plans, none of which are individually significant. These plans provide pension and postretirement health care benefits to certain union employees who may perform services for multiple employers and do not participate in the NSP-Minnesota sponsored pension and postretirement health care plans. Contributing to these types of plans creates risk that differs from providing benefits under NSP-Minnesota sponsored plans, in that if another participating employer ceases to contribute to a multiemployer plan, additional unfunded obligations may need to be funded over time by remaining participating employers. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2019 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | al NSP-Minnesota is involved in various litigation matters that are being defended and handled in the ordinary course of business. Assessing whether a loss is probable or a reasonable possibility, and whether the loss or a range of loss is estimable, often involves complex judgments regarding future events. Management maintains accruals for losses that are probable of being incurred and subject to reasonable estimation. Management may be unable to estimate an amount or range of a reasonably possible loss in certain situations, including when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate the ultimate liabilities, if any, arising from such current proceedings would have a material effect on NSP-Minnesota’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred. Rate Matters MEC Acquisition — In November 2018, NSP-Minnesota reached an agreement with Southern Power Company (a subsidiary of Southern Company) to purchase MEC, a 760 MW natural gas combined cycle facility, with capacity and energy historically sold to NSP-Minnesota under PPAs expiring in 2026 and 2039, for approximately $650 million . In September 2019, the MPUC denied NSP-Minnesota's request to purchase MEC as a rate base asset. In January 2020, the MPUC approved Xcel Energy’s plan to acquire MEC as a non-regulated investment and step into the terms of the existing PPAs with NSP-Minnesota. A newly formed non-regulated subsidiary of Xcel Energy completed the transaction to purchase MEC on Jan. 17, 2020. Sherco — In NSP-Minnesota’s 2013 fuel reconciliation filing, the MPUC made recovery of replacement power costs associated with the 2011 incident at its Sherco Unit 3 plant provisional and subject to further review following conclusion of litigation commenced by NSP-Minnesota, SMMPA (Co-owner of Sherco Unit 3) and insurance companies against GE. In 2018, NSP-Minnesota and SMMPA reached a settlement with GE. NSP-Minnesota notified the MPUC of its proposal to refund the GE settlement proceeds back to customers through the FCA. The insurance providers continued their litigation against GE and the case went to trial. In 2018, GE prevailed in the lawsuit with the insurance companies, however, the jury found comparable fault, finding that GE was 52% and NSP-Minnesota was 48% at fault. At that point in the litigation, NSP-Minnesota was no longer involved in the case and was not present to make arguments about its role in the event. The specific issue leading to the fault apportionment was also not before the jury and not relevant to the outcome of the trial. In January 2019, the DOC recommended that NSP-Minnesota refund $20 million of previously recovered purchased power costs to its customers, based on the jury’s apportionment of fault. The OAG recommended the MPUC withhold any decision until the underlying litigation by the insurance providers (currently under appeal) is concluded. The DOC subsequently filed comments agreeing with the OAG’s recommendation to withhold a decision pending the outcome of any appeals. NSP-Minnesota filed reply comments arguing that the DOC recommendations are without merit and that it acted prudently in operating the plant and its settlement with GE was reasonable. In March 2019, MPUC approved NSP-Minnesota’s proposal to refund the GE settlement proceeds back to customers through the FCA. It also decided to withhold any decision as to NSP-Minnesota’s prudence in connection with the incident at Sherco Unit 3 until after conclusion of the pending litigation between GE and NSP-Minnesota’s insurers. MISO ROE Complaints — In November 2013 and February 2015, customers filed complaints against MISO TOs including NSP-Minnesota and NSP-Wisconsin. The first complaint argued for a reduction in the base ROE in MISO transmission formula rates from 12.38% to 9.15% , and removal of ROE adders (including those for RTO membership). The second complaint sought to reduce base ROE from 12.38% to 8.67% . In September 2016, the FERC issued an order granting a 10.32% base ROE ( 10.82% with the RTO adder) effective for the first complaint period of Nov. 12, 2013 to Feb. 11, 2015 and subsequent to the date of the order. The D.C. Circuit subsequently vacated and remanded FERC Opinion No. 531, which had established the ROE methodology on which the September 2016 FERC order was based. On March 21, 2019, FERC announced a NOI seeking public comments on whether, and if so how, to revise ROE policies in light of the D.C. Circuit Court decision. FERC also initiated a NOI on whether to revise its policies on incentives for electric transmission investments, including the RTO membership incentive. In November 2019, the FERC issued an order adopting a new ROE methodology and settling the MISO base ROE at 9.88% ( 10.38% with the RTO adder), effective Sept. 28, 2016 and for the Nov. 12, 2013 to Feb. 11, 2015 refund period. The FERC also dismissed the second complaint. In December 2019, MISO TOs filed a request for rehearing. Customers also filed requests for rehearing claiming, among other points, that the FERC erred by dismissing the second complaint without refunds. NSP-Minnesota has recognized a liability for its best estimate of final refunds to customers. It is uncertain when the FERC will act on the requests for rehearing or any other pending matters related to the 2019 NOIs. Environmental New and changing federal and state environmental mandates can create financial liabilities for NSP-Minnesota, which are normally recovered through the regulated rate process. Site Remediation — Various federal and state environmental laws impose liability where hazardous substances or other regulated materials have been released to the environment. NSP-Minnesota may sometimes pay all or a portion of the cost to remediate sites where past activities of NSP-Minnesota’s predecessors or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former MGPs; and third-party sites, such as landfills, for which NSP-Minnesota is alleged to have sent wastes to that site. MGP, Landfill or Disposal Sites — NSP-Minnesota is currently investigating or remediating seven MGP, landfill or other disposal sites across its service territories. NSP-Minnesota has recognized its best estimate of costs/liabilities that will result from final resolution of these issues, however, the outcome and timing is unknown. In addition, there may be insurance recovery and/or recovery from other potentially responsible parties, offsetting a portion of costs incurred. Environmental Requirements — Water and Waste Coal Ash Regulation — NSP-Minnesota’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of solid waste. Under the CCR Rule, utilities are required to complete groundwater sampling around their CCR landfills and surface impoundments. Currently, NSP-Minnesota has three regulated ash units in operation. NSP-Minnesota is conducting groundwater sampling and, where appropriate, initiating the assessment of corrective measures and evaluating whether corrective action is required at any CCR landfills or surface impoundments. To date, groundwater monitoring consistent with the CCR Rule has not identified results above the groundwater protection standards in the rule. Therefore, at this time no corrective action requirements have been triggered for these units under the rule. In August 2018, the D.C. Circuit ruled that the EPA cannot allow utilities to continue to use unlined impoundments (including clay lined impoundments) for the storage or disposal of coal ash. In November 2019, the EPA proposed rules in response to this decision. If finalized in their current form, these rules would require NSP-Minnesota to expedite closure plans for one impoundment at an estimated cost of $2 million , and the construction of a new impoundment at an estimated cost of $8.6 million . In 2019, NSP-Minnesota initiated the construction of this new impoundment, an ash pond, expected to be in service in 2020. Upon placing the new ash pond in service, the existing ash pond will be taken out of service, and closure activities as prescribed by the CCR Rule and the facility’s National Pollutant Discharge Elimination System permit will be initiated. Closure costs for existing impoundments are included in the calculation of the ARO liability. See ARO section of Note 10 for further information. Federal CWA WOTUS Rule — In 2015, the EPA and Corps published a final rule that significantly broadened the scope of waters under the CWA that are subject to federal jurisdiction, referred to as “WOTUS”. In 2019, the EPA repealed the 2015 rule and published a draft replacement rule. Until a final rule is issued, NSP-Minnesota cannot estimate potential impacts, but anticipates costs will be recoverable through regulatory mechanisms. Federal CWA ELG — In 2015, the EPA issued a final ELG rule for power plants that discharge treated effluent to surface waters as well as utility-owned landfills that receive CCRs. In 2017, the EPA delayed the compliance date for flue gas desulfurization wastewater and bottom ash transport until November 2020. After 2020, NSP-Minnesota estimates that ELG compliance will cost approximately $10.0 million to complete. The EPA, however, is conducting a rulemaking process to revise certain effluent limitations and pretreatment standards, which may impact compliance costs. NSP-Minnesota anticipates these costs will be fully recoverable through regulatory mechanisms. Federal CWA Section 316(b) — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing impingement and entrainment of aquatic species. NSP-Minnesota estimates the likely cost for complying with impingement and entrainment requirements is approximately $35.6 million , to be incurred between 2020 and 2028. NSP-Minnesota believes six plants could be required by state regulators to make improvements to reduce impingement and entrainment. The exact total cost of the impingement and entrainment improvements is uncertain, but could be up to $191.6 million . NSP-Minnesota anticipates these costs will be fully recoverable through regulatory mechanisms. Environmental Requirements — Air Regional Haze Rules — The regional haze program requires sulfur dioxide, nitrogen oxide and particulate matter emission controls at power plants to reduce visibility impairment in national parks and wilderness areas. The program includes reasonable further progress. The requirements of the first regional haze plans developed by Minnesota have been approved and implemented. AROs — AROs have been recorded for NSP-Minnesota’s assets. For nuclear assets, the ARO is associated with the decommissioning of NSP-Minnesota nuclear generating plants. Aggregate fair value of NSP-Minnesota’s legally restricted assets, for funding future nuclear decommissioning, was $2.4 billion and $2.1 billion for 2019 and 2018 , respectively. NSP-Minnesota’s AROs were as follows: 2019 (Millions of Dollars) Jan. 1, 2019 Amounts Incurred (a) Amounts Settled (b) Accretion Cash Flow Revisions (c) Dec. 31, 2019 Electric Nuclear $ 1,968.3 $ — $ — $ 99.5 $ — $ 2,067.8 Wind 104.9 10.3 — 4.8 (6.9 ) 113.1 Steam and other production 49.2 — (3.2 ) 1.8 (1.0 ) 46.8 Distribution 14.5 — — 0.6 — 15.1 Miscellaneous 1.8 — — — (1.6 ) 0.2 Natural gas Transmission and distribution 38.2 — — 1.6 (3.6 ) 36.2 Miscellaneous 0.2 — — 0.1 — 0.3 Common Miscellaneous 0.8 — — — — 0.8 Total liability $ 2,177.9 $ 10.3 $ (3.2 ) $ 108.4 $ (13.1 ) $ 2,280.3 (a) Amounts incurred relate to the wind farms placed in service in 2019 (Lake Benton and Foxtail). (b) Amounts settled related to closure of certain ash containment facilities. (c) In 2019, AROs were revised for changes in timing and estimates of cash flows. Changes in wind AROs were driven by new dismantling studies. Changes in gas transmission and distribution AROs were primarily related to increased gas line mileage and number of services, which were more than offset by decreased inflation rates. Changes in steam and other production AROs primarily related to the cost estimates to remediate ponds at production facilities. 2018 (Millions of Dollars) Jan. 1, 2018 Amounts Settled (a) Accretion Cash Flow Revisions (b) Dec. 31, 2018 (c) Electric Nuclear $ 1,873.6 $ — $ 94.7 $ — $ 1,968.3 Wind 94.1 — 4.3 6.5 104.9 Steam and other production 64.0 (6.6 ) 2.1 (10.3 ) 49.2 Distribution 5.8 — 0.2 8.5 14.5 Miscellaneous 1.9 — — (0.1 ) 1.8 Natural gas Transmission and distribution 43.6 — 1.8 (7.2 ) 38.2 Miscellaneous 0.2 — — — 0.2 Common Miscellaneous 0.7 — 0.1 — 0.8 Total liability $ 2,083.9 $ (6.6 ) $ 103.2 $ (2.6 ) $ 2,177.9 (a) Amounts settled related to asbestos abatement projects and closure of certain ash containment facilities. (b) In 2018, AROs were revised for changes in timing and estimates of cash flows. Changes in gas transmission and distribution AROs were mainly related to increased gas line mileage and number of services, which were more than offset by increased discount rates. Changes in electric distribution AROs primarily related to increased labor costs. (c) There were no ARO amounts incurred in 2018. Indeterminate AROs — Outside of the recorded asbestos AROs, other plants or buildings may contain asbestos due to the age of many of NSP-Minnesota’s facilities, but no confirmation or measurement of the cost of removal could be determined as of Dec. 31, 2019. Therefore, an ARO has not been recorded for these facilities. Removal Costs — NSP-Minnesota records a regulatory liability for the plant removal costs that are recovered currently in rates. Removal costs have accumulated based on varying rates as authorized by the appropriate regulatory entities. NSP-Minnesota has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Removal costs as of Dec. 31, 2019 and 2018 were $520.3 million and $484.6 million , respectively. Nuclear Related Nuclear Insurance — NSP-Minnesota’s public liability for claims from any nuclear incident is limited to $13.9 billion under the Price-Anderson amendment to the Atomic Energy Act. NSP-Minnesota has secured $450.0 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $13.5 billion of exposure is funded by the Secondary Financial Protection Program, available from assessments by the federal government. NSP-Minnesota is subject to assessments of up to $137.6 million per reactor-incident for each of its three licensed reactors, for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $20.5 million per reactor-incident during any one year. Maximum assessments are subject to inflation adjustments by the NRC and state premium taxes. The NRC’s last adjustment was effective November 2018. NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from NEIL and EMANI. The coverage limits are $2.7 billion for each of NSP-Minnesota’s two nuclear plant sites. NEIL also provides business interruption insurance coverage up to $350.0 million , including the cost of replacement power during prolonged accidental outages of nuclear generating units. Premiums are expensed over the policy term. All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NEIL and EMANI to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage. NSP-Minnesota could be subject to annual maximum assessments of approximately $12.0 million for business interruption insurance and $35.1 million for property damage insurance if losses exceed accumulated reserve funds. Nuclear Fuel Disposal — NSP-Minnesota is responsible for temporarily storing spent nuclear fuel from its nuclear plants. The DOE is responsible for permanently storing spent fuel from U.S. nuclear plants, but no such facility is yet available. NSP-Minnesota owns temporary on-site storage facilities for spent fuel at its Monticello and PI nuclear plants, which consist of storage pools and dry cask facilities. The Monticello dry-cask storage facility currently stores all 30 of the authorized canisters. The PI dry-cask storage facility currently stores 44 of the 64 authorized casks. Monticello’s future spent fuel will continue to be placed in its spent fuel pool. The decommissioning plan addresses the disposition of spent fuel at the end of the licensed life. Regulatory Plant Decommissioning Recovery — Decommissioning activities for NSP-Minnesota’s nuclear facilities are planned to begin at the end of each unit’s operating license and be completed by 2091. NSP-Minnesota’s current operating licenses allow continued use of its Monticello nuclear plant until 2030 and its PI nuclear plant until 2033 for Unit 1 and 2034 for Unit 2. Future decommissioning costs of nuclear facilities are estimated through triennial periodic studies that assess the costs and timing of planned nuclear decommissioning activities for each unit. Obligations for decommissioning are expected to be funded 100% by the external decommissioning trust fund. The cost study assumes the external decommissioning fund will earn an after-tax return between 5.23% and 6.30% . Realized and unrealized gains on fund investments are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Decommissioning costs are quantified in 2014 dollars. Escalation rates are 4.36% for plant removal activities and 3.36% for fuel management and site restoration activities. NSP-Minnesota had $2.4 billion of assets held in external decommissioning trusts at Dec. 31, 2019. The following table summarizes the funded status of NSP-Minnesota’s decommissioning obligation. Xcel Energy believes future decommissioning costs will continue to be recovered in customer rates. The following amounts were prepared on a regulatory basis and not directly recorded in the financial statements as an ARO. Regulatory Basis (Millions of Dollars) 2019 2018 Estimated decommissioning cost obligation from most recently approved study (in 2014 dollars) $ 3,012.3 $ 3,012.3 Effect of escalating costs 688.2 538.9 Estimated decommissioning cost obligation (in current dollars) 3,700.5 3,551.2 Effect of escalating costs to payment date 7,505.0 7,654.3 Estimated future decommissioning costs (undiscounted) 11,205.5 11,205.5 Effect of discounting obligation (using average risk-free interest rate of 2.39% and 3.33% for 2019 and 2018, respectively) (5,562.2 ) (6,911.5 ) Discounted decommissioning cost obligation $ 5,643.3 $ 4,294.0 Assets held in external decommissioning trust $ 2,439.6 $ 2,054.7 Underfunding of external decommissioning fund compared to the discounted decommissioning obligation 3,203.7 2,239.3 Calculations and data used by the regulator in approving NSP-Minnesota’s rates are useful in assessing future cash flows. Regulatory basis information is a means to reconcile amounts previously provided to the MPUC and utilized for regulatory purposes to amounts used for financial reporting. Reconciliation of the discounted decommissioning cost obligation - regulated basis to the ARO recorded in accordance with GAAP: (Millions of Dollars) 2019 2018 Discounted decommissioning cost obligation - regulated basis $ 5,643.3 $ 4,294.0 Differences in discount rate and market risk premium (2,295.2 ) (1,446.4 ) O&M costs not included for GAAP (1,280.3 ) (879.3 ) Nuclear production decommissioning ARO - GAAP $ 2,067.8 $ 1,968.3 Decommissioning expenses recognized as a result of regulation: (Millions of Dollars) 2019 2018 2017 Annual decommissioning recorded as depreciation expense: (a) (b) $ 20.4 $ 20.4 $ 20.4 (a) Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs. (b) Decommissioning expenses in 2019, 2018 and 2017 include Minnesota’s retail jurisdiction annual funding requirement of approximately $14.0 million. The 2014 nuclear decommissioning filing, approved in 2015, was used for regulatory presentation in 2019, 2018 and 2017. The 2017 filing, effective Jan. 1, 2019, has been approved by the MPUC. In December 2019, the MPUC verbally approved for NSP-Minnesota to delay any increase to the annual funding requirement until 2021. Leases NSP-Minnesota evaluates contracts that may contain leases, including PPAs and arrangements for the use of office space and other facilities, vehicles and equipment. Under ASC Topic 842, adopted by NSP-Minnesota on Jan. 1, 2019, a contract contains a lease if it conveys the exclusive right to control the use of a specific asset. A contract determined to contain a lease is evaluated further to determine if the arrangement is a finance lease. ROU assets represent NSP-Minnesota's rights to use leased assets. Starting in 2019, the present value of future operating lease payments are recognized in current and noncurrent operating lease liabilities. These amounts, adjusted for any prepayments or incentives, are recognized as operating lease ROU assets. Most of NSP-Minnesota’s leases do not contain a readily determinable discount rate. Therefore, the present value of future lease payments is generally calculated using the estimated incremental borrowing rate (weighted-average of 3.8% ). NSP-Minnesota has elected to utilize the practical expedient under which non-lease components, such as asset maintenance costs included in payments, are not deducted from minimum lease payments for the purposes of lease accounting and disclosure. Leases with an initial term of 12 months or less are classified as short-term leases and are not recognized on the consolidated balance sheet. Operating lease ROU assets: (Millions of Dollars) Dec. 31, 2019 PPAs $ 556.3 Other 72.2 Gross operating lease ROU assets 628.5 Accumulated amortization (64.7 ) Net operating lease ROU assets $ 563.8 Components of lease expense: (Millions of Dollars) 2019 2018 2017 Operating leases PPA capacity payments $ 75.9 $ 62.5 $ 62.7 Other operating leases (a) 9.1 13.7 14.2 Total operating lease expense (b) $ 85.0 $ 76.2 $ 76.9 (a) Includes short-term lease expense of $1.4 million , $2.0 million and $2.7 million for 2019, 2018 and 2017, respectively. (b) PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income. Expense for other operating leases is included in O&M expense and electric fuel and purchased power. Commitments under operating leases as of Dec. 31, 2019: (Millions of Dollars) PPA (a) (b) Operating Leases Other Operating Leases Total Leases 2020 $ 93.5 $ 7.9 $ 101.4 2021 94.9 8.0 102.9 2022 96.4 11.9 108.3 2023 97.9 7.0 104.9 2024 99.5 6.8 106.3 Thereafter 119.8 44.9 164.7 Total minimum obligation 602.0 86.5 688.5 Interest component of obligation (66.2 ) (16.7 ) (82.9 ) Present value of minimum obligation $ 535.8 $ 69.8 605.6 Less current portion (79.9 ) Noncurrent operating lease liabilities $ 525.7 Weighted-average remaining lease term in years 6.7 (a) Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs. (b) PPA operating leases contractually expire at various dates through 2026. Commitments under operating leases as of Dec. 31, 2018: (Millions of Dollars) PPA (a) (b) Operating Other Operating Leases Total 2019 $ 65.0 $ 13.5 $ 78.5 2020 66.1 8.4 74.5 2021 67.1 8.4 75.5 2022 68.2 8.1 76.3 2023 69.3 7.3 76.6 Thereafter 143.5 36.0 179.5 (a) Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs. (b) PPA operating leases contractually expire at various dates through 2026. Non-Lease PPAs — NSP-Minnesota has entered into PPAs with other utilities and energy suppliers with various expiration dates through 2033 for purchased power to meet system load and energy requirements, operating reserve obligations and as part of wholesale and commodity trading activities. In general, these agreements provide for energy payments, based on actual energy delivered and capacity payments. Certain PPAs accounted for as executory contracts contain minimum energy purchase commitments, and total energy payments on those contracts were $102.4 million , $104.7 million and $96.7 million in 2019, 2018 and 2017, respectively. Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $53.8 million , $52.7 million and $84.1 million in 2019 , 2018 and 2017 , respectively. Capacity and energy payments are contingent on the IPPs meeting contract obligations, including plant availability requirements. Certain contractual payments are adjusted based on market indices. The effects of price adjustments on financial results are mitigated through purchased energy cost recovery mechanisms. At Dec. 31, 2019 , the estimated future payments for capacity and energy that NSP-Minnesota is obligated to purchase pursuant to these executory contracts, subject to availability, were as follows: (Millions of Dollars) Capacity Energy (a) 2020 $ 54.5 $ 109.4 2021 62.2 157.3 2022 61.3 172.9 2023 62.8 176.9 2024 64.5 181.8 Thereafter 45.4 146.3 Total (b) $ 350.7 $ 944.6 (a) Excludes contingent energy payments for renewable energy PPAs. (b) Includes amounts allocated to NSP-Wisconsin through intercompany charges. Fuel Contracts — NSP-Minnesota has entered into various long-term commitments for the purchase and delivery of a significant portion of its coal, nuclear fuel and natural gas requirements. These contracts expire in various years between 2020 and 2037 . NSP-Minnesota is required to pay additional amounts depending on actual quantities shipped under these agreements. Estimated minimum purchases for these contracts as of Dec. 31, 2019 : (Millions of Dollars) Coal Nuclear fuel Natural gas Natural gas 2020 $ 171.3 $ 53.8 $ 36.8 $ 133.0 2021 85.2 102.5 1.4 129.8 2022 51.9 85.3 0.8 124.3 2023 35.1 103.0 — 107.8 2024 0.9 74.5 — 101.1 Thereafter 2.6 275.1 — 273.6 Total (a) $ 347.0 $ 694.2 $ 39.0 $ 869.6 (a) Includes amounts allocated to NSP-Wisconsin through intercompany charges. VIEs Under certain PPAs, NSP-Minnesota purchases power from IPPs for which NSP-Minnesota is required to reimburse fuel costs, or to participate in tolling arrangements under which NSP-Minnesota procures the natural gas required to produce the energy that it purchases. NSP-Minnesota has determined that certain IPPs are VIEs. NSP-Minnesota is not subject to risk of loss from the operations of these entities, and no significant financial support is required other than contractual payments for energy and capacity. NSP-Minnesota evaluated each of these VIEs for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices, and financing activities. NSP-Minnesota concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. NSP-Minnesota had approximately 1,347 MW and 1,002 MW of capacity under long-term PPAs at Dec. 31, 2019 and 2018 , respectively, with entities that have been determined to be VIEs. These agreements have expiration dates through 2039 . |
Other Comprehensive Income
Other Comprehensive Income | 12 Months Ended |
Dec. 31, 2019 | |
Stockholders' Equity Note [Abstract] | |
Other Comprehensive Income | Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31: 2019 (Millions of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive loss at Jan. 1 $ (20.2 ) $ (2.9 ) $ (23.1 ) Other comprehensive loss before reclassifications (net of taxes of $0 and $(0.1) respectively) — (0.4 ) (0.4 ) Losses reclassified from net accumulated other comprehensive loss: Interest rate derivatives (net of taxes of $0.3 and $0, respectively) (a) 0.8 (a) — 0.8 Amortization of net actuarial loss (net of taxes of $0 and $0.1, respectively) — 0.2 (b) 0.2 Net current period other comprehensive income (loss) 0.8 (0.2 ) 0.6 Accumulated other comprehensive loss at Dec. 31 $ (19.4 ) $ (3.1 ) $ (22.5 ) (a) Included in interest charges. (b) Included in the computation of net periodic pension and postretirement benefit costs. See Note 9 for further information. 2018 (Millions of Dollars) Gains and Losses on Cash Flow Hedges Unrealized Gains and Losses on Marketable Securities Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive (loss) income at Jan. 1 $ (20.9 ) $ 0.1 $ (3.7 ) $ (24.5 ) Other comprehensive (loss) income before reclassifications (net of taxes of $0, $0 and $0.3, respectively) — (0.1 ) 0.6 0.5 Losses reclassified from net accumulated other comprehensive loss: Interest rate derivatives (net of taxes of $0.3, $0 and $0, respectively) 0.7 (a) — — 0.7 Amortization of net actuarial loss (net of taxes of $0, $0 and $0.1, respectively) — — 0.2 (b) 0.2 Net current period other comprehensive income (loss) 0.7 (0.1 ) 0.8 1.4 Accumulated other comprehensive loss at Dec. 31 $ (20.2 ) $ — $ (2.9 ) $ (23.1 ) (a) Included in interest charges. (b) |
Segments and Related Informatio
Segments and Related Information | 12 Months Ended |
Dec. 31, 2019 | |
Segment Reporting [Abstract] | |
Segment Information | -Minnesota evaluates performance based on profit or loss generated from the product or service provided. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment. NSP-Minnesota has the following reportable segments: • Regulated Electric — The regulated electric utility segment generates electricity which is transmitted and distributed in Minnesota, North Dakota and South Dakota. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. The regulated electric utility segment also includes NSP-Minnesota’s wholesale commodity and trading operations; and • Regulated Natural Gas — The regulated natural gas utility segment transports, stores and distributes natural gas in portions of Minnesota and North Dakota. NSP-Minnesota presents Other, which includes operating segments, with revenues below the necessary quantitative thresholds. Those operating segments primarily include appliance repair services, non-utility real estate activities and revenues associated with processing solid waste into refuse-derived fuel. Asset and capital expenditure information is not provided for NSP-Minnesota’s reportable segments because as an integrated electric and natural gas utility, NSP-Minnesota operates significant assets that are not dedicated to a specific business segment, and reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations, which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis. To report income from operations for regulated electric and regulated natural gas utility segments, the majority of costs are directly assigned to each segment. However, some costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators. A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising. NSP-Minnesota’s segment information is as follows: (Millions of Dollars) 2019 2018 2017 Regulated Electric Operating revenues (a) $ 4,506.6 $ 4,508.0 $ 4,541.7 Intersegment revenues 0.6 0.8 0.6 Total operating revenue $ 4,507.2 $ 4,508.8 $ 4,542.3 Depreciation and amortization 742.1 697.8 661.3 Interest charges and financing costs 205.3 199.5 199.8 Income tax expense 36.1 16.4 179.9 Net income 491.0 450.4 462.5 Regulated Natural Gas Operating revenues (a) $ 571.3 $ 583.1 $ 531.9 Intersegment revenues 0.8 0.5 0.5 Total operating revenue $ 572.1 $ 583.6 $ 532.4 Depreciation and amortization 48.8 43.3 38.7 Interest charges and financing costs 15.6 14.8 13.5 Income tax expense 12.4 10.2 10.0 Net income 40.0 34.2 28.4 Other Operating revenues (a) $ 33.9 $ 30.8 $ 28.4 Depreciation and amortization 0.4 0.5 0.6 Interest charges and financing costs — — — Income tax expense (1.1 ) 0.6 9.8 Net income (loss) 11.6 7.7 (0.8 ) Consolidated Total Total operating revenue (a) $ 5,113.2 $ 5,123.2 $ 5,103.1 Reconciling eliminations (1.4 ) (1.3 ) (1.1 ) Consolidated total revenue $ 5,111.8 $ 5,121.9 $ 5,102.0 Depreciation and amortization 791.3 741.6 700.6 Interest charges and financing costs 220.9 214.3 213.3 Income tax expense 47.4 27.2 199.7 Net income 542.6 492.3 490.1 (a) Operating revenues include $457.4 million , $473.7 million , and $490.2 million of intercompany revenue for the years ended Dec. 31, 2019 , 2018 and 2017 , respectively. See Note 13 for further information. |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2019 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy Inc., including NSP-Minnesota. The services are provided and billed to each subsidiary in accordance with service agreements executed by each subsidiary. NSP-Minnesota uses the services provided by Xcel Energy Services Inc. whenever possible. Costs are charged directly to the subsidiary and are allocated if they cannot be directly assigned. Xcel Energy Inc., NSP-Minnesota, PSCo and SPS have established a utility money pool arrangement. See Note 5 for further information. The electric production and transmission costs of the entire NSP System are shared by NSP-Minnesota and NSP-Wisconsin. The Interchange Agreement provides for the sharing of all costs of generation and transmission facilities of the system, including capital costs. Significant affiliate transactions among the companies and related parties including billings under the Interchange Agreement for the years ended Dec. 31: (Millions of Dollars) 2019 2018 2017 Operating revenues: Electric $ 457.4 $ 473.7 $ 490.2 Gas 0.5 — — Operating expenses: Purchased power 60.5 61.1 66.8 Transmission expense 116.2 96.8 110.5 Other operating expenses — paid to Xcel Energy Services Inc. 533.2 534.8 539.4 Interest expense 0.7 0.3 — Accounts receivable and payable with affiliates at Dec. 31 were: 2019 2018 (Millions of Dollars) Accounts Receivable Accounts Payable Accounts Receivable Accounts Payable NSP-Wisconsin $ 7.9 $ — $ 11.0 $ — PSCo — 18.8 — 17.9 SPS — 4.2 — 4.7 Other subsidiaries of Xcel Energy Inc. 35.9 53.0 — 87.1 $ 43.8 $ 76.0 $ 11.0 $ 109.7 |
Summarized Quarterly Financial
Summarized Quarterly Financial Data (Unaudited) | 12 Months Ended |
Dec. 31, 2019 | |
Quarterly Financial Information Disclosure [Abstract] | |
Summarized Quarterly Financial Data (Unaudited) | Quarter Ended (Millions of Dollars) March 31, 2019 June 30, 2019 Sept. 30, 2019 Dec. 31, 2019 Operating revenues $ 1,350.5 $ 1,185.0 $ 1,344.6 $ 1,231.7 Operating income 167.3 147.3 291.0 181.3 Net income 113.2 95.9 208.6 124.9 Quarter Ended (Millions of Dollars) March 31, 2018 June 30, 2018 Sept. 30, 2018 Dec. 31, 2018 Operating revenues $ 1,310.8 $ 1,187.7 $ 1,351.8 $ 1,271.6 Operating income (a) 171.4 150.1 259.5 135.5 Net income 111.7 92.4 201.2 87.0 (a) In 2018, NSP-Minnesota implemented ASU No. 2017-07 related to net periodic benefit cost, which resulted in retrospective reclassification of pension costs from O&M expense to other income. |
Schedule II, Valuation and Qual
Schedule II, Valuation and Qualifying Accounts | 12 Months Ended |
Dec. 31, 2019 | |
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract] | |
Schedule II, Valuation and Qualifying Accounts | SCHEDULE II NSP-Minnesota and Subsidiaries Valuation and Qualifying Accounts Years Ended Dec. 31 Allowance for bad debts (Millions of Dollars) 2019 2018 2017 Balance at Jan. 1 $ 23.5 $ 21.3 $ 20.0 Additions charged to costs and expenses 13.0 16.2 15.7 Additions charged to other accounts (a) 6.5 4.1 3.8 Deductions from reserves (b) (20.0 ) (18.1 ) (18.2 ) Balance at Dec. 31 $ 23.0 $ 23.5 $ 21.3 (a) Recovery of amounts previously written off. (b) Deductions related primarily to bad debt write-offs. |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2019 | |
Accounting Policies [Abstract] | |
Business and System of Accounts | General — NSP-Minnesota is engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and in the regulated purchase, transportation, distribution and sale of natural gas. NSP-Minnesota’s consolidated financial statements are presented in accordance with GAAP. All of NSP-Minnesota’s underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions. Certain amounts in the 2018 and 2017 consolidated financial statements or notes have been reclassified to conform to the 2019 presentation for comparative purposes; however, such reclassifications did not affect net income, total assets, liabilities, equity or cash flows. |
Principles of Consolidation | NSP-Minnesota’s consolidated financial statements include its wholly-owned subsidiaries. In the consolidation process, all intercompany transactions and balances are eliminated. NSP-Minnesota has investments in certain plants and transmission facilities jointly owned with nonaffiliated utilities. NSP-Minnesota’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets and NSP-Minnesota’s proportionate share of the operating costs associated with these facilities is included in its consolidated statements of income. |
Subsequent Events | NSP-Minnesota has evaluated events occurring after Dec. 31, 2019 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. |
Use of Estimates | Use of Estimates — NSP-Minnesota uses estimates based on the best information available in recording transactions and balances resulting from business operations. Estimates are used on items such as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. Recorded estimates are revised when better information becomes available or actual amounts can be determined. Revisions can affect operating results. |
Regulatory Accounting | Regulatory Accounting — NSP-Minnesota accounts for income and expense items in accordance with accounting guidance for regulated operations. Under this guidance: • Certain costs, which would otherwise be charged to expense or other comprehensive income, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and • Certain credits, which would otherwise be reflected as income or other comprehensive income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred. Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process. If changes in the regulatory environment occur, NSP-Minnesota may no longer be eligible to apply this accounting treatment, and may be required to eliminate regulatory assets and liabilities from its balance sheet. Such changes could have a material effect on NSP-Minnesota’s results of operations, financial condition and cash flows. See Note 4 for further information. |
Income Taxes | Income Taxes — NSP-Minnesota accounts for income taxes using the asset and liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. NSP-Minnesota defers income taxes for all temporary differences between pretax financial and taxable income and between the book and tax bases of assets and liabilities. NSP-Minnesota uses rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the period that includes the enactment date. The effects of NSP-Minnesota’s tax rate changes are generally subject to a normalization method of accounting. Therefore, the revaluation of most of its net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability, which will be refundable to utility customers over the remaining life of the related assets. A tax rate increase would result in the establishment of a similar regulatory asset. Reversal of certain temporary differences are accounted for as current income tax expense due to the effects of past regulatory practices, when deferred taxes were not required to be recorded due to the use of flow through accounting for ratemaking purposes. Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of regulatory assets and liabilities related to income taxes. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. NSP-Minnesota follows the applicable accounting guidance to measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns. NSP-Minnesota recognizes a tax position in its consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position. Recognition of changes in uncertain tax positions are reflected as a component of income tax expense. NSP-Minnesota reports interest and penalties related to income taxes within the other income and interest charges in the consolidated statements of income. Xcel Energy Inc. and its subsidiaries, including NSP-Minnesota, file consolidated federal income tax returns as well as consolidated or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to its subsidiaries based on separate company computations. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with consolidated state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries. See Note 7 for further information. |
Property, Plant and Equipment and Depreciation | Property, Plant and Equipment and Depreciation in Regulated Operations — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property. Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary. NSP-Minnesota records depreciation expense using the straight-line method over the plant’s useful life. Actuarial life studies are performed and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.7% for 2019, 3.6% for 2018 and 3.6% for 2017. See Note 3 for further information. |
Asset Retirement Obligations | AROs — NSP-Minnesota accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion, and the capitalized costs are depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO. NSP-Minnesota also recovers through rates certain future plant removal costs in addition to AROs. The accumulated removal costs for these obligations are reflected in the consolidated balance sheets as a regulatory liability. See Note 10 for further information. |
Nuclear Decommissioning | Nuclear Decommissioning — Nuclear decommissioning studies that estimate NSP-Minnesota’s costs of decommissioning its nuclear power plants are performed at least every three years and submitted to the state commissions for approval. For ratemaking purposes, NSP-Minnesota recovers regulator-approved decommissioning costs of its nuclear power plants over each facility’s expected service life, typically based on the triennial decommissioning studies. The studies consider estimated future costs of decommissioning and the market value of investments in trust funds and recommend annual funding amounts. Amounts collected in rates are deposited in the trust funds. For financial reporting purposes, NSP-Minnesota accounts for nuclear decommissioning as an ARO. Restricted funds for the payment of future decommissioning expenditures for NSP-Minnesota’s nuclear facilities are included in nuclear decommissioning fund and other assets on the consolidated balance sheets. See Notes 8 and 10 for further information. |
Benefit Plans and Other Postretirement Benefits | Benefit Plans and Other Postretirement Benefits — NSP-Minnesota maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans requires management to make various assumptions and estimates. Certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are deferred as regulatory assets and liabilities, rather than recorded as other comprehensive income, based on regulatory recovery mechanisms. See Note 9 for further information. |
Environmental Costs | Environmental Costs — Environmental costs are recorded when it is probable NSP-Minnesota is liable for remediation costs and the liability can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant. Estimated remediation costs are regularly adjusted as estimates are revised and remediation proceeds. If other participating potentially responsible parties exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for NSP-Minnesota’s expected share of the cost. Future costs of restoring sites are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability. See Note 10 for further information. |
Revenue From Contracts With Customers | Revenue from Contracts with Customers — Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. NSP-Minnesota recognizes revenue that corresponds to the price of the energy delivered to the customer. The measurement of energy sales to customers is generally based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recognized. NSP-Minnesota does not recognize a separate financing component of its collections from customers as contract terms are short-term in nature. NSP-Minnesota presents its revenues net of any excise or sales taxes or fees. NSP-Minnesota recognizes sales to both native load and other end use customers on a gross basis in electric revenues and cost of sales. Revenues and charges for short term wholesale sales of excess energy transacted through RTOs are also recorded on a gross basis. Other RTO revenues and charges are recorded on a net basis in cost of sales. NSP-Minnesota has various rate-adjustment mechanisms that provide for the recovery of natural gas, electric fuel and purchased energy costs. Cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred. When applicable, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets. See Note 6 for further information. |
Cash and Cash Equivalents | Cash and Cash Equivalents — NSP-Minnesota considers investments in instruments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. |
Accounts Receivable and Allowance for Bad Debts | Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. NSP-Minnesota establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers. As of Dec. 31, 2019 and 2018, the allowance for bad debts was $23.0 million and $23.5 million , respectively. |
Inventory | Inventory — Inventory is recorded at average cost and consisted of the following: (Millions of Dollars) Dec. 31, 2019 Dec. 31, 2018 Inventories Materials and supplies $ 175.6 $ 176.3 Fuel 103.2 88.5 Natural gas 26.0 34.6 Total inventories $ 304.8 $ 299.4 |
Fair Value Measurements | Fair Value Measurements — NSP-Minnesota presents cash equivalents, interest rate derivatives, commodity derivatives and nuclear decommissioning fund assets at estimated fair values in its consolidated financial statements. Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted NAVs. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used to establish fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price, NSP-Minnesota may use quoted prices for similar contracts or internally prepared valuation models to determine fair value. For the pension and postretirement plan assets and nuclear decommissioning fund, published trading data and pricing models, generally using the most observable inputs available, are utilized to estimate fair value for each security. See Notes 8 and 9 for further information. |
Derivative Instruments | Derivative Instruments — NSP-Minnesota uses derivative instruments in connection with its interest rate, utility commodity price, vehicle fuel price and commodity trading activities, including forward contracts, futures, swaps and options. Any derivative instruments not qualifying for the normal purchases and normal sales exception are recorded on the consolidated balance sheets at fair value as derivative instruments. Classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues; hedging transactions for vehicle fuel costs are recorded as a component of capital projects and O&M costs; and interest rate hedging transactions are recorded as a component of interest expense. Normal Purchases and Normal Sales — NSP-Minnesota enters into contracts for purchases and sales of commodities for use in its operations. At inception, contracts are evaluated to determine whether a derivative exists and/or whether an instrument may be exempted from derivative accounting if designated as a normal purchase or normal sale. See Note 8 for further information. |
Commodity Trading Operations | Commodity Trading Operations — All applicable gains and losses related to commodity trading activities are shown on a net basis in electric operating revenues in the consolidated statements of income. Commodity trading activities are not associated with energy produced from NSP-Minnesota’s generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms. See Note 8 for further information. |
AFUDC | AFUDC — AFUDC represents the cost of capital used to finance utility construction activity. AFUDC is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in NSP-Minnesota’s rate base for establishing utility rates. |
Alternative Revenue Programs | Alternative Revenue — Certain rate rider mechanisms (including decoupling and CIP programs) qualify as alternative revenue programs. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate. When certain criteria are met, including expected collection within 24 months , revenue is recognized equal to the revenue requirement, which may include incentives and return on rate base items. Billing amounts are revised periodically for differences between total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers. See Note 6 for further information. Conservation Programs — Costs incurred for CIP programs are deferred if it is probable future revenue will recover the incurred cost. Revenues recognized for incentive programs for the recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the year they are earned. Regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers. |
Emission Allowances | Emission Allowances — Emission allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emission allowances and sales of these allowances are included in electric revenues. |
Nuclear Refueling Outage Costs | Nuclear Refueling Outage Costs — NSP-Minnesota uses a deferral and amortization method for nuclear refueling costs. This method amortizes costs over the period between refueling outages consistent with rate recovery. |
Renewable Energy Credits | RECs — Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. Sales of RECs are recorded in electric revenues on a gross basis. The cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense. |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Balance Sheet Related Disclosures [Abstract] | |
Schedule of Utility Inventory [Table Text Block] | Inventory is recorded at average cost and consisted of the following: (Millions of Dollars) Dec. 31, 2019 Dec. 31, 2018 Inventories Materials and supplies $ 175.6 $ 176.3 Fuel 103.2 88.5 Natural gas 26.0 34.6 Total inventories $ 304.8 $ 299.4 |
Property Plant and Equipment (T
Property Plant and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Property, Plant and Equipment [Abstract] | |
Public Utility Property, Plant, and Equipment | Major classes of property, plant and equipment (Millions of Dollars) Dec. 31, 2019 Dec. 31, 2018 Property, plant and equipment Electric plant $ 18,519.5 $ 17,749.3 Natural gas plant 1,562.9 1,475.5 Common and other property 886.7 803.1 CWIP 846.3 615.1 Total property, plant and equipment 21,815.4 20,643.0 Less accumulated depreciation (7,945.3 ) (7,454.8 ) Nuclear fuel 2,909.8 2,770.4 Less accumulated amortization (2,535.9 ) (2,416.9 ) Property, plant and equipment, net $ 14,244.0 $ 13,541.7 |
Schedule of Jointly Owned Utility Plants | Joint Ownership of Generation and Transmission Facilities Jointly owned assets as of Dec. 31, 2019 : (Millions of Dollars) Plant in Service Accumulated Depreciation CWIP Percent Owned Electric generation: Sherco Unit 3 $ 603.0 $ 426.3 $ 3.8 59 % Sherco common facilities 144.7 102.7 1.9 80 Sherco substation 4.8 3.5 — 59 Electric transmission: CapX2020 972.5 91.6 2.2 51 Grand Meadow 10.7 2.6 — 50 Total $ 1,735.7 $ 626.7 $ 7.9 |
Regulatory Assets and Liabili_2
Regulatory Assets and Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Regulatory Assets | Components of regulatory assets: (Millions of Dollars) See Note(s) Remaining Amortization Period Dec. 31, 2019 Dec. 31, 2018 Regulatory Assets Current Noncurrent Current Noncurrent Pension and retiree medical obligations 9 Various $ 27.5 $ 377.7 $ 28.1 $ 424.3 Excess deferred taxes — TCJA 7 Various 10.4 132.2 — 153.3 Net AROs (a) 1, 10 Plant lives — 117.9 — 323.4 Recoverable deferred taxes on AFUDC recorded in plant Plant lives — 114.8 — 117.6 Benson biomass PPA termination and asset purchase Ten years 9.4 72.7 9.8 85.8 Contract valuation adjustments (b) 1, 8 Term of related contract 15.5 62.1 14.1 76.0 Laurentian biomass PPA termination Five years 19.2 53.9 18.1 73.3 PI extended power update Sixteen years 3.1 52.6 3.1 55.8 Purchased power contracts costs Term of related contract 2.7 36.5 2.8 36.6 Nuclear refueling outage costs 1 One to two years 43.3 16.9 36.3 13.5 Sales true-up and revenue decoupling One to two years 53.8 16.3 38.3 6.7 Losses on reacquired debt Term of related debt 1.7 13.8 2.1 15.5 Conservation programs (c) 1 One to two years 18.1 13.5 34.5 21.1 Environmental remediation costs 1, 10 Pending future rate cases 1.3 11.8 1.3 14.3 Deferred purchased natural gas and electric energy costs One to three years 6.2 5.7 5.6 12.6 State commission adjustments Plant lives — 3.4 — 3.4 Renewable resources and environmental initiatives One to two years 72.2 0.6 39.2 0.4 Gas pipeline inspection and remediation costs Less than one year 26.2 — 27.4 — Other Various 9.5 22.6 19.6 20.5 Total regulatory assets $ 320.1 $ 1,125.0 $ 280.3 $ 1,454.1 (a) Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments. (b) Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. (c) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. |
Regulatory Liabilities | Components of regulatory liabilities: (Millions of Dollars) See Note(s) Remaining Amortization Period Dec. 31, 2019 Dec. 31, 2018 Regulatory Liabilities Current Noncurrent Current Noncurrent Deferred income tax adjustments and TCJA refunds (a) 7 Various $ 12.8 $ 1,388.9 $ 153.7 $ 1,465.1 Plant removal costs 1, 10 Plant lives — 520.3 — 484.6 ITC deferrals (b) 1 Various — 8.3 — 8.9 DOE Settlement Less than one year 27.0 — 13.0 — Deferred electric energy costs Less than one year 24.2 — 22.8 — Contract valuation adjustments (c) 1, 8 Less than one year 7.8 — 10.4 — Renewable resources and environmental initiatives Less than one year — — 8.8 — Other Various 69.2 19.6 53.7 26.1 Total regulatory liabilities (d) $ 141.0 $ 1,937.1 $ 262.4 $ 1,984.7 (a) Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA. (b) Includes impact of lower federal tax rate due to the TCJA. (c) Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. (d) Revenue subject for refund of $23.8 million and $12.5 million for 2019 and 2018, respectively, is included in other current liabilities. |
Borrowings and Other Financin_2
Borrowings and Other Financing Instruments (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Debt Disclosure [Abstract] | |
Money Pool [Table Text Block] | (Millions of Dollars, Except Interest Rates) Three Months Ended Dec. 31, 2019 Year Ended Dec. 31 2019 2018 2017 Borrowing limit $ 250 $ 250 $ 250 $ 250 Amount outstanding at period end — — — 85 Average amount outstanding 34 32 17 25 Maximum amount outstanding 119 250 143 142 Weighted average interest rate, computed on a daily basis 1.67 % 2.05 % 1.96 % 1.14 % Weighted average interest rate at period end N/A N/A N/A 1.18 |
Short Term Debt | Commercial paper outstanding for NSP-Minnesota was as follows: (Millions of Dollars, Except Interest Rates) Three Months Ended Dec. 31, 2019 Year Ended Dec. 31 2019 2018 2017 Borrowing limit $ 500 $ 500 $ 500 $ 500 Amount outstanding at period end 30 30 150 20 Average amount outstanding 2 71 38 62 Maximum amount outstanding 30 317 198 237 Weighted average interest rate, computed on a daily basis 2.05 % 2.59 % 2.08 % 1.10 % Weighted average interest rate at end of period 2.05 2.05 2.97 1.93 |
Schedule of Debt To Total Capitalization Ratio | Features of NSP-Minnesota’s credit facility: Debt-to-Total Capitalization Ratio (a) Amount Facility May Be Increased (millions) Additional Periods for Which a One-Year Extension May Be Requested (b) 2019 2018 48 % 48 % $ 100 2 (a) The credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65% . (b) |
Credit Facilities | Dec. 31, 2019 (in millions): Credit Facility (a) Drawn (b) Available $ 500 $ 40 $ 460 (a) This credit facility matures in June 2024 . (b) Includes outstanding commercial paper and letters of credit. |
Schedule of Long-Term Debt | Long term debt obligations for NSP-Minnesota as of Dec. 31 (millions of dollars): Financing Instrument Interest Rate Maturity Date 2019 2018 First mortgage bonds 2.20 % Aug. 15, 2020 $ 300 $ 300 First mortgage bonds 2.15 % Aug. 15, 2022 300 300 First mortgage bonds 2.60 % May 15, 2023 400 400 First mortgage bonds 7.13 % July 1, 2025 250 250 First mortgage bonds 6.50 % March 1, 2028 150 150 First mortgage bonds 5.25 % July 15, 2035 250 250 First mortgage bonds 6.25 % June 1, 2036 400 400 First mortgage bonds 6.20 % July 1, 2037 350 350 First mortgage bonds 5.35 % Nov. 1, 2039 300 300 First mortgage bonds 4.85 % Aug. 15, 2040 250 250 First mortgage bonds 3.40 % Aug. 15, 2042 500 500 First mortgage bonds 4.13 % May 15, 2044 300 300 First mortgage bonds 4.00 % Aug. 15, 2045 300 300 First mortgage bonds 3.60 % May 15, 2046 350 350 First mortgage bonds 3.60 % Sept. 15, 2047 600 600 First mortgage bonds (a) 2.90 % March 1, 2050 600 — Unamortized discount (31 ) (21 ) Unamortized debt issuance cost (48 ) (42 ) Current maturities (300 ) — Total long-term debt $ 5,221 $ 4,937 (a) 2019 financing |
Schedule of Maturities of Long-term Debt | Maturities of long-term debt are as follows: (Millions of Dollars) 2020 $ 300 2021 — 2022 300 2023 400 2024 — |
Dividend Payment Restrictions | Requirements and actuals as of Dec. 31, 2019 : Equity to Total Capitalization Ratio - Required Range Equity to Total Capitalization Ratio - Actual Low High 2019 47.1 % 57.5 % 52.3 % Unrestricted Retained Earnings Total Capitalization Limit on Total Capitalization $ 1.1 billion $ 11.6 billion $ 12.7 billion |
Revenues Revenues (Tables)
Revenues Revenues (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Revenue from Contract with Customer [Abstract] | |
Disaggregation of Revenue | NSP-Minnesota’s operating revenues consisted of the following: Year Ended Dec. 31, 2019 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 1,280.2 $ 303.0 $ 30.1 $ 1,613.3 C&I 2,054.3 228.6 — 2,282.9 Other 32.9 — 3.8 36.7 Total retail 3,367.4 531.6 33.9 3,932.9 Wholesale 210.1 — — 210.1 Transmission 216.0 — — 216.0 Interchange 458.7 — — 458.7 Other 11.9 9.8 — 21.7 Total revenue from contracts with customers 4,264.1 541.4 33.9 4,839.4 Alternative revenue and other 242.5 29.9 — 272.4 Total revenues $ 4,506.6 $ 571.3 $ 33.9 $ 5,111.8 Year Ended Dec. 31, 2018 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 1,308.4 $ 308.8 $ 27.2 $ 1,644.4 C&I 2,052.1 239.3 0.2 2,291.6 Other 36.5 — 3.4 39.9 Total retail 3,397.0 548.1 30.8 3,975.9 Wholesale 189.2 — — 189.2 Transmission 238.1 — — 238.1 Interchange 473.7 — — 473.7 Other 28.3 11.7 — 40.0 Total revenue from contracts with customers 4,326.3 559.8 30.8 4,916.9 Alternative revenue and other 181.7 23.3 — 205.0 Total revenues $ 4,508.0 $ 583.1 $ 30.8 $ 5,121.9 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | |
Summary of Statute of Limitations Applicable to Open Tax Years [Table Text Block] | NSP-Minnesota is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. Statute of limitations applicable to Xcel Energy’s consolidated federal income tax returns expire as follows: Tax Year(s) Expiration 2009 - 2013 June 2020 2014 - 2016 September 2020 |
Reconciliation of Unrecognized Tax Benefits | Unrecognized tax benefits - permanent vs temporary: (Millions of Dollars) Dec. 31, 2019 Dec. 31, 2018 Unrecognized tax benefit — Permanent tax positions $ 14.8 $ 11.6 Unrecognized tax benefit — Temporary tax positions 4.9 5.3 Total unrecognized tax benefit $ 19.7 $ 16.9 Changes in unrecognized tax benefits: (Millions of Dollars) 2019 2018 2017 Balance at Jan. 1 $ 16.9 $ 18.1 $ 60.8 Additions based on tax positions related to the current year 2.6 2.0 2.7 Reductions based on tax positions related to the current year (0.5 ) (0.3 ) (1.7 ) Additions for tax positions of prior years 0.7 0.6 5.7 Reductions for tax positions of prior years — (1.1 ) (49.4 ) Settlements with taxing authorities — (2.4 ) — Balance at Dec. 31 $ 19.7 $ 16.9 $ 18.1 |
Tax Benefits Associated with NOL and Tax Credit Carryforwards | Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards: (Millions of Dollars) Dec. 31, 2019 Dec. 31, 2018 NOL and tax credit carryforwards $ (16.3 ) $ (12.7 ) |
Interest Payable related to Unrecognized Tax Benefits | Interest payable related to unrecognized tax benefits: (Millions of Dollars) 2019 2018 2017 Payable for interest related to unrecognized tax benefits at Jan. 1 $ (1.2 ) $ (0.9 ) $ (2.0 ) Interest (expense) income related to unrecognized tax benefits (0.4 ) (0.3 ) 1.1 Payable for interest related to unrecognized tax benefits at Dec. 31 $ (1.6 ) $ (1.2 ) $ (0.9 ) |
NOL and Tax Credit Carryforwards | NOL amounts represent the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows: (Millions of Dollars) 2019 2018 Federal tax credit carryforwards $ 449.0 $ 379.4 State NOL carryforwards 133.0 221.2 Valuation allowances for state NOL carryforwards (0.5 ) (0.8 ) State tax credit carryforwards, net of federal detriment (a) 77.5 87.9 Valuation allowances for state credit carryforwards, net of federal benefit (b) (65.9 ) (78.5 ) (a) State tax credit carryforwards are net of federal detriment of $20.6 million and $23.4 million as of Dec. 31, 2019 and 2018, respectively. (b) Valuation allowances for state tax credit carryforwards were net of federal benefit of $17.5 million and $20.9 million as of Dec. 31, 2019 and 2018, respectively. |
Schedule of Effective Income Tax Rate Reconciliation | Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. Effective income tax rate for years ended Dec. 31: 2019 2018 (a) 2017 (a) Federal statutory rate 21.0 % 21.0 % 35.0 % State income tax on pretax income, net of federal tax effect 7.1 7.1 5.8 Increases (decreases) in tax from: Wind PTCs (11.8 ) (13.6 ) (11.4 ) Plant regulatory differences (b) (7.4 ) (8.8 ) (0.3 ) Other tax credits, net of NOL & tax credit allowances (1.5 ) (1.1 ) (1.0 ) Change in unrecognized tax benefits 0.5 0.1 (1.6 ) Tax reform — — 2.7 Other, net 0.1 0.5 (0.2 ) Effective income tax rate 8.0 % 5.2 % 29.0 % (a) Prior periods have been reclassified to conform to current year presentation. (b) |
Schedule of Components of Income Tax Expense (Benefit) | Components of income tax expense for years ended Dec. 31: (Millions of Dollars) 2019 2018 2017 Current federal tax expense (benefit) $ 80.7 $ (16.8 ) $ 29.6 Current state tax expense 7.9 5.2 14.7 Current change in unrecognized tax benefit (0.8 ) (1.1 ) (36.2 ) Deferred federal tax (benefit) expense (86.2 ) (2.4 ) 121.6 Deferred state tax expense 43.2 42.1 46.7 Deferred change in unrecognized tax expense 4.0 1.6 24.9 Deferred ITCs (1.4 ) (1.4 ) (1.6 ) Total income tax expense $ 47.4 $ 27.2 $ 199.7 Components of deferred income tax expense as of Dec. 31: (Millions of Dollars) 2019 2018 2017 Deferred tax expense (benefit) excluding items below $ 96.7 $ 70.1 (1,176.4 ) Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities (135.4 ) (28.2 ) 1,369.9 Tax expense allocated to other comprehensive income, net of adoption of ASU No. 2018-02, and other (0.3 ) (0.6 ) (0.3 ) Deferred tax expense $ (39.0 ) $ 41.3 $ 193.2 |
Schedule of Deferred Tax Assets and Liabilities | Components of the net deferred tax liability as of Dec. 31: (Millions of Dollars) 2019 2018 (a) Deferred tax liabilities: Differences between book and tax bases of property $ 2,361.0 $ 2,257.6 Regulatory assets 257.4 260.8 Operating lease assets 169.6 — Pension expense 68.4 64.7 Other 10.2 9.1 Total deferred tax liabilities $ 2,866.6 $ 2,592.2 Deferred tax assets: Tax credit carryforward $ 526.5 $ 467.3 Regulatory Liabilities 364.9 380.5 Operating lease liabilities 169.6 — NOL and tax credit valuation allowances (66.0 ) (78.6 ) Other employee benefits 37.5 38.6 Rate refund 11.0 49.7 NOL carryforward 10.4 17.9 Deferred investment tax credits 5.9 6.4 Other 27.7 28.0 Total deferred tax assets $ 1,087.5 $ 909.8 Net deferred tax liability $ 1,779.1 $ 1,682.4 (a) Prior periods have been reclassified to conform to current year presentation. |
Fair Value of Financial Asset_2
Fair Value of Financial Assets and Liabilities (Tables) | 12 Months Ended | |
Dec. 31, 2019 | ||
Fair Value Disclosures [Abstract] | ||
Fair Value Disclosures [Text Block] | Fair Value Measurements The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. • Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices; • Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs; and • Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation. Specific valuation methods include: Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted NAV. Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds are measured using NAVs. The investments in commingled funds may be redeemed for NAV with proper notice. Private equity commingled fund investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate commingled funds investments may be redeemed with proper notice, however, may be delayed or discounted as a result of fund illiquidity. Investments in debt securities — Fair values for debt securities are determined by a third-party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities. Interest rate derivatives — The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts. Commodity derivatives — The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When contractual settlements relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification. Electric commodity derivatives held by NSP-Minnesota include transmission congestion instruments, generally referred to as FTRs. FTRs purchased from a RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path. The value of an FTR is derived from, and designed to offset, the cost of transmission congestion. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR. If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Given the limited observability of important inputs to the value of FTRs between auction processes, including expected plant operating schedules and retail and wholesale demand, fair value measurements for FTRs have been assigned a Level 3. Non-trading monthly FTR settlements are included in fuel and purchased energy cost recovery mechanisms, and therefore changes in the fair value of the yet to be settled portions of most FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of NSP-Minnesota’s FTRs relative to its electric utility operations, the numerous unobservable quantitative inputs pertinent to the value of FTRs are immaterial to the consolidated financial statements of NSP-Minnesota. Non-Derivative Fair Value Measurements Nuclear Decommissioning Fund — The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning these facilities. The fund contains cash equivalents, debt securities, equity securities and other investments. NSP-Minnesota uses the MPUC approved asset allocation for the escrow and investment targets by asset class for both the escrow and qualified trust. NSP-Minnesota recognizes the costs of funding the decommissioning over the lives of the nuclear plants, assuming rate recovery of all costs. Realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund are deferred as a component of the regulatory asset. Unrealized gains for the nuclear decommissioning fund were $705.5 million and $450.1 million as of Dec. 31, 2019 and 2018 , respectively, and unrealized losses were $5.9 million and $44.8 million as of Dec. 31, 2019 and 2018 , respectively. Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund: Dec. 31, 2019 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total Nuclear decommissioning fund (a) Cash equivalents $ 33.4 $ 33.4 $ — $ — $ — $ 33.4 Commingled funds 732.8 — — — 934.9 934.9 Debt securities 489.2 — 495.2 12.7 — 507.9 Equity securities 484.6 962.0 1.4 — — 963.4 Total $ 1,740.0 $ 995.4 $ 496.6 $ 12.7 $ 934.9 $ 2,439.6 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $55.6 million of rabbi trust assets and miscellaneous investments. Dec. 31, 2018 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total Nuclear decommissioning fund (a) Cash equivalents $ 24.3 $ 24.3 $ — $ — $ — $ 24.3 Commingled funds 758.1 79.2 — — 819.1 898.3 Debt securities 465.6 — 435.6 — — 435.6 Equity securities 401.4 696.5 — — — 696.5 Total $ 1,649.4 $ 800.0 $ 435.6 $ — $ 819.1 $ 2,054.7 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $52.5 million of rabbi trust assets and miscellaneous investments. For the years ended Dec. 31, 2019 and 2018 , there were immaterial Level 3 nuclear decommissioning fund investments or transfer of amounts between levels. Contractual maturity dates of debt securities in the nuclear decommissioning fund as of Dec. 31, 2019 : Final Contractual Maturity (Millions of Dollars) Due in 1 Year or Less Due in 1 to 5 Years Due in 5 to 10 Years Due after 10 Years Total Debt securities $ (6.8 ) $ 110.5 $ 246.1 $ 158.1 $ 507.9 Rabbi Trusts NSP-Minnesota has established a rabbi trust to provide partial funding for future deferred compensation plan distributions. Cost and fair value of assets held in rabbi trusts: Dec. 31, 2019 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Total Rabbi Trusts (a) Cash equivalents $ 1.2 $ 1.2 $ — $ — $ 1.2 Mutual funds 11.4 13.1 — — 13.1 Total $ 12.6 $ 14.3 $ — $ — $ 14.3 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet. Dec. 31, 2018 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Total Rabbi Trusts (a) Cash equivalents $ 0.4 $ 0.4 $ — $ — $ 0.4 Mutual funds 10.8 10.7 — — 10.7 Total $ 11.2 $ 11.1 $ — $ — $ 11.1 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet. Derivative Fair Value Measurements NSP-Minnesota enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices. Interest Rate Derivatives — NSP-Minnesota enters into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes. As of Dec. 31, 2019 , accumulated other comprehensive losses related to interest rate derivatives included $0.8 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings. Wholesale and Commodity Trading Risk — NSP-Minnesota conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. NSP-Minnesota is allowed to conduct these activities within guidelines and limitations as approved by its risk management committee, comprised of management personnel not directly involved in activities governed by this policy. Commodity Derivatives — NSP-Minnesota enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale, FTRs, vehicle fuel, and weather derivatives. As of Dec. 31, 2019 , NSP-Minnesota had no commodity derivative contracts designated as cash flow hedges. NSP-Minnesota may enter into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, but may not be designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. Immaterial amounts to income related to the ineffectiveness of cash flow hedges were recorded for the years ended Dec. 31, 2019 and 2018 . As of Dec. 31, 2019 , there were immaterial net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses or related amounts expected to be reclassified into earnings during the next 12 months. NSP-Minnesota enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of amounts credited to customers under margin-sharing mechanisms. Gross notional amounts of commodity forwards, options and FTRs at Dec. 31: (Amounts in Millions) (a) (b) 2019 2018 MWh of electricity 79.1 56.8 MMBtu of natural gas 77.8 42.7 (a) Amounts are not reflective of net positions in the underlying commodities. (b) Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise. Consideration of Credit Risk and Concentrations — NSP-Minnesota continuously monitors the creditworthiness of counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets. NSP-Minnesota employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. NSP-Minnesota’s most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities. As of Dec. 31, 2019 , eight of NSP-Minnesota’s 10 most significant counterparties for these activities, comprising $54.2 million or 68% of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings. Two of the 10 most significant counterparties, comprising $15.8 million or 20% of this credit exposure, were not rated by these external agencies, but based on NSP-Minnesota’s internal analysis, had credit quality consistent with investment grade. Nine of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities. Qualifying Cash Flow Hedges — Financial impact of qualifying interest rate and vehicle fuel cash flow hedges on NSP-Minnesota’s accumulated other comprehensive loss, included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income: (Millions of Dollars) 2019 2018 2017 Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 $ (20.2 ) $ (20.9 ) $ (18.2 ) After-tax net unrealized gains related to derivatives accounted for as hedges — — 0.1 After-tax net realized losses on derivative transactions reclassified into earnings 0.8 0.7 0.9 Adoption of ASU. 2018-02 (a) — — (3.7 ) Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 $ (19.4 ) $ (20.2 ) $ (20.9 ) (a) In 2017, NSP-Minnesota implemented ASU No. 2018-02 related to TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings. Impact of derivative activity: Pre-Tax Fair Value (Millions of Dollars) Accumulated Other Comprehensive Loss Regulatory (Assets) and Liabilities Year Ended Dec. 31, 2019 Other derivative instruments Electric commodity $ — $ 1.5 Natural gas commodity — (2.9 ) Total $ — $ (1.4 ) Year Ended Dec. 31, 2018 Other derivative instruments Electric commodity $ — $ (5.5 ) Natural gas commodity — 1.8 Total $ — $ (3.7 ) Year Ended Dec. 31, 2017 Derivatives designated as cash flow hedges Vehicle fuel and other commodity $ 0.1 $ — Total $ 0.1 $ — Other derivative instruments Electric commodity — 9.3 Natural gas commodity — (1.9 ) Total $ — $ 7.4 Pre-Tax (Gains) Losses Pre-Tax Gains (Losses) (Millions of Dollars) Accumulated Other Comprehensive Loss Regulatory Year Ended Dec. 31, 2019 Derivatives designated as cash flow hedges Interest rate $ 1.1 (a) $ — $ — Total $ 1.1 $ — $ — Other derivative instruments Commodity trading $ — $ — $ (0.7 ) (c) Electric commodity — 0.8 (d) — Natural gas commodity — 0.9 (e) (2.5 ) (e) Total $ — $ 1.7 $ (3.2 ) Year Ended Dec. 31, 2018 Derivatives designated as cash flow hedges Interest rate $ 1.1 (a) $ — $ — Vehicle fuel and other commodity (0.1 ) (b) — — Total $ 1.0 $ — $ — Other derivative instruments Commodity trading $ — $ — $ 10.9 (c) Electric commodity — 3.3 (d) — Natural gas commodity — (1.9 ) (e) (1.3 ) (e) Total $ — $ 1.4 $ 9.6 Year Ended Dec. 31, 2017 Derivatives designated as cash flow hedges Interest rate $ 1.5 (a) $ — $ — Total $ 1.5 $ — $ — Other derivative instruments Commodity trading $ — $ — $ 9.4 (c) Electric commodity — (13.8 ) (d) — Natural gas commodity — 1.0 (e) (1.2 ) (e) Total $ — $ (12.8 ) $ 8.2 (a) Amounts are recorded to interest charges. (b) Amounts are recorded to O&M expenses. (c) Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate. (d) Amounts are recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate. (e) Amounts are recorded to cost of natural gas sold and transported. These derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms, and reclassified out of income as regulatory assets and liabilities, as appropriate. NSP-Minnesota had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2019 , 2018 and 2017 . Credit Related Contingent Features — Contract provisions for derivative instruments that NSP-Minnesota enters into, including those accounted for as normal purchase-normal sale contracts and therefore not reflected on the consolidated balance sheets, may require the posting of collateral or settlement of the contracts for various reasons, including if NSP-Minnesota’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies, or for cross-default contractual provisions if there was a failure under other financing arrangements related to payment terms or other covenants. As of Dec. 31, 2019 and 2018 , there were $7.1 million and no derivative instruments in a liability position with such underlying contract provisions, respectfully. Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that NSP-Minnesota’s ability to fulfill its contractual obligations is reasonably expected to be impaired. NSP-Minnesota had no collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 2019 and 2018 . Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2019 and 2018 : Dec. 31, 2019 Dec. 31, 2018 Fair Value Fair Value Netting (a) Fair Value Fair Value Netting (a) (Millions of Dollars) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Current derivative assets Other derivative instruments: Commodity trading $ 1.6 $ 39.5 $ 23.6 $ 64.7 $ (42.1 ) $ 22.6 $ 1.1 $ 27.1 $ 2.2 $ 30.4 $ (16.0 ) $ 14.4 Electric commodity — — 8.7 8.7 (0.9 ) 7.8 — — 10.5 10.5 (0.1 ) 10.4 Natural gas commodity — 2.1 — 2.1 — 2.1 — 1.0 — 1.0 — 1.0 Total current derivative assets $ 1.6 $ 41.6 $ 32.3 $ 75.5 $ (43.0 ) 32.5 $ 1.1 $ 28.1 $ 12.7 $ 41.9 $ (16.1 ) 25.8 PPAs (b) — — Current derivative instruments $ 32.5 $ 25.8 Noncurrent derivative assets Other derivative instruments: Commodity trading $ 8.5 $ 29.4 $ 6.0 $ 43.9 $ (34.8 ) $ 9.1 $ — $ 25.3 $ 5.0 $ 30.3 $ (13.4 ) $ 16.9 Total noncurrent derivative assets $ 8.5 $ 29.4 $ 6.0 $ 43.9 $ (34.8 ) 9.1 $ — $ 25.3 $ 5.0 $ 30.3 $ (13.4 ) 16.9 PPAs (b) 0.1 0.1 Noncurrent derivative instruments $ 9.2 $ 17.0 Dec. 31, 2019 Dec. 31, 2018 Fair Value Fair Value Netting (a) Fair Value Fair Value Netting (a) (Millions of Dollars) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Current derivative liabilities Other derivative instruments: Commodity trading $ 2.2 $ 42.1 $ 15.0 $ 59.3 $ (49.8 ) $ 9.5 $ 1.4 $ 23.9 $ 1.7 $ 27.0 $ (24.5 ) $ 2.5 Electric commodity — — 1.0 1.0 (1.0 ) — — — 0.1 0.1 (0.1 ) — Natural gas commodity — 1.7 — 1.7 — 1.7 — — — — — — Total current derivative liabilities $ 2.2 $ 43.8 $ 16.0 $ 62.0 $ (50.8 ) 11.2 $ 1.4 $ 23.9 $ 1.8 $ 27.1 $ (24.6 ) 2.5 PPAs (b) 13.8 14.0 Current derivative instruments $ 25.0 $ 16.5 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ 2.0 $ 32.3 $ 17.0 $ 51.3 $ (3.3 ) $ 48.0 $ 0.1 $ 16.0 $ 1.6 $ 17.7 $ 17.9 $ 35.6 Total noncurrent derivative liabilities $ 2.0 $ 32.3 $ 17.0 $ 51.3 $ (3.3 ) 48.0 $ 0.1 $ 16.0 $ 1.6 $ 17.7 $ 17.9 35.6 PPAs (b) 62.2 76.6 Noncurrent derivative instruments $ 110.2 $ 112.2 (a) NSP-Minnesota nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2019 and 2018 . At both Dec. 31, 2019 and 2018 , derivative assets and liabilities include $31.5 million of obligations to return cash collateral, respectively. At Dec. 31, 2019 and 2018 , derivative assets and liabilities include the rights to reclaim cash collateral of $7.9 million and $8.7 million , respectively. The counterparty netting excludes settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. (b) During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. Changes in Level 3 commodity derivatives for the years ended Dec. 31, 2019 , 2018 and 2017 : Year Ended Dec. 31 (Millions of Dollars) 2019 2018 2017 Balance at Jan. 1 $ 14.3 $ 22.6 $ 15.3 Purchases 16.7 26.4 40.6 Settlements (27.5 ) (17.2 ) (41.7 ) Net transactions recorded during the period: Gains (losses) recognized in earnings (a) 3.2 (1.5 ) 5.5 Net (losses) gains recognized as regulatory assets and liabilities (1.4 ) (16.0 ) 2.9 Balance at Dec. 31 $ 5.3 $ 14.3 $ 22.6 (a) Amounts relate to commodity derivatives held at the end of the period. NSP-Minnesota recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the years ended 2017 - 2019 . Fair Value of Long-Term Debt As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value: 2019 2018 (Millions of Dollars) Carrying Fair Value Carrying Fair Value Long-term debt, including current portion $ 5,521.3 $ 6,296.5 $ 4,937.2 $ 5,230.9 Fair value of NSP-Minnesota’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. Fair value estimates are based on information available to management as of Dec. 31, 2019 and 2018 , and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2. | |
Cost and Fair Value of Nuclear Decommissioning Fund Investments | Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund: Dec. 31, 2019 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total Nuclear decommissioning fund (a) Cash equivalents $ 33.4 $ 33.4 $ — $ — $ — $ 33.4 Commingled funds 732.8 — — — 934.9 934.9 Debt securities 489.2 — 495.2 12.7 — 507.9 Equity securities 484.6 962.0 1.4 — — 963.4 Total $ 1,740.0 $ 995.4 $ 496.6 $ 12.7 $ 934.9 $ 2,439.6 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $55.6 million of rabbi trust assets and miscellaneous investments. Dec. 31, 2018 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total Nuclear decommissioning fund (a) Cash equivalents $ 24.3 $ 24.3 $ — $ — $ — $ 24.3 Commingled funds 758.1 79.2 — — 819.1 898.3 Debt securities 465.6 — 435.6 — — 435.6 Equity securities 401.4 696.5 — — — 696.5 Total $ 1,649.4 $ 800.0 $ 435.6 $ — $ 819.1 $ 2,054.7 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $52.5 million of rabbi trust assets and miscellaneous investments. | |
Final Contractual Maturity Dates of Debt Securities in the Nuclear Decommissioning Fund by Asset Class | Contractual maturity dates of debt securities in the nuclear decommissioning fund as of Dec. 31, 2019 : Final Contractual Maturity (Millions of Dollars) Due in 1 Year or Less Due in 1 to 5 Years Due in 5 to 10 Years Due after 10 Years Total Debt securities $ (6.8 ) $ 110.5 $ 246.1 $ 158.1 $ 507.9 | |
Rabbi Trust Securities Amortized Cost and Fair Value Measured on Recurrring Basis [Table Text Block] | Cost and fair value of assets held in rabbi trusts: Dec. 31, 2019 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Total Rabbi Trusts (a) Cash equivalents $ 1.2 $ 1.2 $ — $ — $ 1.2 Mutual funds 11.4 13.1 — — 13.1 Total $ 12.6 $ 14.3 $ — $ — $ 14.3 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet. Dec. 31, 2018 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Total Rabbi Trusts (a) Cash equivalents $ 0.4 $ 0.4 $ — $ — $ 0.4 Mutual funds 10.8 10.7 — — 10.7 Total $ 11.2 $ 11.1 $ — $ — $ 11.1 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet. | |
Gross Notional Amounts of Commodity Forwards, Options, and FTRs | Gross notional amounts of commodity forwards, options and FTRs at Dec. 31: (Amounts in Millions) (a) (b) 2019 2018 MWh of electricity 79.1 56.8 MMBtu of natural gas 77.8 42.7 (a) Amounts are not reflective of net positions in the underlying commodities. (b) Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise. | |
Financial Impact of Qualifying Cash Flow Hedges on Accumulated Other Comprehensive Loss | (Millions of Dollars) 2019 2018 2017 Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 $ (20.2 ) $ (20.9 ) $ (18.2 ) After-tax net unrealized gains related to derivatives accounted for as hedges — — 0.1 After-tax net realized losses on derivative transactions reclassified into earnings 0.8 0.7 0.9 Adoption of ASU. 2018-02 (a) — — (3.7 ) Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 $ (19.4 ) $ (20.2 ) $ (20.9 ) (a) In 2017, NSP-Minnesota implemented ASU No. 2018-02 related to TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings. | |
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income | Pre-Tax (Gains) Losses Pre-Tax Gains (Losses) (Millions of Dollars) Accumulated Other Comprehensive Loss Regulatory Year Ended Dec. 31, 2019 Derivatives designated as cash flow hedges Interest rate $ 1.1 (a) $ — $ — Total $ 1.1 $ — $ — Other derivative instruments Commodity trading $ — $ — $ (0.7 ) (c) Electric commodity — 0.8 (d) — Natural gas commodity — 0.9 (e) (2.5 ) (e) Total $ — $ 1.7 $ (3.2 ) Year Ended Dec. 31, 2018 Derivatives designated as cash flow hedges Interest rate $ 1.1 (a) $ — $ — Vehicle fuel and other commodity (0.1 ) (b) — — Total $ 1.0 $ — $ — Other derivative instruments Commodity trading $ — $ — $ 10.9 (c) Electric commodity — 3.3 (d) — Natural gas commodity — (1.9 ) (e) (1.3 ) (e) Total $ — $ 1.4 $ 9.6 Year Ended Dec. 31, 2017 Derivatives designated as cash flow hedges Interest rate $ 1.5 (a) $ — $ — Total $ 1.5 $ — $ — Other derivative instruments Commodity trading $ — $ — $ 9.4 (c) Electric commodity — (13.8 ) (d) — Natural gas commodity — 1.0 (e) (1.2 ) (e) Total $ — $ (12.8 ) $ 8.2 (a) Amounts are recorded to interest charges. (b) Amounts are recorded to O&M expenses. (c) Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate. (d) Amounts are recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate. (e) Amounts are recorded to cost of natural gas sold and transported. These derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms, and reclassified out of income as regulatory assets and liabilities, as appropriate. Impact of derivative activity: Pre-Tax Fair Value (Millions of Dollars) Accumulated Other Comprehensive Loss Regulatory (Assets) and Liabilities Year Ended Dec. 31, 2019 Other derivative instruments Electric commodity $ — $ 1.5 Natural gas commodity — (2.9 ) Total $ — $ (1.4 ) Year Ended Dec. 31, 2018 Other derivative instruments Electric commodity $ — $ (5.5 ) Natural gas commodity — 1.8 Total $ — $ (3.7 ) Year Ended Dec. 31, 2017 Derivatives designated as cash flow hedges Vehicle fuel and other commodity $ 0.1 $ — Total $ 0.1 $ — Other derivative instruments Electric commodity — 9.3 Natural gas commodity — (1.9 ) Total $ — $ 7.4 | [1] |
Derivative Assets and Liabilities Measured at Fair Value on a Recurring Basis by Hierarchy Level | The following table presents for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2019 and 2018 : Dec. 31, 2019 Dec. 31, 2018 Fair Value Fair Value Netting (a) Fair Value Fair Value Netting (a) (Millions of Dollars) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Current derivative assets Other derivative instruments: Commodity trading $ 1.6 $ 39.5 $ 23.6 $ 64.7 $ (42.1 ) $ 22.6 $ 1.1 $ 27.1 $ 2.2 $ 30.4 $ (16.0 ) $ 14.4 Electric commodity — — 8.7 8.7 (0.9 ) 7.8 — — 10.5 10.5 (0.1 ) 10.4 Natural gas commodity — 2.1 — 2.1 — 2.1 — 1.0 — 1.0 — 1.0 Total current derivative assets $ 1.6 $ 41.6 $ 32.3 $ 75.5 $ (43.0 ) 32.5 $ 1.1 $ 28.1 $ 12.7 $ 41.9 $ (16.1 ) 25.8 PPAs (b) — — Current derivative instruments $ 32.5 $ 25.8 Noncurrent derivative assets Other derivative instruments: Commodity trading $ 8.5 $ 29.4 $ 6.0 $ 43.9 $ (34.8 ) $ 9.1 $ — $ 25.3 $ 5.0 $ 30.3 $ (13.4 ) $ 16.9 Total noncurrent derivative assets $ 8.5 $ 29.4 $ 6.0 $ 43.9 $ (34.8 ) 9.1 $ — $ 25.3 $ 5.0 $ 30.3 $ (13.4 ) 16.9 PPAs (b) 0.1 0.1 Noncurrent derivative instruments $ 9.2 $ 17.0 Dec. 31, 2019 Dec. 31, 2018 Fair Value Fair Value Netting (a) Fair Value Fair Value Netting (a) (Millions of Dollars) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Current derivative liabilities Other derivative instruments: Commodity trading $ 2.2 $ 42.1 $ 15.0 $ 59.3 $ (49.8 ) $ 9.5 $ 1.4 $ 23.9 $ 1.7 $ 27.0 $ (24.5 ) $ 2.5 Electric commodity — — 1.0 1.0 (1.0 ) — — — 0.1 0.1 (0.1 ) — Natural gas commodity — 1.7 — 1.7 — 1.7 — — — — — — Total current derivative liabilities $ 2.2 $ 43.8 $ 16.0 $ 62.0 $ (50.8 ) 11.2 $ 1.4 $ 23.9 $ 1.8 $ 27.1 $ (24.6 ) 2.5 PPAs (b) 13.8 14.0 Current derivative instruments $ 25.0 $ 16.5 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ 2.0 $ 32.3 $ 17.0 $ 51.3 $ (3.3 ) $ 48.0 $ 0.1 $ 16.0 $ 1.6 $ 17.7 $ 17.9 $ 35.6 Total noncurrent derivative liabilities $ 2.0 $ 32.3 $ 17.0 $ 51.3 $ (3.3 ) 48.0 $ 0.1 $ 16.0 $ 1.6 $ 17.7 $ 17.9 35.6 PPAs (b) 62.2 76.6 Noncurrent derivative instruments $ 110.2 $ 112.2 (a) NSP-Minnesota nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2019 and 2018 . At both Dec. 31, 2019 and 2018 , derivative assets and liabilities include $31.5 million of obligations to return cash collateral, respectively. At Dec. 31, 2019 and 2018 , derivative assets and liabilities include the rights to reclaim cash collateral of $7.9 million and $8.7 million , respectively. The counterparty netting excludes settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. (b) During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. | |
Changes in Level 3 Commodity Derivatives | Changes in Level 3 commodity derivatives for the years ended Dec. 31, 2019 , 2018 and 2017 : Year Ended Dec. 31 (Millions of Dollars) 2019 2018 2017 Balance at Jan. 1 $ 14.3 $ 22.6 $ 15.3 Purchases 16.7 26.4 40.6 Settlements (27.5 ) (17.2 ) (41.7 ) Net transactions recorded during the period: Gains (losses) recognized in earnings (a) 3.2 (1.5 ) 5.5 Net (losses) gains recognized as regulatory assets and liabilities (1.4 ) (16.0 ) 2.9 Balance at Dec. 31 $ 5.3 $ 14.3 $ 22.6 (a) Amounts relate to commodity derivatives held at the end of the period. | |
Carrying Amount and Fair Value of Long-term Debt | 2019 2018 (Millions of Dollars) Carrying Fair Value Carrying Fair Value Long-term debt, including current portion $ 5,521.3 $ 6,296.5 $ 4,937.2 $ 5,230.9 | |
[1] | Amounts are recorded to interest charges. |
Benefit Plans and Other Postr_2
Benefit Plans and Other Postretirement Benefits (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Benefit Plans and Other Postretirement Benefits [Abstract] | |
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost | Pension Benefits Postretirement Benefits (Millions of Dollars) 2019 2018 2019 2018 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss $ 440.0 $ 502.0 $ 36.8 $ 34.3 Prior service credit (0.2 ) (1.2 ) (9.4 ) (12.4 ) Total $ 439.8 $ 500.8 $ 27.4 $ 21.9 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates: Current regulatory assets $ 29.3 $ 35.5 $ — $ — Noncurrent regulatory assets 410.5 465.3 25.6 20.5 Deferred income taxes — — 0.5 0.4 Net-of-tax accumulated other comprehensive income — — 1.3 1.0 Total $ 439.8 $ 500.8 $ 27.4 $ 21.9 Measurement date Dec. 31, 2019 Dec. 31, 2018 Dec. 31, 2019 Dec. 31, 2018 |
Projected Benefit Payments for the Pension and Postretirement Benefit Plans | Projected Benefit Payments NSP-Minnesota’s projected benefit payments: (Millions of Dollars) Projected Pension Benefit Payments Gross Projected Postretirement Health Care Benefit Payments Expected Medicare Part D Subsidies Net Projected Postretirement Health Care Benefit Payments 2020 $ 89.9 $ 6.9 $ — $ 6.9 2021 82.4 6.6 — 6.6 2022 80.8 6.2 — 6.2 2023 78.5 5.9 — 5.9 2024 74.1 5.6 — 5.6 2025-2029 326.7 23.6 — 23.6 |
Pension Plan | |
Benefit Plans and Other Postretirement Benefits [Abstract] | |
Target Asset Allocations and Plan Assets Measured at Fair Value | or each of the fair value hierarchy levels, NSP-Minnesota’s pension plan assets measured at fair value: Dec. 31, 2019 (a) Dec. 31, 2018 (a) (Millions of Dollars) Level 1 Level 2 Level 3 Measured at NAV Total Level 1 Level 2 Level 3 Measured at NAV Total Cash equivalents $ 40.9 $ — $ — $ — $ 40.9 $ 31.8 $ — $ — $ — $ 31.8 Commingled funds 360.3 — — 270.3 630.6 241.0 — — 271.2 512.2 Debt securities — 155.5 1.1 — 156.6 — 143.7 — — 143.7 Equity securities 22.6 — — — 22.6 29.3 — — — 29.3 Other (31.5 ) 1.2 — (5.2 ) (35.5 ) 0.5 1.3 — (8.2 ) (6.4 ) Total $ 392.3 $ 156.7 $ 1.1 $ 265.1 $ 815.2 $ 302.6 $ 145.0 $ — $ 263.0 $ 710.6 (a) See Note 8 for further information on fair value measurement inputs and methods. For each of the fair value hierarchy levels, NSP-Minnesota’s postretirement benefit plan assets that were measured at fair value: Dec. 31, 2019 (a) Dec. 31, 2018 (a) (Millions of Dollars) Level 1 Level 2 Level 3 Measured at NAV Total Level 1 Level 2 Level 3 Measured at NAV Total Cash equivalents $ 0.1 $ — $ — $ — $ 0.1 $ 0.1 $ — $ — $ — $ 0.1 Insurance contracts — 0.3 — — 0.3 — 0.3 — — 0.3 Commingled funds 0.4 — — 0.5 0.9 0.8 — — 0.2 1.0 Debt securities — 1.3 — — 1.3 — 1.0 — — 1.0 Equity securities — — — — — — — — — — Total $ 0.5 $ 1.6 $ — $ 0.5 $ 2.6 $ 0.9 $ 1.3 $ — $ 0.2 $ 2.4 |
Changes in Projected Benefit Obligations, Fair Value of Plan Assets, and Funded Status of Plan [Table Text Block] | Pension Benefits Postretirement Benefits (Millions of Dollars) 2019 2018 2019 2018 Change in Benefit Obligation: Obligation at Jan. 1 $ 907.0 $ 1,035.1 $ 76.0 $ 88.8 Service cost 25.4 28.0 0.1 0.2 Interest cost 37.1 35.2 3.2 3.1 Plan amendments 1.0 — — — Actuarial loss (gain) 61.7 (50.8 ) 3.8 (9.0 ) Plan participants’ contributions — — 0.3 0.4 Benefit payments (a) (90.0 ) (140.5 ) (7.9 ) (7.5 ) Obligation at Dec. 31 $ 942.2 $ 907.0 $ 75.5 $ 76.0 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 710.6 $ 824.5 $ 2.4 $ 6.5 Actual return on plan assets 147.8 (36.5 ) — — Employer contributions 46.8 63.1 7.7 3.0 Plan participants’ contributions — — 0.3 0.4 Benefit payments (90.0 ) (140.5 ) (7.8 ) (7.5 ) Fair value of plan assets at Dec. 31 $ 815.2 $ 710.6 $ 2.6 $ 2.4 Funded status of plans at Dec. 31 $ (127.0 ) $ (196.4 ) $ (72.9 ) $ (73.6 ) Amounts recognized in the Consolidated Balance Sheet at Dec. 31: Current assets (liabilities) $ — $ — $ (4.3 ) $ (4.8 ) Noncurrent assets (liabilities) (127.0 ) (196.4 ) (68.6 ) (68.8 ) Net amounts recognized $ (127.0 ) $ (196.4 ) $ (72.9 ) $ (73.6 ) (a) Includes approximately $105 million of lump-sum benefit payments used in the determination of a settlement charge in 2018. Significant Assumptions Used to Measure Benefit Obligations: Discount rate for year-end valuation 3.49 % 4.31 % 3.47 % 4.32 % Expected average long-term increase in compensation level 3.75 % 3.75 % N/A N/A Mortality table Pri-2012 RP-2014 Pri-2012 RP-2014 Health care costs trend rate — initial: Pre-65 N/A N/A 6.00 % 6.50 % Health care costs trend rate — initial: Post-65 N/A N/A 5.10 % 5.30 % Ultimate trend assumption — initial: Pre-65 N/A N/A 4.50 % 4.50 % Ultimate trend assumption — initial: Post-65 N/A N/A 4.50 % 4.50 % Years until ultimate trend is reached N/A N/A 3 4 |
Components of Net Periodic Benefit Costs | Pension Benefits Postretirement Benefits (Millions of Dollars) 2019 2018 2017 2019 2018 2017 Service cost $ 25.4 $ 28.0 $ 27.8 $ 0.1 $ 0.2 $ 0.1 Interest cost 37.1 35.2 40.7 3.2 3.1 3.4 Expected return on plan assets (54.3 ) (58.2 ) (60.1 ) (0.1 ) (0.4 ) (0.2 ) Amortization of prior service cost (0.1 ) (0.1 ) 1.1 (3.0 ) (3.0 ) (3.0 ) Amortization of net loss 30.2 38.5 39.6 1.5 2.4 2.0 Settlement charge (a) — 48.8 48.2 — — — Net periodic pension cost 38.3 92.2 97.3 1.7 2.3 2.3 Costs not recognized due to effects of regulation (5.2 ) (66.0 ) (72.2 ) — — — Net benefit cost recognized for financial reporting $ 33.1 $ 26.2 $ 25.1 $ 1.7 $ 2.3 $ 2.3 Significant Assumptions Used to Measure Costs: Discount rate 4.31 % 3.63 % 4.13 % 4.32 % 3.62 % 4.13 % Expected average long-term increase in compensation level 3.75 3.75 3.75 — — — Expected average long-term rate of return on assets 7.10 7.10 7.10 4.50 5.30 5.80 (a) A settlement charge is required when the amount of lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2018 and 2017, as a result of lump-sum distributions during the 2018 and 2017 plan years, NSP-Minnesota recorded a total pension settlement charge of $48.8 million in 2018 and $48.2 million |
Postretirement Benefits Plan | |
Benefit Plans and Other Postretirement Benefits [Abstract] | |
Target Asset Allocations and Plan Assets Measured at Fair Value | Target asset allocations: Pension Benefits Postretirement Benefits 2019 2018 2019 2018 Domestic and international equity securities 37 % 37 % 15 % 18 % Long-duration fixed income and interest rate swap securities 30 28 — — Short-to-intermediate fixed income securities 14 18 72 70 Alternative investments 17 15 9 8 Cash 2 2 4 4 Total 100 % 100 % 100 % 100 % |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Commitments and Contingencies Disclosure [Abstract] | |
Assets and Liabilities, Lessee [Table Text Block] | Operating lease ROU assets: (Millions of Dollars) Dec. 31, 2019 PPAs $ 556.3 Other 72.2 Gross operating lease ROU assets 628.5 Accumulated amortization (64.7 ) Net operating lease ROU assets $ 563.8 |
Lease, Cost [Table Text Block] | Components of lease expense: (Millions of Dollars) 2019 2018 2017 Operating leases PPA capacity payments $ 75.9 $ 62.5 $ 62.7 Other operating leases (a) 9.1 13.7 14.2 Total operating lease expense (b) $ 85.0 $ 76.2 $ 76.9 (a) Includes short-term lease expense of $1.4 million , $2.0 million and $2.7 million for 2019, 2018 and 2017, respectively. (b) PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income. Expense for other operating leases is included in O&M expense and electric fuel and purchased power. |
Lessee, Operating Lease, Liability, Maturity [Table Text Block] | Commitments under operating leases as of Dec. 31, 2019: (Millions of Dollars) PPA (a) (b) Operating Leases Other Operating Leases Total Leases 2020 $ 93.5 $ 7.9 $ 101.4 2021 94.9 8.0 102.9 2022 96.4 11.9 108.3 2023 97.9 7.0 104.9 2024 99.5 6.8 106.3 Thereafter 119.8 44.9 164.7 Total minimum obligation 602.0 86.5 688.5 Interest component of obligation (66.2 ) (16.7 ) (82.9 ) Present value of minimum obligation $ 535.8 $ 69.8 605.6 Less current portion (79.9 ) Noncurrent operating lease liabilities $ 525.7 Weighted-average remaining lease term in years 6.7 (a) Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs. (b) PPA operating leases contractually expire at various dates through 2026. |
Estimated Minimum Purchases Under Fuel Contracts | Estimated minimum purchases for these contracts as of Dec. 31, 2019 : (Millions of Dollars) Coal Nuclear fuel Natural gas Natural gas 2020 $ 171.3 $ 53.8 $ 36.8 $ 133.0 2021 85.2 102.5 1.4 129.8 2022 51.9 85.3 0.8 124.3 2023 35.1 103.0 — 107.8 2024 0.9 74.5 — 101.1 Thereafter 2.6 275.1 — 273.6 Total (a) $ 347.0 $ 694.2 $ 39.0 $ 869.6 (a) Includes amounts allocated to NSP-Wisconsin through intercompany charges. |
Estimated Future Payments for Capacity and Energy Pursuant to Purchased Power Agreements | At Dec. 31, 2019 , the estimated future payments for capacity and energy that NSP-Minnesota is obligated to purchase pursuant to these executory contracts, subject to availability, were as follows: (Millions of Dollars) Capacity Energy (a) 2020 $ 54.5 $ 109.4 2021 62.2 157.3 2022 61.3 172.9 2023 62.8 176.9 2024 64.5 181.8 Thereafter 45.4 146.3 Total (b) $ 350.7 $ 944.6 (a) Excludes contingent energy payments for renewable energy PPAs. (b) Includes amounts allocated to NSP-Wisconsin through intercompany charges. |
Future Commitments Under Operating Leases | Commitments under operating leases as of Dec. 31, 2018: (Millions of Dollars) PPA (a) (b) Operating Other Operating Leases Total 2019 $ 65.0 $ 13.5 $ 78.5 2020 66.1 8.4 74.5 2021 67.1 8.4 75.5 2022 68.2 8.1 76.3 2023 69.3 7.3 76.6 Thereafter 143.5 36.0 179.5 (a) Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs. (b) PPA operating leases contractually expire at various dates through 2026. |
Asset Retirement Obligations | NSP-Minnesota’s AROs were as follows: 2019 (Millions of Dollars) Jan. 1, 2019 Amounts Incurred (a) Amounts Settled (b) Accretion Cash Flow Revisions (c) Dec. 31, 2019 Electric Nuclear $ 1,968.3 $ — $ — $ 99.5 $ — $ 2,067.8 Wind 104.9 10.3 — 4.8 (6.9 ) 113.1 Steam and other production 49.2 — (3.2 ) 1.8 (1.0 ) 46.8 Distribution 14.5 — — 0.6 — 15.1 Miscellaneous 1.8 — — — (1.6 ) 0.2 Natural gas Transmission and distribution 38.2 — — 1.6 (3.6 ) 36.2 Miscellaneous 0.2 — — 0.1 — 0.3 Common Miscellaneous 0.8 — — — — 0.8 Total liability $ 2,177.9 $ 10.3 $ (3.2 ) $ 108.4 $ (13.1 ) $ 2,280.3 (a) Amounts incurred relate to the wind farms placed in service in 2019 (Lake Benton and Foxtail). (b) Amounts settled related to closure of certain ash containment facilities. (c) In 2019, AROs were revised for changes in timing and estimates of cash flows. Changes in wind AROs were driven by new dismantling studies. Changes in gas transmission and distribution AROs were primarily related to increased gas line mileage and number of services, which were more than offset by decreased inflation rates. Changes in steam and other production AROs primarily related to the cost estimates to remediate ponds at production facilities. 2018 (Millions of Dollars) Jan. 1, 2018 Amounts Settled (a) Accretion Cash Flow Revisions (b) Dec. 31, 2018 (c) Electric Nuclear $ 1,873.6 $ — $ 94.7 $ — $ 1,968.3 Wind 94.1 — 4.3 6.5 104.9 Steam and other production 64.0 (6.6 ) 2.1 (10.3 ) 49.2 Distribution 5.8 — 0.2 8.5 14.5 Miscellaneous 1.9 — — (0.1 ) 1.8 Natural gas Transmission and distribution 43.6 — 1.8 (7.2 ) 38.2 Miscellaneous 0.2 — — — 0.2 Common Miscellaneous 0.7 — 0.1 — 0.8 Total liability $ 2,083.9 $ (6.6 ) $ 103.2 $ (2.6 ) $ 2,177.9 (a) Amounts settled related to asbestos abatement projects and closure of certain ash containment facilities. (b) In 2018, AROs were revised for changes in timing and estimates of cash flows. Changes in gas transmission and distribution AROs were mainly related to increased gas line mileage and number of services, which were more than offset by increased discount rates. Changes in electric distribution AROs primarily related to increased labor costs. (c) There were no ARO amounts incurred in 2018. |
Funded Status of Nuclear Decommissioning Obligation | The following amounts were prepared on a regulatory basis and not directly recorded in the financial statements as an ARO. Regulatory Basis (Millions of Dollars) 2019 2018 Estimated decommissioning cost obligation from most recently approved study (in 2014 dollars) $ 3,012.3 $ 3,012.3 Effect of escalating costs 688.2 538.9 Estimated decommissioning cost obligation (in current dollars) 3,700.5 3,551.2 Effect of escalating costs to payment date 7,505.0 7,654.3 Estimated future decommissioning costs (undiscounted) 11,205.5 11,205.5 Effect of discounting obligation (using average risk-free interest rate of 2.39% and 3.33% for 2019 and 2018, respectively) (5,562.2 ) (6,911.5 ) Discounted decommissioning cost obligation $ 5,643.3 $ 4,294.0 Assets held in external decommissioning trust $ 2,439.6 $ 2,054.7 Underfunding of external decommissioning fund compared to the discounted decommissioning obligation 3,203.7 2,239.3 |
Reconciliation of Decommissioning Cost Obligation - Regulatory to GAAP | Reconciliation of the discounted decommissioning cost obligation - regulated basis to the ARO recorded in accordance with GAAP: (Millions of Dollars) 2019 2018 Discounted decommissioning cost obligation - regulated basis $ 5,643.3 $ 4,294.0 Differences in discount rate and market risk premium (2,295.2 ) (1,446.4 ) O&M costs not included for GAAP (1,280.3 ) (879.3 ) Nuclear production decommissioning ARO - GAAP $ 2,067.8 $ 1,968.3 |
Nuclear Decommissioning Expenses Recognized as Result of Regulation | Decommissioning expenses recognized as a result of regulation: (Millions of Dollars) 2019 2018 2017 Annual decommissioning recorded as depreciation expense: (a) (b) $ 20.4 $ 20.4 $ 20.4 (a) Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs. (b) Decommissioning expenses in 2019, 2018 and 2017 include Minnesota’s retail jurisdiction annual funding requirement of approximately $14.0 million. |
Other Comprehensive Income (Tab
Other Comprehensive Income (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Stockholders' Equity Note [Abstract] | |
Changes in Accumulated Other Comprehensive Income (Loss), Net of Tax | 2018 (Millions of Dollars) Gains and Losses on Cash Flow Hedges Unrealized Gains and Losses on Marketable Securities Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive (loss) income at Jan. 1 $ (20.9 ) $ 0.1 $ (3.7 ) $ (24.5 ) Other comprehensive (loss) income before reclassifications (net of taxes of $0, $0 and $0.3, respectively) — (0.1 ) 0.6 0.5 Losses reclassified from net accumulated other comprehensive loss: Interest rate derivatives (net of taxes of $0.3, $0 and $0, respectively) 0.7 (a) — — 0.7 Amortization of net actuarial loss (net of taxes of $0, $0 and $0.1, respectively) — — 0.2 (b) 0.2 Net current period other comprehensive income (loss) 0.7 (0.1 ) 0.8 1.4 Accumulated other comprehensive loss at Dec. 31 $ (20.2 ) $ — $ (2.9 ) $ (23.1 ) 2019 (Millions of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive loss at Jan. 1 $ (20.2 ) $ (2.9 ) $ (23.1 ) Other comprehensive loss before reclassifications (net of taxes of $0 and $(0.1) respectively) — (0.4 ) (0.4 ) Losses reclassified from net accumulated other comprehensive loss: Interest rate derivatives (net of taxes of $0.3 and $0, respectively) (a) 0.8 (a) — 0.8 Amortization of net actuarial loss (net of taxes of $0 and $0.1, respectively) — 0.2 (b) 0.2 Net current period other comprehensive income (loss) 0.8 (0.2 ) 0.6 Accumulated other comprehensive loss at Dec. 31 $ (19.4 ) $ (3.1 ) $ (22.5 ) |
Segments and Related Informat_2
Segments and Related Information (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Segment Reporting [Abstract] | |
Results from Operations by Reportable Segment | (Millions of Dollars) 2019 2018 2017 Regulated Electric Operating revenues (a) $ 4,506.6 $ 4,508.0 $ 4,541.7 Intersegment revenues 0.6 0.8 0.6 Total operating revenue $ 4,507.2 $ 4,508.8 $ 4,542.3 Depreciation and amortization 742.1 697.8 661.3 Interest charges and financing costs 205.3 199.5 199.8 Income tax expense 36.1 16.4 179.9 Net income 491.0 450.4 462.5 Regulated Natural Gas Operating revenues (a) $ 571.3 $ 583.1 $ 531.9 Intersegment revenues 0.8 0.5 0.5 Total operating revenue $ 572.1 $ 583.6 $ 532.4 Depreciation and amortization 48.8 43.3 38.7 Interest charges and financing costs 15.6 14.8 13.5 Income tax expense 12.4 10.2 10.0 Net income 40.0 34.2 28.4 Other Operating revenues (a) $ 33.9 $ 30.8 $ 28.4 Depreciation and amortization 0.4 0.5 0.6 Interest charges and financing costs — — — Income tax expense (1.1 ) 0.6 9.8 Net income (loss) 11.6 7.7 (0.8 ) Consolidated Total Total operating revenue (a) $ 5,113.2 $ 5,123.2 $ 5,103.1 Reconciling eliminations (1.4 ) (1.3 ) (1.1 ) Consolidated total revenue $ 5,111.8 $ 5,121.9 $ 5,102.0 Depreciation and amortization 791.3 741.6 700.6 Interest charges and financing costs 220.9 214.3 213.3 Income tax expense 47.4 27.2 199.7 Net income 542.6 492.3 490.1 (a) Operating revenues include $457.4 million , $473.7 million , and $490.2 million of intercompany revenue for the years ended Dec. 31, 2019 , 2018 and 2017 , respectively. See Note 13 for further information. |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Significant affiliate transactions among the companies and related parties including billings under the Interchange Agreement for the years ended Dec. 31: (Millions of Dollars) 2019 2018 2017 Operating revenues: Electric $ 457.4 $ 473.7 $ 490.2 Gas 0.5 — — Operating expenses: Purchased power 60.5 61.1 66.8 Transmission expense 116.2 96.8 110.5 Other operating expenses — paid to Xcel Energy Services Inc. 533.2 534.8 539.4 Interest expense 0.7 0.3 — Accounts receivable and payable with affiliates at Dec. 31 were: 2019 2018 (Millions of Dollars) Accounts Receivable Accounts Payable Accounts Receivable Accounts Payable NSP-Wisconsin $ 7.9 $ — $ 11.0 $ — PSCo — 18.8 — 17.9 SPS — 4.2 — 4.7 Other subsidiaries of Xcel Energy Inc. 35.9 53.0 — 87.1 $ 43.8 $ 76.0 $ 11.0 $ 109.7 |
Summarized Quarterly Financia_2
Summarized Quarterly Financial Data (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Quarterly Financial Information Disclosure [Abstract] | |
Summarized Quarterly Financial Data (Unaudited) | Quarter Ended (Millions of Dollars) March 31, 2019 June 30, 2019 Sept. 30, 2019 Dec. 31, 2019 Operating revenues $ 1,350.5 $ 1,185.0 $ 1,344.6 $ 1,231.7 Operating income 167.3 147.3 291.0 181.3 Net income 113.2 95.9 208.6 124.9 Quarter Ended (Millions of Dollars) March 31, 2018 June 30, 2018 Sept. 30, 2018 Dec. 31, 2018 Operating revenues $ 1,310.8 $ 1,187.7 $ 1,351.8 $ 1,271.6 Operating income (a) 171.4 150.1 259.5 135.5 Net income 111.7 92.4 201.2 87.0 (a) In 2018, NSP-Minnesota implemented ASU No. 2017-07 related to net periodic benefit cost, which resulted in retrospective reclassification of pension costs from O&M expense to other income. |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Property, Plant and Equipment [Abstract] | |||
Depreciation expense expressed as a percentage of average depreciable property | 3.70% | 3.60% | 3.60% |
Nuclear Decommissioning [Abstract] | |||
Minimum amount of time between nuclear decommissioning studies (in years) | 3 years | ||
Cash and Cash Equivalents [Abstract] | |||
Maximum number of months of remaining maturity at time of purchase to consider investments in certain instruments as cash equivalents | 3 months | ||
Accounts and Financing Receivable, after Allowance for Credit Loss, Current and Noncurrent [Abstract] | |||
Allowance for bad debts | $ 23 | $ 23.5 | |
Alternative Revenue Programs [Abstract] | |||
Maximum number of months following end of annual period in which revenues are earned to be included in incentive programs | 24 months | ||
Public Utilities, Inventory [Line Items] | |||
Inventories | $ 304.8 | 299.4 | |
Supplies | |||
Public Utilities, Inventory [Line Items] | |||
Inventories | 175.6 | 176.3 | |
Public Utilities, Inventory, Fuel | |||
Public Utilities, Inventory [Line Items] | |||
Inventories | 103.2 | 88.5 | |
Public Utilities, Inventory, Natural Gas | |||
Public Utilities, Inventory [Line Items] | |||
Inventories | $ 26 | $ 34.6 |
Accounting Pronouncements - Rec
Accounting Pronouncements - Recently Adopted (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Jan. 01, 2019 | Dec. 31, 2018 |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||
Operating Lease, Right-of-Use Asset | $ 563.8 | $ 0 | |
Present value of minimum obligation | $ 605.6 | ||
Accounting Standards Update 2016-02 | |||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||
Operating Lease, Right-of-Use Asset | $ 500 | ||
Present value of minimum obligation | $ 500 |
Property Plant and Equipment (D
Property Plant and Equipment (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment | $ 21,815.4 | $ 20,643 |
Accumulated depreciation and amortization | 7,945.3 | 7,454.8 |
Property, Plant and Equipment, Net | 14,244 | 13,541.7 |
Electric plant | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment | 18,519.5 | 17,749.3 |
Natural gas plant | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment | 1,562.9 | 1,475.5 |
Common and other property | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment | 886.7 | 803.1 |
CWIP | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment | 846.3 | 615.1 |
Nuclear fuel | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment | 2,909.8 | 2,770.4 |
Accumulated depreciation and amortization | $ 2,535.9 | $ 2,416.9 |
Property Plant and Equipment _2
Property Plant and Equipment Property Plant and Equipment Joint Ownership (Details) $ in Millions | Dec. 31, 2019USD ($) |
Jointly Owned Utility Plant Interests [Line Items] | |
Plant in Service | $ 1,735.7 |
Accumulated Depreciation | 626.7 |
CWIP | 7.9 |
Electric Generation | Sherco Unit 3 | |
Jointly Owned Utility Plant Interests [Line Items] | |
Plant in Service | 603 |
Accumulated Depreciation | 426.3 |
CWIP | $ 3.8 |
Percent Owned | 59.00% |
Electric Generation | Sherco Common Facilities Units 1, 2 and 3 | |
Jointly Owned Utility Plant Interests [Line Items] | |
Plant in Service | $ 144.7 |
Accumulated Depreciation | 102.7 |
CWIP | $ 1.9 |
Percent Owned | 80.00% |
Electric Generation | Sherco Substation | |
Jointly Owned Utility Plant Interests [Line Items] | |
Plant in Service | $ 4.8 |
Accumulated Depreciation | 3.5 |
CWIP | $ 0 |
Percent Owned | 59.00% |
Electric Transmission | CapX2020 | |
Jointly Owned Utility Plant Interests [Line Items] | |
Plant in Service | $ 972.5 |
Accumulated Depreciation | 91.6 |
CWIP | $ 2.2 |
Percent Owned | 51.00% |
Electric Transmission | Grand Meadow | |
Jointly Owned Utility Plant Interests [Line Items] | |
Plant in Service | $ 10.7 |
Accumulated Depreciation | 2.6 |
CWIP | $ 0 |
Percent Owned | 50.00% |
Regulatory Assets and Liabili_3
Regulatory Assets and Liabilities, Regulatory Assets (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | |
Regulatory Assets [Line Items] | |||
Regulatory Asset, Current | $ 320.1 | $ 280.3 | |
Regulatory Asset, Noncurrent | 1,125 | 1,454.1 | |
Pension and Retiree Medical Obligations | |||
Regulatory Assets [Line Items] | |||
Regulatory Asset, Current | 27.5 | 28.1 | |
Regulatory Asset, Noncurrent | 377.7 | 424.3 | |
Excess deferred taxes - TCJA | |||
Regulatory Assets [Line Items] | |||
Regulatory Asset, Current | 10.4 | 0 | |
Regulatory Asset, Noncurrent | 132.2 | 153.3 | |
Net AROs | |||
Regulatory Assets [Line Items] | |||
Regulatory Asset, Current | [1] | 0 | 0 |
Regulatory Asset, Noncurrent | [1] | 117.9 | 323.4 |
Recoverable Deferred Taxes on AFUDC Recorded in Plant | |||
Regulatory Assets [Line Items] | |||
Regulatory Asset, Current | 0 | 0 | |
Regulatory Asset, Noncurrent | 114.8 | 117.6 | |
Benson purchase power agreement termination and asset purchase | |||
Regulatory Assets [Line Items] | |||
Regulatory Asset, Current | 9.4 | 9.8 | |
Regulatory Asset, Noncurrent | 72.7 | 85.8 | |
Contract Valuation Adjustments | |||
Regulatory Assets [Line Items] | |||
Regulatory Asset, Current | [2] | 15.5 | 14.1 |
Regulatory Asset, Noncurrent | [2] | 62.1 | 76 |
Laurentian biomass PPA termination | |||
Regulatory Assets [Line Items] | |||
Regulatory Asset, Current | 19.2 | 18.1 | |
Regulatory Asset, Noncurrent | 53.9 | 73.3 | |
PI extended power update | |||
Regulatory Assets [Line Items] | |||
Regulatory Asset, Current | 3.1 | 3.1 | |
Regulatory Asset, Noncurrent | 52.6 | 55.8 | |
Purchased Power Agreements | |||
Regulatory Assets [Line Items] | |||
Regulatory Asset, Current | 2.7 | 2.8 | |
Regulatory Asset, Noncurrent | 36.5 | 36.6 | |
Nuclear Refueling Outage Costs | |||
Regulatory Assets [Line Items] | |||
Regulatory Asset, Current | 43.3 | 36.3 | |
Regulatory Asset, Noncurrent | 16.9 | 13.5 | |
Sales True-Up and Revenue Decoupling | |||
Regulatory Assets [Line Items] | |||
Regulatory Asset, Current | 53.8 | 38.3 | |
Regulatory Asset, Noncurrent | 16.3 | 6.7 | |
Loss on Reacquired Debt | |||
Regulatory Assets [Line Items] | |||
Regulatory Asset, Current | 1.7 | 2.1 | |
Regulatory Asset, Noncurrent | 13.8 | 15.5 | |
Conservation Programs | |||
Regulatory Assets [Line Items] | |||
Regulatory Asset, Current | [3] | 18.1 | 34.5 |
Regulatory Asset, Noncurrent | [3] | 13.5 | 21.1 |
Environmental Remediation Costs | |||
Regulatory Assets [Line Items] | |||
Regulatory Asset, Current | 1.3 | 1.3 | |
Regulatory Asset, Noncurrent | 11.8 | 14.3 | |
Deferred Purchased Natural Gas and Electric Energy Costs | |||
Regulatory Assets [Line Items] | |||
Regulatory Asset, Current | 6.2 | 5.6 | |
Regulatory Asset, Noncurrent | 5.7 | 12.6 | |
State Commission Adjustments | |||
Regulatory Assets [Line Items] | |||
Regulatory Asset, Current | 0 | 0 | |
Regulatory Asset, Noncurrent | 3.4 | 3.4 | |
Renewable Resources and Environmental Initiatives | |||
Regulatory Assets [Line Items] | |||
Regulatory Asset, Current | 72.2 | 39.2 | |
Regulatory Asset, Noncurrent | 0.6 | 0.4 | |
Gas Pipeline Inspection and Remediation Costs | |||
Regulatory Assets [Line Items] | |||
Regulatory Asset, Current | 26.2 | 27.4 | |
Regulatory Asset, Noncurrent | 0 | 0 | |
Other | |||
Regulatory Assets [Line Items] | |||
Regulatory Asset, Current | 9.5 | 19.6 | |
Regulatory Asset, Noncurrent | $ 22.6 | $ 20.5 | |
[1] | Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments. | ||
[2] | Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. | ||
[3] | Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. |
Regulatory Assets and Liabili_4
Regulatory Assets and Liabilities, Regulatory Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | |
Regulatory Liabilities [Line Items] | |||
Regulatory Liability, Current | [1] | $ 141 | $ 262.4 |
Regulatory Liability, Noncurrent | [1] | 1,937.1 | 1,984.7 |
Regulatory assets not currently earning a return | 235.1 | 190.2 | |
Deferred income tax adjustments and TCJA refunds | |||
Regulatory Liabilities [Line Items] | |||
Regulatory Liability, Current | [2] | 12.8 | 153.7 |
Regulatory Liability, Noncurrent | [2] | 1,388.9 | 1,465.1 |
Plant Removal Costs | |||
Regulatory Liabilities [Line Items] | |||
Regulatory Liability, Current | 0 | 0 | |
Regulatory Liability, Noncurrent | 520.3 | 484.6 | |
Investment Tax Credit Deferrals | |||
Regulatory Liabilities [Line Items] | |||
Regulatory Liability, Current | [3] | 0 | 0 |
Regulatory Liability, Noncurrent | [3] | 8.3 | 8.9 |
DOE Settlement | |||
Regulatory Liabilities [Line Items] | |||
Regulatory Liability, Current | 27 | 13 | |
Regulatory Liability, Noncurrent | 0 | 0 | |
Deferred Electric Energy Costs | |||
Regulatory Liabilities [Line Items] | |||
Regulatory Liability, Current | 24.2 | 22.8 | |
Regulatory Liability, Noncurrent | 0 | 0 | |
Contract Valuation Adjustments | |||
Regulatory Liabilities [Line Items] | |||
Regulatory Liability, Current | [4] | 7.8 | 10.4 |
Regulatory Liability, Noncurrent | [4] | 0 | 0 |
Renewable Resources and Environmental Initiatives | |||
Regulatory Liabilities [Line Items] | |||
Regulatory Liability, Current | 0 | 8.8 | |
Regulatory Liability, Noncurrent | 0 | 0 | |
Other Regulatory Liabilities | |||
Regulatory Liabilities [Line Items] | |||
Regulatory Liability, Current | 69.2 | 53.7 | |
Regulatory Liability, Noncurrent | 19.6 | 26.1 | |
Other Current Liabilities | |||
Regulatory Liabilities [Line Items] | |||
Entity's Recorded Provision for Revenue Subject To Refund | $ 23.8 | $ 12.5 | |
[1] | Revenue subject for refund of $23.8 million and $12.5 million for 2019 and 2018, respectively, is included in other current liabilities. | ||
[2] | Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA. | ||
[3] | Includes impact of lower federal tax rate due to the TCJA. | ||
[4] | Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. |
Regulatory Assets and Liabili_5
Regulatory Assets and Liabilities Regulatory assets and liabilities Phantom (Details) | 12 Months Ended |
Dec. 31, 2019 | |
Benson purchase power agreement termination and asset purchase | |
Regulatory Assets [Line Items] | |
Regulatory Asset, Amortization Period | 10 years |
Laurentian biomass PPA termination | |
Regulatory Assets [Line Items] | |
Regulatory Asset, Amortization Period | 5 years |
PI extended power update | |
Regulatory Assets [Line Items] | |
Regulatory Asset, Amortization Period | 16 years |
Conservation Programs | Minimum [Member] | |
Regulatory Assets [Line Items] | |
Regulatory Asset, Amortization Period | 1 year |
Conservation Programs | Maximum | |
Regulatory Assets [Line Items] | |
Regulatory Asset, Amortization Period | 2 years |
Nuclear Refueling Outage Costs | Minimum [Member] | |
Regulatory Assets [Line Items] | |
Regulatory Asset, Amortization Period | 1 year |
Nuclear Refueling Outage Costs | Maximum | |
Regulatory Assets [Line Items] | |
Regulatory Asset, Amortization Period | 2 years |
Deferred Purchased Natural Gas and Electric Energy Costs | Minimum [Member] | |
Regulatory Assets [Line Items] | |
Regulatory Asset, Amortization Period | 1 year |
Deferred Purchased Natural Gas and Electric Energy Costs | Maximum | |
Regulatory Assets [Line Items] | |
Regulatory Asset, Amortization Period | 3 years |
Sales True-Up and Revenue Decoupling | Minimum [Member] | |
Regulatory Assets [Line Items] | |
Regulatory Asset, Amortization Period | 1 year |
Sales True-Up and Revenue Decoupling | Maximum | |
Regulatory Assets [Line Items] | |
Regulatory Asset, Amortization Period | 2 years |
Renewable Resources and Environmental Initiatives | Minimum [Member] | |
Regulatory Assets [Line Items] | |
Regulatory Asset, Amortization Period | 1 year |
Renewable Resources and Environmental Initiatives | Maximum | |
Regulatory Assets [Line Items] | |
Regulatory Asset, Amortization Period | 2 years |
Short-Term Debt (Details)
Short-Term Debt (Details) - USD ($) | 3 Months Ended | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Short-term Debt [Line Items] | ||||
Short-term Debt | $ 150,000,000 | $ 30,000,000 | $ 150,000,000 | |
Money Pool [Member] | ||||
Short-term Debt [Line Items] | ||||
Line of Credit Facility, Maximum Borrowing Capacity | 250,000,000 | 250,000,000 | 250,000,000 | $ 250,000,000 |
Short-term Debt | 0 | 0 | 0 | 85,000,000 |
Short-term Debt, Average Outstanding Amount | 34,000,000 | 32,000,000 | 17,000,000 | 25,000,000 |
Short-term Debt, Maximum Amount Outstanding During Period | $ 119,000,000 | $ 250,000,000 | $ 143,000,000 | $ 142,000,000 |
Short-term Debt, Weighted Average Interest Rate, over Time | 1.67% | 2.05% | 1.96% | 1.14% |
Short-term Debt, Weighted Average Interest Rate, at Point in Time | 1.18% | |||
Commercial Paper [Member] | ||||
Short-term Debt [Line Items] | ||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 500,000,000 | $ 500,000,000 | $ 500,000,000 | $ 500,000,000 |
Short-term Debt | 150,000,000 | 30,000,000 | 150,000,000 | 20,000,000 |
Short-term Debt, Average Outstanding Amount | 2,000,000 | 71,000,000 | 38,000,000 | 62,000,000 |
Short-term Debt, Maximum Amount Outstanding During Period | $ 30,000,000 | $ 317,000,000 | $ 198,000,000 | $ 237,000,000 |
Short-term Debt, Weighted Average Interest Rate, over Time | 2.05% | 2.59% | 2.08% | 1.10% |
Short-term Debt, Weighted Average Interest Rate, at Point in Time | 2.97% | 2.05% | 2.97% | 1.93% |
Letters of Credit (Details)
Letters of Credit (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Line of Credit Facility [Line Items] | ||
Short-term Debt | $ 30 | $ 150 |
Letter of Credit | ||
Line of Credit Facility [Line Items] | ||
Short-term Debt | 10 | $ 37 |
Bilateral Credit Agreement [Member] | Letter of Credit | ||
Line of Credit Facility [Line Items] | ||
Line of Credit Facility, Maximum Borrowing Capacity | 75 | |
Short-term Debt | 22 | |
Line of Credit Facility, Remaining Borrowing Capacity | $ 53 |
Credit Facilities (Details)
Credit Facilities (Details) - Revolving Credit Facility [Member] | 12 Months Ended | ||
Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | ||
Line of Credit Facility [Line Items] | |||
Line Of Credit Facility Debt To Total Capitalization Ratio (as a percent) | 48.00% | 48.00% | |
Line Of Credit Facility Maximum Amount Credit Facility May Be Increased | $ 100,000,000 | ||
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval | 2 | ||
Term Of Each Additional Period Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval | 1 | ||
Line Of Credit Facility Maximum Debt To Total Capitalization Ratio Allowed | 65.00% | ||
Line Of Credit Facility Minimum Threshhold Percentage Of Subsidiary Assets To Consolidated Assets Required To Initiate Cross Default Provisions | 15.00% | ||
Line of Credit Facility, Minimum Amount of Indebtedness in Default to Initiate Cross Default Provisions | $ 75,000,000 | ||
Line of Credit Facility, Maximum Borrowing Capacity | [1] | 500,000,000 | |
Drawn | [2] | 40,000,000 | |
Line of Credit Facility, Remaining Borrowing Capacity | 460,000,000 | ||
Direct advances on the credit facility outstanding | $ 0 | $ 0 | |
[1] | This credit facility matures in June 2024 . | ||
[2] | Includes outstanding commercial paper and letters of credit. |
Long-Term Debt (Details)
Long-Term Debt (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | ||
Long-Term Borrowings and Other Financing Instruments | |||
Long-term Debt, Gross | $ 5,521.3 | $ 4,937.2 | |
Unamortized discount | (31) | (21) | |
Unamortized debt expense | (48) | (42) | |
Long-term Debt, Current Maturities | 300 | 0 | |
Long-term Debt | 5,221 | 4,937 | |
2020 | 300 | ||
2021 | 0 | ||
2022 | 300 | ||
2023 | 400 | ||
2024 | 0 | ||
First Mortgage Bonds | Series Due Aug. 15, 2020 [Member] | |||
Long-Term Borrowings and Other Financing Instruments | |||
Face Amount | $ 300 | 300 | |
Debt Instrument, Interest Rate, Stated Percentage | 2.20% | ||
First Mortgage Bonds | Series Due Aug. 15, 2022 [Member] | |||
Long-Term Borrowings and Other Financing Instruments | |||
Face Amount | $ 300 | 300 | |
Debt Instrument, Interest Rate, Stated Percentage | 2.15% | ||
First Mortgage Bonds | Series Due May 15, 2023 [Member] | |||
Long-Term Borrowings and Other Financing Instruments | |||
Face Amount | $ 400 | 400 | |
Debt Instrument, Interest Rate, Stated Percentage | 2.60% | ||
First Mortgage Bonds | Series Due July 1, 2025 [Member] | |||
Long-Term Borrowings and Other Financing Instruments | |||
Face Amount | $ 250 | 250 | |
Debt Instrument, Interest Rate, Stated Percentage | 7.13% | ||
First Mortgage Bonds | Series Due March 1, 2028 [Member] | |||
Long-Term Borrowings and Other Financing Instruments | |||
Face Amount | $ 150 | 150 | |
Debt Instrument, Interest Rate, Stated Percentage | 6.50% | ||
First Mortgage Bonds | Series Due July 15, 2035 [Domain] | |||
Long-Term Borrowings and Other Financing Instruments | |||
Face Amount | $ 250 | 250 | |
Debt Instrument, Interest Rate, Stated Percentage | 5.25% | ||
First Mortgage Bonds | Series Due June 1, 2036 [Domain] | |||
Long-Term Borrowings and Other Financing Instruments | |||
Face Amount | $ 400 | 400 | |
Debt Instrument, Interest Rate, Stated Percentage | 6.25% | ||
First Mortgage Bonds | Series Due July 1, 2037 [Member] | |||
Long-Term Borrowings and Other Financing Instruments | |||
Face Amount | $ 350 | 350 | |
Debt Instrument, Interest Rate, Stated Percentage | 6.20% | ||
First Mortgage Bonds | Series Due Nov. 1, 2039 [Member] | |||
Long-Term Borrowings and Other Financing Instruments | |||
Face Amount | $ 300 | 300 | |
Debt Instrument, Interest Rate, Stated Percentage | 5.35% | ||
First Mortgage Bonds | Series Due Aug. 15, 2040 [Member] | |||
Long-Term Borrowings and Other Financing Instruments | |||
Face Amount | $ 250 | 250 | |
Debt Instrument, Interest Rate, Stated Percentage | 4.85% | ||
First Mortgage Bonds | Series Due Aug. 15, 2042 [Member] | |||
Long-Term Borrowings and Other Financing Instruments | |||
Face Amount | $ 500 | 500 | |
Debt Instrument, Interest Rate, Stated Percentage | 3.40% | ||
First Mortgage Bonds | Series Due May 15, 2044 [Member] | |||
Long-Term Borrowings and Other Financing Instruments | |||
Face Amount | $ 300 | 300 | |
Debt Instrument, Interest Rate, Stated Percentage | 4.13% | ||
First Mortgage Bonds | Series Due Aug. 15, 2045 [Member] | |||
Long-Term Borrowings and Other Financing Instruments | |||
Face Amount | $ 300 | 300 | |
Debt Instrument, Interest Rate, Stated Percentage | 4.00% | ||
First Mortgage Bonds | Series Due May 15, 2046 [Member] | |||
Long-Term Borrowings and Other Financing Instruments | |||
Face Amount | $ 350 | 350 | |
Debt Instrument, Interest Rate, Stated Percentage | 3.60% | ||
First Mortgage Bonds | Series Due Sept. 15, 2047 [Member] | |||
Long-Term Borrowings and Other Financing Instruments | |||
Face Amount | $ 600 | 600 | |
Debt Instrument, Interest Rate, Stated Percentage | 3.60% | ||
First Mortgage Bonds | Series Due March 1, 2050 [Domain] | |||
Long-Term Borrowings and Other Financing Instruments | |||
Face Amount | [1] | $ 600 | $ 0 |
Debt Instrument, Interest Rate, Stated Percentage | [1] | 2.90% | |
Letter of Credit [Member] | Letter of Credit [Member] | |||
Long-Term Borrowings and Other Financing Instruments | |||
Line of Credit Facility, Expiration Period | 1 year | ||
[1] | 2019 financing |
Deferred Financing Costs (Detai
Deferred Financing Costs (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Deferred Financing Costs [Abstract] | ||
Deferred Finance Costs, Noncurrent, Net | $ 48 | $ 42 |
Dividend and Other Capital-Rela
Dividend and Other Capital-Related Restrictions (Details) $ in Billions | Dec. 31, 2019USD ($) |
Dividend and Other Capital-Related Restrictions [Abstract] | |
Equity to total capitalization ratio, low end of range (in hundredths) | 47.10% |
Equity to total capitalization ratio, high end of range (in hundredths) | 57.50% |
Equity to total capitalization ratio | 52.30% |
Unrestricted Retained Earnings Per State Regulatory Commissions Dividend Restrictions | $ 1.1 |
Capitalization, Short term debt, long term debt and equity | 11.6 |
Maximum total capitalization | $ 12.7 |
Revenues Revenues (Details)
Revenues Revenues (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Total revenue from contracts with customers | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | $ 4,839.4 | $ 4,916.9 |
Retail | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 3,932.9 | 3,975.9 |
Retail | Residential | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 1,613.3 | 1,644.4 |
Retail | Commercial and Industrial (C&I) | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 2,282.9 | 2,291.6 |
Retail | Other | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 36.7 | 39.9 |
Wholesale | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 210.1 | 189.2 |
Transmission | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 216 | 238.1 |
Interchange | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 458.7 | 473.7 |
Other | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 21.7 | 40 |
Alternative and Other [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenue Not from Contract with Customer | 272.4 | 205 |
Regulated Electric | Total revenue from contracts with customers | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 4,264.1 | 4,326.3 |
Regulated Electric | Retail | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 3,367.4 | 3,397 |
Regulated Electric | Retail | Residential | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 1,280.2 | 1,308.4 |
Regulated Electric | Retail | Commercial and Industrial (C&I) | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 2,054.3 | 2,052.1 |
Regulated Electric | Retail | Other | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 32.9 | 36.5 |
Regulated Electric | Wholesale | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 210.1 | 189.2 |
Regulated Electric | Transmission | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 216 | 238.1 |
Regulated Electric | Interchange | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 458.7 | 473.7 |
Regulated Electric | Other | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 11.9 | 28.3 |
Regulated Electric | Alternative and Other [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenue Not from Contract with Customer | 242.5 | 181.7 |
Regulated Natural Gas | Total revenue from contracts with customers | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 541.4 | 559.8 |
Regulated Natural Gas | Retail | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 531.6 | 548.1 |
Regulated Natural Gas | Retail | Residential | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 303 | 308.8 |
Regulated Natural Gas | Retail | Commercial and Industrial (C&I) | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 228.6 | 239.3 |
Regulated Natural Gas | Retail | Other | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 0 | 0 |
Regulated Natural Gas | Wholesale | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 0 | 0 |
Regulated Natural Gas | Transmission | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 0 | 0 |
Regulated Natural Gas | Interchange | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 0 | 0 |
Regulated Natural Gas | Other | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 9.8 | 11.7 |
Regulated Natural Gas | Alternative and Other [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenue Not from Contract with Customer | 29.9 | 23.3 |
All Other | Total revenue from contracts with customers | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 33.9 | 30.8 |
All Other | Retail | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 33.9 | 30.8 |
All Other | Retail | Residential | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 30.1 | 27.2 |
All Other | Retail | Commercial and Industrial (C&I) | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 0 | 0.2 |
All Other | Retail | Other | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 3.8 | 3.4 |
All Other | Wholesale | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 0 | 0 |
All Other | Transmission | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 0 | 0 |
All Other | Interchange | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 0 | 0 |
All Other | Other | ||
Disaggregation of Revenue [Line Items] | ||
Total revenue from contracts with customers | 0 | 0 |
All Other | Alternative and Other [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenue Not from Contract with Customer | 0 | 0 |
Operating Segments | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | 5,111.8 | 5,121.9 |
Operating Segments | Regulated Electric | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | 4,506.6 | 4,508 |
Operating Segments | Regulated Natural Gas | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | 571.3 | 583.1 |
Operating Segments | All Other | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | $ 33.9 | $ 30.8 |
Income Taxes (Details)
Income Taxes (Details) - USD ($) | 1 Months Ended | 3 Months Ended | 12 Months Ended | |||||||||||
Dec. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |||||
Federal Tax Reform [Abstract] | ||||||||||||||
Tax Cuts and Jobs Act of 2017, Corporate Federal Tax Rate | 21.00% | |||||||||||||
Tax Cuts and Jobs Act of 2017, Net Operating Loss Deduction Limitation, Percent of Taxable income | 80.00% | |||||||||||||
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Regulatory Liability, Provisional Income Tax (Expense) Benefit, Gross | $ 1,500,000,000 | |||||||||||||
Tax Cuts and Jobs Act, Incomplete Accounting, Provisional Income Tax Expense (Benefit) | 19,000,000 | |||||||||||||
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Net Income Reduction | 5,000,000 | |||||||||||||
Tax Audits [Abstract] | ||||||||||||||
Unrecognized Tax Benefits, Interest on Income Taxes Accrued | $ (1,600,000) | $ (1,200,000) | $ (900,000) | $ (2,000,000) | ||||||||||
Interest Income (Expense) related to unrecognized tax benefits | $ (400,000) | $ (300,000) | $ 1,100,000 | |||||||||||
Unrecognized Tax Benefits [Abstract] | ||||||||||||||
Unrecognized tax benefit — Permanent tax positions | 14,800,000 | 11,600,000 | ||||||||||||
Unrecognized tax benefit — Temporary tax positions | 4,900,000 | 5,300,000 | ||||||||||||
Total unrecognized tax benefit | 18,100,000 | $ 16,900,000 | 16,900,000 | 18,100,000 | 18,100,000 | $ 60,800,000 | 19,700,000 | 16,900,000 | 18,100,000 | $ 60,800,000 | ||||
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | ||||||||||||||
Balance at Jan. 1 | 16,900,000 | 18,100,000 | 60,800,000 | |||||||||||
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions | 2,600,000 | 2,000,000 | 2,700,000 | |||||||||||
Unrecognized Tax Benefits, Decrease Resulting from Current Period Tax Positions | (500,000) | (300,000) | (1,700,000) | |||||||||||
Unrecognized Tax Benefits Increases Resulting From Prior Period Tax Positions | 700,000 | 600,000 | 5,700,000 | |||||||||||
Unrecognized Tax Benefits Decreases Resulting From Prior Period Tax Positions | 0 | (1,100,000) | (49,400,000) | |||||||||||
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities | 0 | (2,400,000) | 0 | |||||||||||
Balance at Dec. 31 | 18,100,000 | 16,900,000 | $ 19,700,000 | $ 16,900,000 | $ 18,100,000 | $ 60,800,000 | ||||||||
Tax Benefits Associated With NOL And Tax Credit Carryforwards [Abstract] | ||||||||||||||
NOL and tax credit carryforwards | (16,300,000) | (12,700,000) | ||||||||||||
Net Deferred Tax Liability associated with the Unrecognized Tax Benefit Amounts and Related NOLs and Tax Credit Carryforwards | (11,300,000) | (7,300,000) | ||||||||||||
Decrease in Unrecognized Tax Benefits is Reasonably Possible | 13,700,000 | |||||||||||||
Amounts accrued for penalties related to unrecognized tax benefits | 0 | 0 | $ 0 | |||||||||||
Effective Income Tax Rate Reconciliation, Percent [Abstract] | ||||||||||||||
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 21.00% | 21.00% | [1] | 35.00% | [1] | 35.00% | ||||||||
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent | 7.10% | 7.10% | [1] | 5.80% | [1] | |||||||||
Effective Income Tax Rate Reconciliation, Tax Credit, Percent | (11.80%) | (13.60%) | [1] | (11.40%) | [1] | |||||||||
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Percent | 0.00% | 0.00% | [1] | 2.70% | [1] | |||||||||
Effective Income Tax Rate Reconciliation Regulatory Differences Utility Plant Items | [2] | (7.40%) | (8.80%) | [1] | (0.30%) | [1] | ||||||||
Effective Income Tax Rate Reconciliation, Other Regulatory Items, Percent | (1.50%) | (1.10%) | [1] | (1.00%) | [1] | |||||||||
Effective Income Tax Rate Reconciliation Change In Unrecognized Tax Benefits | 0.50% | 0.10% | [1] | (1.60%) | [1] | |||||||||
Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent | 0.10% | 0.50% | [1] | (0.20%) | [1] | |||||||||
Effective Income Tax Rate Reconciliation, Percent | 8.00% | 5.20% | [1] | 29.00% | [1] | |||||||||
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract] | ||||||||||||||
Current Federal Tax Expense (Benefit) | $ 80,700,000 | $ (16,800,000) | $ 29,600,000 | |||||||||||
Current State and Local Tax Expense (Benefit) | 7,900,000 | 5,200,000 | 14,700,000 | |||||||||||
Current Change In Unrecognized Tax Expense (Benefit) | (800,000) | (1,100,000) | (36,200,000) | |||||||||||
Deferred Federal Income Tax Expense (Benefit) | (86,200,000) | (2,400,000) | 121,600,000 | |||||||||||
Deferred State and Local Income Tax Expense (Benefit) | 43,200,000 | 42,100,000 | 46,700,000 | |||||||||||
Deferred Change In Unrecognized Tax Expense (Benefit) | 4,000,000 | 1,600,000 | 24,900,000 | |||||||||||
Deferred investment tax credits | (1,400,000) | (1,400,000) | (1,600,000) | |||||||||||
Income taxes | 47,400,000 | 27,200,000 | 199,700,000 | |||||||||||
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract] | ||||||||||||||
Deferred tax expense (benefit) excluding selected items | 96,700,000 | 70,100,000 | (1,176,400,000) | |||||||||||
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities | (135,400,000) | (28,200,000) | 1,369,900,000 | |||||||||||
Other Comprehensive Income (Loss), Tax | (300,000) | (600,000) | (300,000) | |||||||||||
Deferred Income Tax Expense (Benefit) | $ (39,000,000) | $ 41,300,000 | $ 193,200,000 | |||||||||||
Deferred Tax Liabilities, Gross [Abstract] | ||||||||||||||
Deferred Tax Liabilities, Property, Plant and Equipment | 2,361,000,000 | 2,257,600,000 | [3] | |||||||||||
Deferred Tax Liabilities, Regulatory Assets | 257,400,000 | 260,800,000 | [3] | |||||||||||
Deferred Tax Liabilities, Operating Lease Asset | 169,600,000 | 0 | [3] | |||||||||||
Deferred Tax Liabilities, Compensation and Benefits, Employee Benefits | 68,400,000 | 64,700,000 | [3] | |||||||||||
Deferred Tax Liabilities, Other | 10,200,000 | 9,100,000 | [3] | |||||||||||
Deferred Tax Liabilities, Gross | 2,866,600,000 | 2,592,200,000 | [3] | |||||||||||
Deferred Tax Assets, Gross [Abstract] | ||||||||||||||
Deferred Tax Assets Tax credit carryforward | 526,500,000 | 467,300,000 | [3] | |||||||||||
Deferred Tax Assets Regulatory Liabilities | 364,900,000 | 380,500,000 | [3] | |||||||||||
Deferred Tax Assets, Operating Lease Liabilities | 169,600,000 | 0 | [3] | |||||||||||
Deferred Tax Assets, Operating Loss Carryforwards | 10,400,000 | 17,900,000 | [3] | |||||||||||
Deferred Tax Assets Deferred Investment Tax Credits | 5,900,000 | 6,400,000 | [3] | |||||||||||
Deferred Tax Assets, Valuation Allowance | (66,000,000) | (78,600,000) | [3] | |||||||||||
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Employee Benefits | 37,500,000 | 38,600,000 | [3] | |||||||||||
Deferred Tax Assets Rate Refund | 11,000,000 | 49,700,000 | [3] | |||||||||||
Deferred Tax Assets, Other | 27,700,000 | 28,000,000 | [3] | |||||||||||
Deferred Tax Assets, Net of Valuation Allowance | 1,087,500,000 | 909,800,000 | [3] | |||||||||||
Deferred Tax Liabilities, Net | 1,779,100,000 | 1,682,400,000 | [3] | |||||||||||
Internal Revenue Service (IRS) | ||||||||||||||
Tax Audits [Abstract] | ||||||||||||||
Tax Credit Carryforward, Amount | 449,000,000 | 379,400,000 | ||||||||||||
Potential Tax Adjustments | $ 0 | |||||||||||||
State and Local Jurisdiction | ||||||||||||||
Tax Audits [Abstract] | ||||||||||||||
Operating Loss Carryforwards | 133,000,000 | 221,200,000 | ||||||||||||
Operating Loss Carryforwards, Valuation Allowance | (500,000) | (800,000) | ||||||||||||
Tax Credit Carryforward Net Of Federal Detriment | [4] | 77,500,000 | 87,900,000 | |||||||||||
Valuation Allowance for Tax Credit Carryforward Net of Federal Benefit | [5] | (65,900,000) | (78,500,000) | |||||||||||
Federal detriment | 20,600,000 | 23,400,000 | ||||||||||||
Federal Benefit | $ 17,500,000 | $ 20,900,000 | ||||||||||||
Plant Related Regulatory Liability [Member] | ||||||||||||||
Federal Tax Reform [Abstract] | ||||||||||||||
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Regulatory Liability, Provisional Income Tax (Expense) Benefit | 1,100,000,000 | |||||||||||||
Non-Plant Related Regulated Liability [Member] | ||||||||||||||
Federal Tax Reform [Abstract] | ||||||||||||||
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Regulatory Liability, Provisional Income Tax (Expense) Benefit | 56,000,000 | |||||||||||||
Non-Plant Related Regulatory Asset [Member] | ||||||||||||||
Federal Tax Reform [Abstract] | ||||||||||||||
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Regulatory Asset, Provisional Income Tax Expense (Benefit) | $ 133,000,000 | |||||||||||||
[1] | (a) Prior periods have been reclassified to conform to current year presentation. | |||||||||||||
[2] | (b) Regulatory differences for income tax primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit of excess deferred credits are offset by corresponding revenue reductions. | |||||||||||||
[3] | Prior periods have been reclassified to conform to current year presentation | |||||||||||||
[4] | State tax credit carryforwards are net of federal detriment of $20.6 million and $23.4 million as of Dec. 31, 2019 and 2018, respectively. | |||||||||||||
[5] | Valuation allowances for state tax credit carryforwards were net of federal benefit of $17.5 million and $20.9 million as of Dec. 31, 2019 and 2018, respectively. |
Nuclear Decommissioning Fund (D
Nuclear Decommissioning Fund (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Available-for-sale Securities, Gross Unrealized Gain | $ 705.5 | $ 450.1 | ||
Available-for-sale Securities, Gross Unrealized Loss | 5.9 | 44.8 | ||
Decommissioning Fund Investments, Fair Value | 2,400 | 2,100 | ||
Investments [Abstract] | ||||
Miscellaneous investments | 55.6 | 52.5 | ||
Final Contractual Maturity [Abstract] | ||||
Due in 1 Year or Less | (6.8) | |||
Due in 1 to 5 Years | 110.5 | |||
Due in 5 to 10 Years | 246.1 | |||
Due after 10 Years | 158.1 | |||
Total | 507.9 | |||
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Decommissioning Fund Investments, Fair Value | 2,439.6 | 2,054.7 | ||
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Cost | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Decommissioning Fund Investments, Fair Value | 1,740 | [1] | 1,649.4 | [2] |
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Cost | Cash equivalents | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 33.4 | [1] | 24.3 | [2] |
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Cost | Commingled Funds | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Available-for-sale Securities | 732.8 | [1] | 758.1 | [2] |
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Cost | Debt Securities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Debt Securities, Available-for-sale | 489.2 | [1] | 465.6 | [2] |
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Cost | Equity Securities | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Available-for-sale Securities, Equity Securities | 484.6 | [1] | 401.4 | [2] |
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Alternative Investment | 934.9 | [1] | 819.1 | [2] |
Decommissioning Fund Investments, Fair Value | 2,439.6 | [1] | 2,054.7 | [2] |
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Cash equivalents | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 33.4 | [1] | 24.3 | [2] |
Alternative Investment | 0 | [1] | 0 | [2] |
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Commingled Funds | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Alternative Investment | 934.9 | [1] | 819.1 | [2] |
Available-for-sale Securities | 934.9 | [1] | 898.3 | [2] |
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Debt Securities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Alternative Investment | 0 | [1] | 0 | [2] |
Debt Securities, Available-for-sale | 507.9 | [1] | 435.6 | [2] |
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Equity Securities | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Alternative Investment | 0 | [1] | 0 | [2] |
Available-for-sale Securities, Equity Securities | 963.4 | [1] | 696.5 | [2] |
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Decommissioning Fund Investments, Fair Value | 995.4 | [1] | 800 | [2] |
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Cash equivalents | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 33.4 | [1] | 24.3 | [2] |
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Commingled Funds | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Available-for-sale Securities | 0 | [1] | 79.2 | [2] |
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Debt Securities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Debt Securities, Available-for-sale | 0 | [1] | 0 | [2] |
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Equity Securities | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Available-for-sale Securities, Equity Securities | 962 | [1] | 696.5 | [2] |
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Decommissioning Fund Investments, Fair Value | 496.6 | [1] | 435.6 | [2] |
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Cash equivalents | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 0 | [1] | 0 | [2] |
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Commingled Funds | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Available-for-sale Securities | 0 | [1] | 0 | [2] |
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Debt Securities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Debt Securities, Available-for-sale | 495.2 | [1] | 435.6 | [2] |
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Equity Securities | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Available-for-sale Securities, Equity Securities | 1.4 | [1] | 0 | [2] |
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Decommissioning Fund Investments, Fair Value | 12.7 | [1] | 0 | [2] |
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Cash equivalents | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 0 | [1] | 0 | [2] |
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Commingled Funds | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Available-for-sale Securities | 0 | [1] | 0 | [2] |
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Debt Securities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Debt Securities, Available-for-sale | 12.7 | [1] | 0 | [2] |
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Equity Securities | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Available-for-sale Securities, Equity Securities | $ 0 | [1] | $ 0 | [2] |
[1] | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $55.6 million of rabbi trust assets and miscellaneous investments. | |||
[2] | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $52.5 million of rabbi trust assets and miscellaneous investments. |
Fair Value of Financial Asset_3
Fair Value of Financial Assets and Liabilities Rabbi Trust (Details) - Fair Value Measured on a Recurring Basis - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | [1] | |
Cost | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Debt Securities, Trading, and Equity Securities, FV-NI | $ 12.6 | $ 11.2 | ||
Cost | Rabbi Trust [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 1.2 | [2] | 0.4 | |
Cost | Mutual Funds [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Debt Securities, Trading, and Equity Securities, FV-NI | 11.4 | [2] | 10.8 | |
Fair Value | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Debt Securities, Trading, and Equity Securities, FV-NI | 14.3 | [2] | 11.1 | |
Fair Value | Level 1 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Debt Securities, Trading, and Equity Securities, FV-NI | 14.3 | [2] | 11.1 | |
Fair Value | Level 2 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Debt Securities, Trading, and Equity Securities, FV-NI | 0 | [2] | 0 | |
Fair Value | Level 3 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Debt Securities, Trading, and Equity Securities, FV-NI | 0 | [2] | 0 | |
Fair Value | Rabbi Trust [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 1.2 | [2] | 0.4 | |
Fair Value | Rabbi Trust [Member] | Level 1 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 1.2 | [2] | 0.4 | |
Fair Value | Rabbi Trust [Member] | Level 2 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 0 | [2] | 0 | |
Fair Value | Rabbi Trust [Member] | Level 3 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 0 | [2] | 0 | |
Fair Value | Mutual Funds [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Debt Securities, Trading, and Equity Securities, FV-NI | 13.1 | [2] | 10.7 | |
Fair Value | Mutual Funds [Member] | Level 1 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Debt Securities, Trading, and Equity Securities, FV-NI | 13.1 | [2] | 10.7 | |
Fair Value | Mutual Funds [Member] | Level 2 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Debt Securities, Trading, and Equity Securities, FV-NI | 0 | [2] | 0 | |
Fair Value | Mutual Funds [Member] | Level 3 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Debt Securities, Trading, and Equity Securities, FV-NI | $ 0 | [2] | $ 0 | |
[1] | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet. | |||
[2] | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet. |
Interest Rate Derivatives (Deta
Interest Rate Derivatives (Details) $ in Millions | Dec. 31, 2019USD ($) |
Interest Rate Swap [Member] | |
Interest Rate Derivatives [Abstract] | |
Amount of accumulated other comprehensive gains (losses) related to interest rate derivatives expected to be reclassified into earnings within the next twelve months | $ (0.8) |
Fair Value of Financial Asset_4
Fair Value of Financial Assets and Liabilities Commodity Derivatives (Details) MWh in Millions, MMBTU in Millions, $ in Millions | Dec. 31, 2019USD ($)MMBTUMWh | Dec. 31, 2018MMBTUMWh | |
Derivative [Line Items] | |||
Commodity contracts designated as cash flow hedges | $ | $ 0 | ||
Electric Commodity | |||
Derivative [Line Items] | |||
Derivative, Nonmonetary Notional Amount | MWh | [1],[2] | 79.1 | 56.8 |
Natural Gas Commodity | |||
Derivative [Line Items] | |||
Derivative, Nonmonetary Notional Amount | MMBTU | [1],[2] | 77.8 | 42.7 |
[1] | Amounts are not reflective of net positions in the underlying commodities. | ||
[2] | Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise. |
Fair Value of Financial Asset_5
Fair Value of Financial Assets and Liabilities Consideration of Credit Risk and Concentrations (Details) - Credit Concentration Risk [Member] $ in Millions | Dec. 31, 2019USD ($)Counterparty |
Derivative [Line Items] | |
Number of most significant counterparties | 10 |
Municipal or Cooperative Entities or Other Utilities | |
Derivative [Line Items] | |
Number of most significant counterparties | 9 |
External Credit Rating, Investment Grade | |
Derivative [Line Items] | |
Number of most significant counterparties | 8 |
Credit exposure for the most significant counterparties | $ | $ 54.2 |
Percentage of credit exposure for the most significant counterparties | 68.00% |
No Investment Grade Ratings from External Credit Rating Agencies | |
Derivative [Line Items] | |
Number of most significant counterparties | 2 |
Credit exposure for the most significant counterparties | $ | $ 15.8 |
Percentage of credit exposure for the most significant counterparties | 20.00% |
Qualifying Cash Flow Hedges (De
Qualifying Cash Flow Hedges (Details) - USD ($) $ in Millions | 12 Months Ended | ||||||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |||||
Financial Impact of Qualifying Cash Flow Hedges on Accumulated Other Comprehensive Income (Loss) [Roll Forward] | |||||||
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 | $ (20.2) | $ (20.9) | $ (18.2) | ||||
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges | 0 | 0 | 0.1 | ||||
After-tax net realized losses on derivative transactions reclassified into earnings | 0.8 | 0.7 | 0.9 | ||||
Adoption of ASU. 2018-02 (a) | [1] | 0 | 0 | (3.7) | |||
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 | (19.4) | (20.2) | (20.9) | ||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | |||||||
Fair Value Hedges, Net | 0 | 0 | 0 | ||||
Not Designated as Hedging Instrument | |||||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | |||||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 0 | 0 | 0 | ||||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | (1.4) | (3.7) | 7.4 | ||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | 0 | 0 | ||||
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities) | (1.7) | (1.4) | (12.8) | ||||
Derivative, Gain (Loss) on Derivative, Net | (3.2) | 9.6 | 8.2 | ||||
Not Designated as Hedging Instrument | Commodity Trading Contract | |||||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | |||||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | 0 | 0 | ||||
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | 0 | ||||
Derivative, Gain (Loss) on Derivative, Net | [2] | (0.7) | 10.9 | 9.4 | |||
Not Designated as Hedging Instrument | Electric Commodity Contract | |||||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | |||||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 0 | 0 | 0 | ||||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 1.5 | (5.5) | 9.3 | ||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | 0 | 0 | ||||
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities) | [3] | (0.8) | (3.3) | (13.8) | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | 0 | ||||
Not Designated as Hedging Instrument | Natural Gas Commodity Contract | |||||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | |||||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 0 | 0 | 0 | ||||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | (2.9) | 1.8 | (1.9) | ||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | 0 | 0 | ||||
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities) | [4] | (0.9) | (1.9) | (1) | |||
Derivative, Gain (Loss) on Derivative, Net | [4] | (2.5) | (1.3) | (1.2) | |||
Designated as Hedging Instrument | Cash Flow Hedges | |||||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | |||||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 1.1 | 1 | (0.1) | ||||
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | 0 | ||||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | |||||
Designated as Hedging Instrument | Cash Flow Hedges | Interest Rate Contract | |||||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | |||||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 1.1 | [5] | 1.1 | [5] | 1.5 | [6] | |
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | 0 | ||||
Derivative, Gain (Loss) on Derivative, Net | $ 0 | 0 | 0 | ||||
Designated as Hedging Instrument | Cash Flow Hedges | Vehicle Fuel Commodity | |||||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | |||||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | (0.1) | [6] | (0.1) | ||||
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities) | 0 | $ 0 | |||||
Derivative, Gain (Loss) on Derivative, Net | $ 0 | ||||||
[1] | In 2017, NSP-Minnesota implemented ASU No. 2018-02 related to TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings. | ||||||
[2] | Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate. | ||||||
[3] | Amounts are recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate. | ||||||
[4] | Amounts are recorded to cost of natural gas sold and transported. These derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms, and reclassified out of income as regulatory assets and liabilities, as appropriate. | ||||||
[5] | Amounts are recorded to interest charges. | ||||||
[6] | Amounts are recorded to O&M expenses. |
Credit Related Contingent Featu
Credit Related Contingent Features (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Fair Value Disclosures [Abstract] | ||
Derivative instruments in a gross liability position | $ 7.1 | $ 0 |
Collateral posted related to adequate assurance clauses in derivative contracts | $ 0 | $ 0 |
Recurring Fair Value Measuremen
Recurring Fair Value Measurements (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | ||
Derivatives, Fair Value [Line Items] | ||||
Return Cash Collateral | $ 31.5 | $ 31.5 | ||
Reclaim Cash Collateral | 7.9 | 8.7 | ||
Commodity Contract [Member] | ||||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward] | ||||
Balance at beginning of period | 14.3 | 22.6 | $ 15.3 | |
Purchases | 16.7 | 26.4 | 40.6 | |
Settlements | (27.5) | (17.2) | (41.7) | |
Gains (losses) recognized in earnings | [1] | 3.2 | (1.5) | 5.5 |
Net gains (losses) recognized as regulatory assets and liabilities | (1.4) | (16) | 2.9 | |
Balance at end of period | 5.3 | 14.3 | 22.6 | |
Transfers Between Levels, Net | 0 | 0 | $ 0 | |
Other Current Assets | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Net | 32.5 | 25.8 | ||
Other Noncurrent Assets | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Net | 9.2 | 17 | ||
Other Current Liabilities | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Net | 25 | 16.5 | ||
Other Noncurrent Liabilities | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Net | 110.2 | 112.2 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Gross | 75.5 | 41.9 | ||
Netting | [2] | (43) | (16.1) | |
Derivative Asset, Net | 32.5 | 25.8 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets | Level 1 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Gross | 1.6 | 1.1 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets | Level 2 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Gross | 41.6 | 28.1 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets | Level 3 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Gross | 32.3 | 12.7 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Contract [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Gross | 64.7 | 30.4 | ||
Netting | [2] | (42.1) | (16) | |
Derivative Asset, Net | 22.6 | 14.4 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Contract [Member] | Level 1 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Gross | 1.6 | 1.1 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Contract [Member] | Level 2 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Gross | 39.5 | 27.1 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Contract [Member] | Level 3 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Gross | 23.6 | 2.2 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Electric Commodity | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Gross | 8.7 | 10.5 | ||
Netting | [2] | (0.9) | (0.1) | |
Derivative Asset, Net | 7.8 | 10.4 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Electric Commodity | Level 1 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Gross | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Electric Commodity | Level 2 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Gross | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Electric Commodity | Level 3 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Gross | 8.7 | 10.5 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Gross | 2.1 | 1 | ||
Netting | [2] | 0 | 0 | |
Derivative Asset, Net | 2.1 | 1 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity | Level 1 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Gross | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity | Level 2 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Gross | 2.1 | 1 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity | Level 3 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Gross | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Gross | 43.9 | 30.3 | ||
Netting | [2] | (34.8) | (13.4) | |
Derivative Asset, Net | 9.1 | 16.9 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Level 1 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Gross | 8.5 | 0 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Level 2 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Gross | 29.4 | 25.3 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Level 3 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Gross | 6 | 5 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Contract [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Gross | 43.9 | 30.3 | ||
Netting | [2] | (34.8) | (13.4) | |
Derivative Asset, Net | 9.1 | 16.9 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Contract [Member] | Level 1 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Gross | 8.5 | 0 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Contract [Member] | Level 2 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Gross | 29.4 | 25.3 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Contract [Member] | Level 3 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Gross | 6 | 5 | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Gross | 62 | 27.1 | ||
Netting | [2] | 50.8 | 24.6 | |
Derivative Liability, Net | 11.2 | 2.5 | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Level 1 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Gross | 2.2 | 1.4 | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Level 2 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Gross | 43.8 | 23.9 | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Level 3 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Gross | 16 | 1.8 | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Contract [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Gross | 59.3 | 27 | ||
Netting | [2] | 49.8 | 24.5 | |
Derivative Liability, Net | 9.5 | 2.5 | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Contract [Member] | Level 1 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Gross | 2.2 | 1.4 | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Contract [Member] | Level 2 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Gross | 42.1 | 23.9 | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Contract [Member] | Level 3 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Gross | 15 | 1.7 | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Gross | 1 | 0.1 | ||
Netting | [2] | 1 | 0.1 | |
Derivative Liability, Net | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity | Level 1 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Gross | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity | Level 2 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Gross | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity | Level 3 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Gross | 1 | 0.1 | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Gross | 1.7 | 0 | ||
Netting | [2] | 0 | 0 | |
Derivative Liability, Net | 1.7 | 0 | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity | Level 1 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Gross | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity | Level 2 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Gross | 1.7 | 0 | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity | Level 3 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Gross | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Gross | 51.3 | 17.7 | ||
Netting | [2] | 3.3 | 17.9 | |
Derivative Liability, Net | 48 | 35.6 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Level 1 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Gross | 2 | 0.1 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Level 2 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Gross | 32.3 | 16 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Level 3 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Gross | 17 | 1.6 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Contract [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Gross | 51.3 | 17.7 | ||
Netting | [2] | 3.3 | 17.9 | |
Derivative Liability, Net | 48 | 35.6 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Contract [Member] | Level 1 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Gross | 2 | 0.1 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Contract [Member] | Level 2 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Gross | 32.3 | 16 | ||
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Contract [Member] | Level 3 | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Gross | 17 | 1.6 | ||
Fair Value, Measurements, Nonrecurring | Other Current Assets | Purchased Power Agreements | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Net | [3] | 0 | 0 | |
Fair Value, Measurements, Nonrecurring | Other Noncurrent Assets | Purchased Power Agreements | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Net | [3] | 0.1 | 0.1 | |
Fair Value, Measurements, Nonrecurring | Other Current Liabilities | Purchased Power Agreements | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Net | [3] | 13.8 | 14 | |
Fair Value, Measurements, Nonrecurring | Other Noncurrent Liabilities | Purchased Power Agreements | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Net | [3] | $ 62.2 | $ 76.6 | |
[1] | Amounts relate to commodity derivatives held at the end of the period. | |||
[2] | NSP-Minnesota nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2019 and 2018 . At both Dec. 31, 2019 and 2018 , derivative assets and liabilities include $31.5 million of obligations to return cash collateral, respectively. At Dec. 31, 2019 and 2018 , derivative assets and liabilities include the rights to reclaim cash collateral of $7.9 million and $8.7 million , respectively. The counterparty netting excludes settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. | |||
[3] | During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. |
Fair Value of Long-Term Debt (D
Fair Value of Long-Term Debt (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Financial Liabilities, Balance Sheet Groupings [Abstract] | ||
Long-term Debt, Gross | $ 5,521.3 | $ 4,937.2 |
Long-term debt, Fair Value | $ 6,296.5 | $ 5,230.9 |
Fair Value of Financial Asset_6
Fair Value of Financial Assets and Liabilities Fair Value Phantom (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Fair Value Hedges, Net | $ 0 | $ 0 | $ 0 |
Collateral Already Posted Adequate Assurance Clauses Aggregate Fair Value | 0 | 0 | |
Return Cash Collateral | 31.5 | 31.5 | |
Commodity Contract [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Transfers Between Levels, Net | $ 0 | $ 0 | $ 0 |
Benefit Plans and Other Postr_3
Benefit Plans and Other Postretirement Benefits, Pension Benefits (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Target Pension Asset Allocations [Abstract] | ||||
Defined Contribution Plan, Cost | $ 12 | $ 12 | $ 12 | |
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan | ||||
Pension Benefits [Abstract] | ||||
Total benefit obligation | 4 | 4 | ||
Net benefit cost recognized for financial reporting | 1 | 1 | ||
Pension Plan | ||||
Pension Benefits [Abstract] | ||||
Total benefit obligation | 942.2 | 907 | 1,035.1 | |
Net benefit cost recognized for financial reporting | $ 33.1 | $ 26.2 | $ 25.1 | |
Minimum number of years historical achieved weighted average annual returns used to determine investment return assumptions (in years) | 20 years | |||
Expected average long-term rate of return on assets (as a percent) | 7.10% | 7.10% | 7.10% | |
Target Pension Asset Allocations [Abstract] | ||||
Target pension asset allocations (as a percent) | 100.00% | 100.00% | ||
Pension Plan | Domestic and international equity securities | ||||
Target Pension Asset Allocations [Abstract] | ||||
Target pension asset allocations (as a percent) | 37.00% | 37.00% | ||
Pension Plan | Long-duration fixed income and interest rate swap securities | ||||
Target Pension Asset Allocations [Abstract] | ||||
Target pension asset allocations (as a percent) | 30.00% | 28.00% | ||
Pension Plan | Short-to-intermediate fixed income securities | ||||
Target Pension Asset Allocations [Abstract] | ||||
Target pension asset allocations (as a percent) | 14.00% | 18.00% | ||
Pension Plan | Alternative investments | ||||
Target Pension Asset Allocations [Abstract] | ||||
Target pension asset allocations (as a percent) | 17.00% | 15.00% | ||
Pension Plan | Cash | ||||
Target Pension Asset Allocations [Abstract] | ||||
Target pension asset allocations (as a percent) | 2.00% | 2.00% | ||
Xcel Energy Inc. | Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan | ||||
Pension Benefits [Abstract] | ||||
Total benefit obligation | $ 39 | $ 33 | ||
Net benefit cost recognized for financial reporting | $ 4 | |||
Forecast [Member] | Pension Plan | ||||
Pension Benefits [Abstract] | ||||
Expected average long-term rate of return on assets for next fiscal year (as a percent) | 7.10% |
Benefit Plans and Other Postr_4
Benefit Plans and Other Postretirement Benefits, Fair Value of Pension Plan Assets (Details) - Pension Plan - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 |
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | $ 815.2 | $ 710.6 | $ 824.5 |
Plan assets at net asset value | 265.1 | 263 | |
Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 392.3 | 302.6 | |
Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 156.7 | 145 | |
Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 1.1 | 0 | |
Debt Securities [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 156.6 | 143.7 | |
Plan assets at net asset value | 0 | 0 | |
Debt Securities [Member] | Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Debt Securities [Member] | Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 155.5 | 143.7 | |
Debt Securities [Member] | Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 1.1 | 0 | |
Cash | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 40.9 | 31.8 | |
Plan assets at net asset value | 0 | 0 | |
Cash | Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 40.9 | 31.8 | |
Cash | Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Cash | Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Commingled Funds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 630.6 | 512.2 | |
Plan assets at net asset value | 270.3 | 271.2 | |
Commingled Funds | Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 360.3 | 241 | |
Commingled Funds | Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Commingled Funds | Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Domestic and international equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 22.6 | 29.3 | |
Plan assets at net asset value | 0 | 0 | |
Domestic and international equity securities | Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 22.6 | 29.3 | |
Domestic and international equity securities | Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Domestic and international equity securities | Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Other | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | (35.5) | (6.4) | |
Plan assets at net asset value | (5.2) | (8.2) | |
Other | Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | (31.5) | 0.5 | |
Other | Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 1.2 | 1.3 | |
Other | Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | $ 0 | $ 0 |
Benefit Plans and Other Postr_5
Benefit Plans and Other Postretirement Benefits, Pension Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) $ in Millions | 12 Months Ended | ||||
Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($)Plan | Dec. 31, 2018USD ($)Plan | Dec. 31, 2017USD ($)Plan | ||
Significant Assumptions Used to Measure Costs [Abstract] | |||||
Liability, Defined Benefit Plan, Noncurrent | $ (235.9) | $ (305.1) | |||
Pension Plan | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement | [1] | 0 | (48.8) | $ (48.2) | |
Defined Benefit Plan, Accumulated Benefit Obligation | 872 | 845 | |||
Change in Projected Benefit Obligation [Roll Forward] | |||||
Obligation at Jan. 1 | $ 942.2 | 907 | 1,035.1 | ||
Service cost | 25.4 | 28 | 27.8 | ||
Interest cost | 37.1 | 35.2 | 40.7 | ||
Plan amendments | 1 | 0 | |||
Actuarial loss (gain) | 61.7 | (50.8) | |||
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant | 0 | 0 | |||
Benefit payments | (90) | (140.5) | |||
Obligation at Dec. 31 | 942.2 | 907 | 1,035.1 | ||
Defined Benefit Plan, Plan Assets, Payment for Settlement | 105 | ||||
Change in Fair Value of Plan Assets [Roll Forward] | |||||
Fair value of plan assets at Jan. 1 | $ 815.2 | 710.6 | 824.5 | ||
Actual return (loss) on plan assets | 147.8 | (36.5) | |||
Employer contributions | 46.8 | 63.1 | |||
Benefit payments | (90) | (140.5) | |||
Fair value of plan assets at Dec. 31 | 815.2 | 710.6 | 824.5 | ||
Funded Status of Plans at Dec. 31 [Abstract] | |||||
Funded status | (127) | (196.4) | |||
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract] | |||||
Net loss | 440 | 502 | |||
Prior service (credit) cost | (0.2) | (1.2) | |||
Total | 439.8 | 500.8 | |||
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates [Abstract] | |||||
Current regulatory assets | 29.3 | 35.5 | |||
Noncurrent regulatory assets | 410.5 | 465.3 | |||
Total | $ 439.8 | $ 500.8 | |||
Significant Assumptions Used to Measure Benefit Obligations [Abstract] | |||||
Discount rate for year-end valuation (as a percent) | 3.49% | 4.31% | |||
Expected average long-term increase in compensation level (as a percent) | 3.75% | 3.75% | |||
Cash Flows [Abstract] | |||||
Total contributions to Xcel Energy's pension plans during the period | $ 47 | $ 63 | 61 | ||
Components of Net Periodic Benefit Cost (Credit) [Abstract] | |||||
Service cost | 25.4 | 28 | 27.8 | ||
Interest cost | 37.1 | 35.2 | 40.7 | ||
Expected return on plan assets | (54.3) | (58.2) | (60.1) | ||
Amortization of prior service cost (credit) | (0.1) | (0.1) | 1.1 | ||
Amortization of net loss | 30.2 | 38.5 | 39.6 | ||
Net periodic pension cost | 38.3 | 92.2 | 97.3 | ||
Costs not recognized due to effects of regulation | (5.2) | (66) | (72.2) | ||
Net benefit cost recognized for financial reporting | 33.1 | 26.2 | $ 25.1 | ||
Significant Assumptions Used to Measure Costs [Abstract] | |||||
Defined Benefit Plan, Plan Assets, Contributions by Plan Participant | 0 | 0 | |||
Liability, Defined Benefit Plan, Current | 0 | 0 | |||
Liability, Defined Benefit Plan, Noncurrent | (127) | (196.4) | |||
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position | $ (127) | $ (196.4) | |||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 4.31% | 3.63% | 4.13% | ||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase | 3.75% | 3.75% | 3.75% | ||
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Deferred Income Taxes | $ 0 | $ 0 | |||
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Net-Of-Tax Accumulated Other Comprehensive Income | 0 | 0 | |||
Defined Benefit Plan, Accumulated Benefit Obligation | $ (872) | $ (845) | |||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets | 7.10% | 7.10% | 7.10% | ||
Xcel Energy Inc. | Pension Plan | |||||
Cash Flows [Abstract] | |||||
Number of pension plans to which contributions were made | Plan | 4 | 4 | 4 | ||
Total contributions to Xcel Energy's pension plans during the period | $ 154 | $ 150 | $ 162 | ||
Subsequent Event | |||||
Cash Flows [Abstract] | |||||
Number of pension plans to which contributions were made | 4 | ||||
Significant Assumptions Used to Measure Costs [Abstract] | |||||
Expected contribution to postretirement health care plans next year | $ 7 | ||||
Subsequent Event | Pension Plan | |||||
Cash Flows [Abstract] | |||||
Total contributions to Xcel Energy's pension plans during the period | 44 | ||||
Subsequent Event | Xcel Energy Inc. | |||||
Significant Assumptions Used to Measure Costs [Abstract] | |||||
Expected contribution to postretirement health care plans next year | 10 | ||||
Subsequent Event | Xcel Energy Inc. | Pension Plan | |||||
Cash Flows [Abstract] | |||||
Total contributions to Xcel Energy's pension plans during the period | $ 150 | ||||
[1] | A settlement charge is required when the amount of lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2018 and 2017, as a result of lump-sum distributions during the 2018 and 2017 plan years, NSP-Minnesota recorded a total pension settlement charge of $48.8 million in 2018 and $48.2 million |
Benefit Plans and Other Postr_6
Benefit Plans and Other Postretirement Benefits, Defined Contribution Plans (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Defined Contribution Plans [Abstract] | |||
Defined Contribution Plan, Cost | $ 12 | $ 12 | $ 12 |
Benefit Plans and Other Postr_7
Benefit Plans and Other Postretirement Benefits, Postretirement Health Care Benefits (Details) - Postretirement Benefits Plan | Dec. 31, 2019 | Dec. 31, 2018 |
Postretirement Health Care Benefits [Abstract] | ||
Target pension asset allocations (as a percent) | 100.00% | 100.00% |
Domestic and international equity securities | ||
Postretirement Health Care Benefits [Abstract] | ||
Target pension asset allocations (as a percent) | 15.00% | 18.00% |
Long-duration fixed income and interest rate swap securities | ||
Postretirement Health Care Benefits [Abstract] | ||
Target pension asset allocations (as a percent) | 0.00% | 0.00% |
Short-to-intermediate fixed income securities | ||
Postretirement Health Care Benefits [Abstract] | ||
Target pension asset allocations (as a percent) | 72.00% | 70.00% |
Alternative investments | ||
Postretirement Health Care Benefits [Abstract] | ||
Target pension asset allocations (as a percent) | 9.00% | 8.00% |
Cash | ||
Postretirement Health Care Benefits [Abstract] | ||
Target pension asset allocations (as a percent) | 4.00% | 4.00% |
Benefit Plans and Other Postr_8
Benefit Plans and Other Postretirement Benefits, Fair Value of Postretirement Benefit Plan Assets (Details) - Postretirement Benefits Plan - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 |
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | $ 2.6 | $ 2.4 | $ 6.5 |
Plan assets at net asset value | 0.5 | 0.2 | |
Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0.5 | 0.9 | |
Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 1.6 | 1.3 | |
Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Debt Securities [Member] | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 1.3 | 1 | |
Plan assets at net asset value | 0 | 0 | |
Debt Securities [Member] | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Debt Securities [Member] | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 1.3 | 1 | |
Debt Securities [Member] | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Equity Securities | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Plan assets at net asset value | 0 | 0 | |
Equity Securities | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Equity Securities | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Equity Securities | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Cash | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0.1 | 0.1 | |
Plan assets at net asset value | 0 | 0 | |
Cash | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0.1 | 0.1 | |
Cash | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Cash | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Insurance contracts | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0.3 | 0.3 | |
Plan assets at net asset value | 0 | 0 | |
Insurance contracts | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Insurance contracts | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0.3 | 0.3 | |
Insurance contracts | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Commingled Funds | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0.9 | 1 | |
Plan assets at net asset value | 0.5 | 0.2 | |
Commingled Funds | Level 1 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0.4 | 0.8 | |
Commingled Funds | Level 2 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | 0 | 0 | |
Commingled Funds | Level 3 | |||
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract] | |||
Fair value of plan assets | $ 0 | $ 0 |
Benefit Plans and Other Postr_9
Benefit Plans and Other Postretirement Benefits, Postretirement Benefit Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) - USD ($) $ in Millions | 12 Months Ended | ||||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | ||
Funded Status of Plans at Dec. 31 [Abstract] | |||||
Noncurrent liabilities | $ (235.9) | $ (305.1) | |||
Cash Flows [Abstract] | |||||
Total contributions to Xcel Energy's postretirement health care plans during the year | 8 | 3 | $ 10 | ||
Pension Plan | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan amendments | 1 | 0 | |||
Payment for Pension Benefits | 47 | 63 | 61 | ||
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Current Regulatory Assets | 29.3 | 35.5 | |||
Change in Projected Benefit Obligation [Roll Forward] | |||||
Obligation at Jan. 1 | $ 942.2 | 907 | 1,035.1 | ||
Service cost | 25.4 | 28 | 27.8 | ||
Interest cost | 37.1 | 35.2 | 40.7 | ||
Plan participants' contributions | 0 | 0 | |||
Actuarial loss (gain) | 61.7 | (50.8) | |||
Benefit payments | (90) | (140.5) | |||
Obligation at Dec. 31 | 942.2 | 907 | 1,035.1 | ||
Change in Fair Value of Plan Assets [Roll Forward] | |||||
Fair value of plan assets at Jan. 1 | 815.2 | 710.6 | 824.5 | ||
Actual return (loss) on plan assets | 147.8 | (36.5) | |||
Defined Benefit Plan, Plan Assets, Contributions by Plan Participant | 0 | 0 | |||
Employer contributions | 46.8 | 63.1 | |||
Benefit payments | (90) | (140.5) | |||
Fair value of plan assets at Dec. 31 | 815.2 | 710.6 | 824.5 | ||
Funded Status of Plans at Dec. 31 [Abstract] | |||||
Funded status | (127) | (196.4) | |||
Current liabilities | 0 | 0 | |||
Noncurrent liabilities | (127) | (196.4) | |||
Net postretirement amounts recognized on consolidated balance sheets | (127) | (196.4) | |||
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract] | |||||
Net loss | 440 | 502 | |||
Prior service (credit) cost | (0.2) | (1.2) | |||
Total | 439.8 | 500.8 | |||
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates [Abstract] | |||||
Noncurrent regulatory assets | 410.5 | 465.3 | |||
Deferred income taxes | 0 | 0 | |||
Net-of-tax accumulated other comprehensive income | 0 | 0 | |||
Total | $ 439.8 | $ 500.8 | |||
Significant Assumptions Used to Measure Benefit Obligations [Abstract] | |||||
Discount rate for year-end valuation (as a percent) | 3.49% | 4.31% | |||
Components of Net Periodic Benefit Cost (Credit) [Abstract] | |||||
Service cost | $ 25.4 | $ 28 | 27.8 | ||
Interest cost | 37.1 | 35.2 | 40.7 | ||
Expected return on plan assets | (54.3) | (58.2) | (60.1) | ||
Amortization of prior service cost (credit) | (0.1) | (0.1) | 1.1 | ||
Amortization of net loss | 30.2 | 38.5 | 39.6 | ||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement | [1] | 0 | 48.8 | 48.2 | |
Net periodic postretirement benefit cost | $ 38.3 | $ 92.2 | $ 97.3 | ||
Significant Assumptions Used to Measure Costs [Abstract] | |||||
Discount rate (as a percent) | 4.31% | 3.63% | 4.13% | ||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase | 3.75% | 3.75% | 3.75% | ||
Expected average long-term rate of return on assets (as a percent) | 7.10% | 7.10% | 7.10% | ||
Defined Benefit Plan Credits (Costs) Not Recognized Due To Effects of Regulation | $ (5.2) | $ (66) | $ (72.2) | ||
Net benefit cost recognized for financial reporting | 33.1 | 26.2 | 25.1 | ||
Postretirement Benefits Plan | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan amendments | 0 | 0 | |||
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Current Regulatory Assets | 0 | 0 | |||
Change in Projected Benefit Obligation [Roll Forward] | |||||
Obligation at Jan. 1 | 75.5 | 76 | 88.8 | ||
Service cost | 0.1 | 0.2 | 0.1 | ||
Interest cost | 3.2 | 3.1 | 3.4 | ||
Plan participants' contributions | 0.3 | 0.4 | |||
Actuarial loss (gain) | 3.8 | (9) | |||
Benefit payments | (7.9) | (7.5) | |||
Obligation at Dec. 31 | 75.5 | 76 | 88.8 | ||
Change in Fair Value of Plan Assets [Roll Forward] | |||||
Fair value of plan assets at Jan. 1 | 2.6 | 2.4 | 6.5 | ||
Actual return (loss) on plan assets | 0 | 0 | |||
Defined Benefit Plan, Plan Assets, Contributions by Plan Participant | 0.3 | 0.4 | |||
Employer contributions | 7.7 | 3 | |||
Benefit payments | (7.8) | (7.5) | |||
Fair value of plan assets at Dec. 31 | 2.6 | 2.4 | 6.5 | ||
Funded Status of Plans at Dec. 31 [Abstract] | |||||
Funded status | (72.9) | (73.6) | |||
Current liabilities | (4.3) | (4.8) | |||
Noncurrent liabilities | (68.6) | (68.8) | |||
Net postretirement amounts recognized on consolidated balance sheets | (72.9) | (73.6) | |||
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract] | |||||
Net loss | 36.8 | 34.3 | |||
Prior service (credit) cost | (9.4) | (12.4) | |||
Total | 27.4 | 21.9 | |||
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates [Abstract] | |||||
Noncurrent regulatory assets | 25.6 | 20.5 | |||
Deferred income taxes | 0.5 | 0.4 | |||
Net-of-tax accumulated other comprehensive income | 1.3 | 1 | |||
Total | $ 27.4 | $ 21.9 | |||
Significant Assumptions Used to Measure Benefit Obligations [Abstract] | |||||
Discount rate for year-end valuation (as a percent) | 3.47% | 4.32% | |||
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Pre-65 | 6.00% | 6.50% | |||
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Post-65 | 5.10% | 5.30% | |||
Ultimate health care trend assumption rate (as a percent) | 4.50% | 4.50% | |||
Period until ultimate trend rate is reached (in years) | 3 years | 4 years | |||
Components of Net Periodic Benefit Cost (Credit) [Abstract] | |||||
Service cost | $ 0.1 | $ 0.2 | 0.1 | ||
Interest cost | 3.2 | 3.1 | 3.4 | ||
Expected return on plan assets | (0.1) | (0.4) | (0.2) | ||
Amortization of prior service cost (credit) | (3) | (3) | (3) | ||
Amortization of net loss | 1.5 | 2.4 | 2 | ||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement | 0 | 0 | 0 | ||
Net periodic postretirement benefit cost | $ 1.7 | $ 2.3 | $ 2.3 | ||
Significant Assumptions Used to Measure Costs [Abstract] | |||||
Discount rate (as a percent) | 4.32% | 3.62% | 4.13% | ||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase | 0.00% | 0.00% | 0.00% | ||
Expected average long-term rate of return on assets (as a percent) | 4.50% | 5.30% | 5.80% | ||
Defined Benefit Plan Credits (Costs) Not Recognized Due To Effects of Regulation | $ 0 | $ 0 | $ 0 | ||
Net benefit cost recognized for financial reporting | 1.7 | 2.3 | 2.3 | ||
Xcel Energy Inc. | |||||
Cash Flows [Abstract] | |||||
Total contributions to Xcel Energy's postretirement health care plans during the year | 15 | 11 | 20 | ||
Xcel Energy Inc. | Pension Plan | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Payment for Pension Benefits | $ 154 | $ 150 | $ 162 | ||
Subsequent Event | |||||
Cash Flows [Abstract] | |||||
Expected contribution to postretirement health care plans next year | 7 | ||||
Subsequent Event | Pension Plan | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Payment for Pension Benefits | 44 | ||||
Subsequent Event | Xcel Energy Inc. | |||||
Cash Flows [Abstract] | |||||
Expected contribution to postretirement health care plans next year | 10 | ||||
Subsequent Event | Xcel Energy Inc. | Pension Plan | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Payment for Pension Benefits | $ 150 | ||||
[1] | A settlement charge is required when the amount of lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2018 and 2017, as a result of lump-sum distributions during the 2018 and 2017 plan years, NSP-Minnesota recorded a total pension settlement charge of $48.8 million in 2018 and $48.2 million |
Benefit Plans and Other Post_10
Benefit Plans and Other Postretirement Benefits, Projected Benefit Payments (Details) $ in Millions | Dec. 31, 2019USD ($) |
Pension Plan | |
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract] | |
2020 | $ 89.9 |
2021 | 82.4 |
2022 | 80.8 |
2023 | 78.5 |
2024 | 74.1 |
2025-2029 | 326.7 |
Postretirement Benefits Plan | |
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract] | |
2020 | 6.9 |
2021 | 6.6 |
2022 | 6.2 |
2023 | 5.9 |
2024 | 5.6 |
2025-2029 | 23.6 |
Expected Medicare Part D Subsidies [Abstract] | |
2020 | 0 |
2021 | 0 |
2022 | 0 |
2023 | 0 |
2024 | 0 |
2025-2029 | 0 |
Defined Benefit Plan, Net Projected Benefit Payments [Abstract] | |
2020 | 6.9 |
2021 | 6.6 |
2022 | 6.2 |
2023 | 5.9 |
2024 | 5.6 |
2025-2029 | $ 23.6 |
Commitments and Contingencies M
Commitments and Contingencies MEC Acquisition (Details) - Unregulated Operation [Member] - MEC Holdings LLC [Member] $ in Millions | 12 Months Ended |
Dec. 31, 2019USD ($)MW | |
Public Utilities, General Disclosures [Line Items] | |
Natural Gas Combine Cycle Facility Output | MW | 760 |
Property, Plant and Equipment, Additions | $ | $ 650 |
Commitments and Contingencies S
Commitments and Contingencies Sherco (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended |
Jan. 31, 2019 | Dec. 31, 2019 | |
NSP Minnesota [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Percentage of Fault | 48.00% | |
Customer refund of previously recovered purchased power costs | $ 20 | |
General Electric (GE) [Domain] | ||
Public Utilities, General Disclosures [Line Items] | ||
Percentage of Fault | 52.00% |
Commitments and Contingencies_2
Commitments and Contingencies MISO ROE Complaints (Details) - FERC Proceeding, MISO ROE Complaint [Member] - NSP Minnesota and NSP Wisconsin [Member] [Member] | 1 Months Ended | 12 Months Ended | 39 Months Ended | |
Feb. 28, 2015 | Nov. 30, 2013 | Dec. 31, 2016 | Dec. 31, 2019 | |
Public Utilities, General Disclosures [Line Items] | ||||
Public Utilities, Base Return On Equity Charged To Customers Through Transmission Formula Rates | 12.38% | 12.38% | ||
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, Recommended By Third Parties | 8.67% | 9.15% | ||
Public Utilities, ROE developed with new approach | 9.88% | |||
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, with RTO Adder, Approved | 10.38% | |||
Federal Energy Regulatory Commission (FERC) [Member] | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, Approved | 10.32% | |||
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, with RTO Adder, Approved | 10.82% |
Commitments and Contingencies,
Commitments and Contingencies, Legal Contingencies (Details) $ in Millions | 1 Months Ended | 12 Months Ended |
Jan. 31, 2019USD ($) | Dec. 31, 2019USD ($)MW | |
General Electric (GE) [Domain] | ||
Loss Contingencies [Line Items] | ||
Percentage of Fault | 52.00% | |
NSP Minnesota [Member] | ||
Loss Contingencies [Line Items] | ||
Percentage of Fault | 48.00% | |
Legal Contingencies [Abstract] | ||
Customer refund of previously recovered purchased power costs | $ 20 | |
Unregulated Operation [Member] | MEC Holdings LLC [Member] | ||
Loss Contingencies [Line Items] | ||
Natural Gas Combine Cycle Facility Output | MW | 760 | |
Property, Plant and Equipment, Additions | $ 650 |
Commitments and Contingencies_3
Commitments and Contingencies MGP Sites (Details) | Dec. 31, 2019Site |
Other MGP, Landfill, or Disposal Sites [Domain] | |
Loss Contingencies [Line Items] | |
Number of identified MGP, landfill, or disposal sites under current investigation and/or remediation | 7 |
Commitments and Contingencies E
Commitments and Contingencies Environmental Requirements - Water and Waste (Details) $ in Millions | Dec. 31, 2019USD ($)Plant |
Federal Coal Ash Regulation [Domain] | |
Loss Contingencies [Line Items] | |
Number of regulated ash units that will still be in operation by the end of 2019 | 3 |
Number of impoundments where closure plans will be expedited | 1 |
Estimated cost of closure of an impoundment | $ 2 |
Estimated cost of construction of a new impoundment | 8.6 |
Clean Water Act Effluent Limitations Guidelines [Domain] | |
Loss Contingencies [Line Items] | |
Liability for estimated cost to comply with regulation | $ 10 |
Federal Clean Water Act Section 316 (b) [Member] | |
Loss Contingencies [Line Items] | |
Minimum number of plants which could be required to make improvements to reduce entrainment | Plant | 6 |
Capital Addition Purchase Commitments [Member] | Federal Clean Water Act Section 316 (b) [Member] | |
Loss Contingencies [Line Items] | |
Liability for estimated cost to comply with regulation | $ 35.6 |
Liability for estimated cost to comply with impingement and entrainment regulation | $ 191.6 |
Commitments and Contingencies_4
Commitments and Contingencies, Asset Retirement Obligations (Details) - USD ($) $ in Millions | 12 Months Ended | ||||
Dec. 31, 2019 | Dec. 31, 2018 | ||||
Asset Retirement Obligations [Line Items] | |||||
Amounts Incurred | [1] | $ (10.3) | $ 0 | ||
Amounts Settled | 3.2 | [2] | 6.6 | [3] | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||||
Beginning balance | 2,177.9 | [4] | 2,083.9 | ||
Amounts Incurred | [1] | (10.3) | 0 | ||
Accretion | 108.4 | 103.2 | |||
Cash flow revisions | (13.1) | [5] | (2.6) | [6] | |
Ending balance | 2,280.3 | 2,177.9 | [4] | ||
Legally restricted assets, for purposes of funding future nuclear decommissioning | 2,400 | 2,100 | |||
Electric Plant Nuclear Production Decommissioning | |||||
Asset Retirement Obligations [Line Items] | |||||
Amounts Incurred | [1] | 0 | |||
Amounts Settled | 0 | [2] | 0 | [3] | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||||
Beginning balance | 1,968.3 | [4] | 1,873.6 | ||
Amounts Incurred | [1] | 0 | |||
Accretion | 99.5 | 94.7 | |||
Cash flow revisions | 0 | [5] | 0 | [6] | |
Ending balance | 2,067.8 | 1,968.3 | [4] | ||
Electric Plant Wind Production | |||||
Asset Retirement Obligations [Line Items] | |||||
Amounts Incurred | [1] | (10.3) | |||
Amounts Settled | 0 | [2] | 0 | [3] | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||||
Beginning balance | 104.9 | [4] | 94.1 | ||
Amounts Incurred | [1] | (10.3) | |||
Accretion | 4.8 | 4.3 | |||
Cash flow revisions | (6.9) | [5] | 6.5 | [6] | |
Ending balance | 113.1 | 104.9 | [4] | ||
Electric Plant Steam Production Ash Containment | |||||
Asset Retirement Obligations [Line Items] | |||||
Amounts Incurred | [2] | 0 | |||
Amounts Settled | 3.2 | [2] | 6.6 | [3] | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||||
Beginning balance | 49.2 | [4] | 64 | ||
Amounts Incurred | [2] | 0 | |||
Accretion | 1.8 | 2.1 | |||
Cash flow revisions | (1) | [5] | (10.3) | [6] | |
Ending balance | 46.8 | 49.2 | [4] | ||
Electric Plant Electric Distribution | |||||
Asset Retirement Obligations [Line Items] | |||||
Amounts Incurred | [1] | 0 | |||
Amounts Settled | 0 | [2] | 0 | [3] | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||||
Beginning balance | 14.5 | [4] | 5.8 | ||
Amounts Incurred | [1] | 0 | |||
Accretion | 0.6 | 0.2 | |||
Cash flow revisions | 0 | [5] | 8.5 | [6] | |
Ending balance | 15.1 | 14.5 | [4] | ||
Electric Plant Other | |||||
Asset Retirement Obligations [Line Items] | |||||
Amounts Incurred | [1] | 0 | |||
Amounts Settled | 0 | [2] | 0 | [3] | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||||
Beginning balance | 1.8 | [4] | 1.9 | ||
Amounts Incurred | [1] | 0 | |||
Accretion | 0 | 0 | |||
Cash flow revisions | (1.6) | [5] | (0.1) | [6] | |
Ending balance | 0.2 | 1.8 | [4] | ||
Natural Gas Plant Gas Transmission and Distribution | |||||
Asset Retirement Obligations [Line Items] | |||||
Amounts Incurred | [1] | 0 | |||
Amounts Settled | 0 | [2] | 0 | [3] | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||||
Beginning balance | 38.2 | [4] | 43.6 | ||
Amounts Incurred | [1] | 0 | |||
Accretion | 1.6 | 1.8 | |||
Cash flow revisions | (3.6) | [5] | (7.2) | [6] | |
Ending balance | 36.2 | 38.2 | [4] | ||
Natural Gas Plant Other | |||||
Asset Retirement Obligations [Line Items] | |||||
Amounts Incurred | [1] | 0 | |||
Amounts Settled | 0 | [2] | 0 | [3] | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||||
Beginning balance | 0.2 | [4] | 0.2 | ||
Amounts Incurred | [1] | 0 | |||
Accretion | 0.1 | 0 | |||
Cash flow revisions | 0 | [5] | 0 | [6] | |
Ending balance | 0.3 | 0.2 | [4] | ||
Common and Other Property Common Miscellaneous | |||||
Asset Retirement Obligations [Line Items] | |||||
Amounts Incurred | [1] | 0 | |||
Amounts Settled | 0 | [2] | 0 | [3] | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||||
Beginning balance | 0.8 | [4] | 0.7 | ||
Amounts Incurred | [1] | 0 | |||
Accretion | 0 | 0.1 | |||
Cash flow revisions | 0 | [5] | 0 | [6] | |
Ending balance | 0.8 | 0.8 | [4] | ||
Removal Costs [Member] | |||||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||||
Regulatory Liabilities | $ 520.3 | $ 484.6 | |||
[1] | Amounts incurred relate to the wind farms placed in service in 2019 (Lake Benton and Foxtail). | ||||
[2] | Amounts settled related to closure of certain ash containment facilities. | ||||
[3] | Amounts settled related to asbestos abatement projects and closure of certain ash containment facilities. | ||||
[4] | There were no ARO amounts incurred in 2018. | ||||
[5] | In 2019, AROs were revised for changes in timing and estimates of cash flows. Changes in wind AROs were driven by new dismantling studies. Changes in gas transmission and distribution AROs were primarily related to increased gas line mileage and number of services, which were more than offset by decreased inflation rates. Changes in steam and other production AROs primarily related to the cost estimates to remediate ponds at production facilities. | ||||
[6] | In 2018, AROs were revised for changes in timing and estimates of cash flows. Changes in gas transmission and distribution AROs were mainly related to increased gas line mileage and number of services, which were more than offset by increased discount rates. Changes in electric distribution AROs primarily related to increased labor costs. |
Commitments and Contingencies_5
Commitments and Contingencies, Removal Costs (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Removal Costs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities | $ 520.3 | $ 484.6 |
Commitments and Contingencies_6
Commitments and Contingencies, Nuclear Insurance (Details) - Nuclear Insurance $ in Millions | 12 Months Ended |
Dec. 31, 2019USD ($)PlantReactor | |
Nuclear Insurance [Abstract] | |
Nuclear insurance coverage secured for the Company's public liability exposure | $ 450 |
Nuclear insurance coverage exposure funded by the Secondary Financial Protection Program | 13,500 |
Maximum assessments per reactor per accident | $ 137.6 |
Number of owned and licensed reactors | Reactor | 3 |
Maximum funding requirement per reactor for any one year | $ 20.5 |
Number of nuclear plant sites operated by NSP-Minnesota | Plant | 2 |
Maximum assessments for business interruption insurance each calendar year | $ 12 |
Maximum assessment for property damage insurance NSP-Minnesota is subject to each calendar year | 35.1 |
Maximum | |
Nuclear Insurance [Abstract] | |
Loss Contingency, Estimate of Possible Loss | 13,900 |
Insurance coverage limits for NSP-Minnesota's nuclear plant sites | 2,700 |
Nuclear Electric Interruption Insurance Coverage Limits for Nuclear Plant Sites | $ 350 |
Commitments and Contingencies N
Commitments and Contingencies Nuclear Fuel Disposal (Details) | Dec. 31, 2019Canister |
Monticello [Member] | |
Loss Contingencies [Line Items] | |
Number Of Authorized Canisters Filled And Placed In Dry Cask Nuclear Storage Facility | 30 |
Prairie Island [Member] | |
Loss Contingencies [Line Items] | |
Number Of Authorized Canisters Filled And Placed In Dry Cask Nuclear Storage Facility | 44 |
Number Of Authorized Canisters In Dry Cask Nuclear Storage Facility | 64 |
Commitments and Contingencies R
Commitments and Contingencies Regulatory Plant Decommissioning Recovery (Details) $ in Millions | 12 Months Ended | |||
Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | ||
Public Utilities, General Disclosures [Line Items] | ||||
Percentage Of Total Obligation For Decommissioning Expected To Be Funded By External Funds | 100.00% | |||
Assumed annual escalation rate during operations and radiological portion of decommissioning | 4.36% | 4.36% | ||
Assumed annual escalation rate during independent fuel storage installation and site restoration portion of decommissioning | 3.36% | 3.36% | ||
Estimated Decommissioning Cost Obligation From Most Recently Approved Study | $ 3,012.3 | $ 3,012.3 | ||
Effect Of Escalating Costs To Current Year Dollars | 688.2 | 538.9 | ||
Estimated Decommissioning Cost Obligation In Current Dollars | 3,700.5 | 3,551.2 | ||
Effect Of Escalating Costs To Payment Date | 7,505 | 7,654.3 | ||
Estimated Future Decommissioning Costs Undiscounted | 11,205.5 | 11,205.5 | ||
Effect of discounting obligation (using average risk-free interest rate of 2.39% and 3.33% for 2019 and 2018, respectively) | 5,562.2 | 6,911.5 | ||
Discounted decommissioning cost obligation | 5,643.3 | 4,294 | ||
Decommissioning Fund Investments, Fair Value | 2,400 | 2,100 | ||
Discounted Decommissioning Obligation Compared To Assets Currently Held In Trust | 3,203.7 | 2,239.3 | ||
Differences in Discount Rate and Market Risk Premium | 2,295.2 | 1,446.4 | ||
Operating and Maintenance Costs Not Included for GAAP | 1,280.3 | 879.3 | ||
Asset Retirement Obligation | 2,280.3 | 2,177.9 | [1] | $ 2,083.9 |
Nuclear Decommissioning Expense | 20.4 | 20.4 | 20.4 | |
Approved annual accrual for decommissioning costs | $ 14 | 14 | 14 | |
Minimum [Member] | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Assumed after tax rate of return used to determine funding for external decommissioning trust fund | 5.23% | |||
Maximum [Member] | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Assumed after tax rate of return used to determine funding for external decommissioning trust fund | 6.30% | |||
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Decommissioning Fund Investments, Fair Value | $ 2,439.6 | 2,054.7 | ||
Nuclear Plant [Member] | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Asset Retirement Obligation | $ 2,067.8 | $ 1,968.3 | [1] | $ 1,873.6 |
Measurement Input, Risk Free Interest Rate [Member] | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Debt Instrument, Measurement Input | 0.0333 | 0.028 | ||
[1] | There were no ARO amounts incurred in 2018. |
Commitments and Contingencies_7
Commitments and Contingencies Nuclear Obligations Phantom (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | |
Public Utilities, General Disclosures [Line Items] | |||
Assumed annual escalation rate during operations and radiological portion of decommissioning | 4.36% | 4.36% | |
Assumed annual escalation rate during independent fuel storage installation and site restoration portion of decommissioning | 3.36% | 3.36% | |
Approved annual accrual for decommissioning costs | $ 14 | $ 14 | $ 14 |
Measurement Input, Risk Free Interest Rate [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Debt Instrument, Measurement Input | 0.0333 | 0.028 |
Commitments and Contingencies_8
Commitments and Contingencies, Leases (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | ||
Lessee, Lease, Description [Line Items] | ||||
Short-term Lease, Cost | $ 1.4 | $ 2 | $ 2.7 | |
Operating Lease, Weighted Average Discount Rate, Percent | 3.80% | |||
Operating Lease, Assets and Liabilities, Lessee [Abstract] | ||||
Operating Lease, Right-of-Use Asset, Gross | $ 628.5 | |||
Operating Lease, Right-of-Use Asset, Accumulated Depreciation | (64.7) | |||
Operating Lease, Right-of-Use Asset | 563.8 | 0 | ||
Lease, Cost [Abstract] | ||||
Operating Lease, Cost | [1] | 85 | 76.2 | 76.9 |
Lessee, Operating Lease, Liability, Payment, Due [Abstract] | ||||
2020 | 101.4 | |||
2021 | 102.9 | |||
2022 | 108.3 | |||
2023 | 104.9 | |||
2024 | 106.3 | |||
Thereafter | 164.7 | |||
Total minimum obligation | 688.5 | |||
Interest component of obligation | (82.9) | |||
Present value of minimum obligation | 605.6 | |||
Less current portion | (79.9) | 0 | ||
Operating Lease, Liability, Noncurrent | $ 525.7 | 0 | ||
Weighted-average remaining lease term in years | 6 years 8 months 12 days | |||
Operating Leases, Future Minimum Payments Due [Abstract] | ||||
2019 | 78.5 | |||
2021 | 75.5 | |||
2022 | 76.3 | |||
2020 | 74.5 | |||
2023 | 76.6 | |||
Thereafter | 179.5 | |||
Property, Plant and Equipment, Other Types [Member] | ||||
Operating Lease, Assets and Liabilities, Lessee [Abstract] | ||||
Operating Lease, Right-of-Use Asset, Gross | $ 72.2 | |||
Lease, Cost [Abstract] | ||||
Operating Lease, Cost | [2] | 9.1 | 13.7 | 14.2 |
Lessee, Operating Lease, Liability, Payment, Due [Abstract] | ||||
2020 | 7.9 | |||
2021 | 8 | |||
2022 | 11.9 | |||
2023 | 7 | |||
2024 | 6.8 | |||
Thereafter | 44.9 | |||
Total minimum obligation | 86.5 | |||
Interest component of obligation | (16.7) | |||
Present value of minimum obligation | 69.8 | |||
Office Space and Other Equipment | ||||
Operating Leases, Future Minimum Payments Due [Abstract] | ||||
2019 | [3],[4] | 65 | ||
2021 | [3],[4] | 67.1 | ||
2022 | [3],[4] | 68.2 | ||
2020 | [3],[4] | 66.1 | ||
2023 | [3],[4] | 69.3 | ||
Thereafter | [3],[4] | 143.5 | ||
Purchased Power Agreements | ||||
Operating Lease, Assets and Liabilities, Lessee [Abstract] | ||||
Operating Lease, Right-of-Use Asset, Gross | 556.3 | |||
Lease, Cost [Abstract] | ||||
Operating Lease, Cost | 75.9 | 62.5 | $ 62.7 | |
Lessee, Operating Lease, Liability, Payment, Due [Abstract] | ||||
2020 | [5],[6] | 93.5 | ||
2021 | [5],[6] | 94.9 | ||
2022 | [5],[6] | 96.4 | ||
2023 | [5],[6] | 97.9 | ||
2024 | [5],[6] | 99.5 | ||
Thereafter | [5],[6] | 119.8 | ||
Total minimum obligation | [5],[6] | 602 | ||
Interest component of obligation | [5],[6] | (66.2) | ||
Present value of minimum obligation | [5],[6] | $ 535.8 | ||
Operating Leases, Future Minimum Payments Due [Abstract] | ||||
2019 | 13.5 | |||
2021 | 8.4 | |||
2022 | 8.1 | |||
2020 | 8.4 | |||
2023 | 7.3 | |||
Thereafter | $ 36 | |||
[1] | PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income. Expense for other operating leases is included in O&M expense and electric fuel and purchased power. | |||
[2] | Includes short-term lease expense of $1.4 million , $2.0 million and $2.7 million for 2019, 2018 and 2017, respectively. | |||
[3] | Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs. | |||
[4] | PPA operating leases contractually expire at various dates through 2026. | |||
[5] | Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs. | |||
[6] | PPA operating leases contractually expire at various dates through 2026. |
Commitments and Contingencies_9
Commitments and Contingencies, Purchased Power Agreements (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Capacity | |||
Purchased Power Agreements (PPAs) [Abstract] | |||
Purchased power expense | $ 53.8 | $ 52.7 | $ 84.1 |
Estimated Future Payments Under PPAs [Abstract] | |||
2020 | 54.5 | ||
2021 | 62.2 | ||
2022 | 61.3 | ||
2023 | 62.8 | ||
2024 | 64.5 | ||
Thereafter | 45.4 | ||
Total | 350.7 | ||
Energy | |||
Purchased Power Agreements (PPAs) [Abstract] | |||
Purchased power expense | 102.4 | $ 104.7 | $ 96.7 |
Estimated Future Payments Under PPAs [Abstract] | |||
2020 | 109.4 | ||
2021 | 157.3 | ||
2022 | 172.9 | ||
2023 | 176.9 | ||
2024 | 181.8 | ||
Thereafter | 146.3 | ||
Total | $ 944.6 |
Commitments and Contingencie_10
Commitments and Contingencies, Fuel Contracts (Details) $ in Millions | Dec. 31, 2019USD ($) |
Coal | |
Fuel Contracts [Abstract] | |
2020 | $ 171.3 |
2021 | 85.2 |
2022 | 51.9 |
2023 | 35.1 |
2024 | 0.9 |
Thereafter | 2.6 |
Total | 347 |
Nuclear Fuel | |
Fuel Contracts [Abstract] | |
2020 | 53.8 |
2021 | 102.5 |
2022 | 85.3 |
2023 | 103 |
2024 | 74.5 |
Thereafter | 275.1 |
Total | 694.2 |
Natural Gas Supply | |
Fuel Contracts [Abstract] | |
2020 | 36.8 |
2021 | 1.4 |
2022 | 0.8 |
2023 | 0 |
2024 | 0 |
Thereafter | 0 |
Total | 39 |
Natural Gas Storage and Transportation | |
Fuel Contracts [Abstract] | |
2020 | 133 |
2021 | 129.8 |
2022 | 124.3 |
2023 | 107.8 |
2024 | 101.1 |
Thereafter | 273.6 |
Total | $ 869.6 |
Commitments and Contingencie_11
Commitments and Contingencies, Variable Interest Entities (Details) - MW | Dec. 31, 2019 | Dec. 31, 2018 |
Independent Power Producing Entities | ||
Purchased Power Agreements [Abstract] | ||
Generating capacity (in MW) | 1,347 | 1,002 |
Other Comprehensive Income (Det
Other Comprehensive Income (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Accumulated other comprehensive (loss) income at beginning of period | $ 5,573.1 | |
Accumulated other comprehensive (loss) income at end of period | 6,081.8 | $ 5,573.1 |
Gains and Losses on Cash Flow Hedges | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Accumulated other comprehensive (loss) income at beginning of period | (20.2) | (20.9) |
Other comprehensive income (loss) before reclassifications | 0 | 0 |
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | 0 | 0 |
Net current period other comprehensive income (loss) | 0.8 | 0.7 |
Accumulated other comprehensive (loss) income at end of period | (19.4) | (20.2) |
Gains and Losses on Cash Flow Hedges | Interest Rate Swap [Member] | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | 0.8 | 0.7 |
Unrealized Gains and Losses on Marketable Securities | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Accumulated other comprehensive (loss) income at beginning of period | 0 | 0.1 |
Other comprehensive income (loss) before reclassifications | (0.1) | |
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | 0 | |
Net current period other comprehensive income (loss) | (0.1) | |
Accumulated other comprehensive (loss) income at end of period | 0 | |
Unrealized Gains and Losses on Marketable Securities | Interest Rate Swap [Member] | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | 0 | |
Defined Benefit Pension and Postretirement Items | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Accumulated other comprehensive (loss) income at beginning of period | (2.9) | (3.7) |
Other comprehensive income (loss) before reclassifications | (0.4) | 0.6 |
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | 0.2 | 0.2 |
Net current period other comprehensive income (loss) | (0.2) | 0.8 |
Accumulated other comprehensive (loss) income at end of period | (3.1) | (2.9) |
Defined Benefit Pension and Postretirement Items | Interest Rate Swap [Member] | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | 0 | 0 |
Total | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Accumulated other comprehensive (loss) income at beginning of period | (23.1) | (24.5) |
Other comprehensive income (loss) before reclassifications | (0.4) | 0.5 |
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | 0.2 | 0.2 |
Net current period other comprehensive income (loss) | 0.6 | 1.4 |
Accumulated other comprehensive (loss) income at end of period | (22.5) | (23.1) |
Total | Interest Rate Swap [Member] | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | $ 0.8 | $ 0.7 |
Other Comprehensive Income Phan
Other Comprehensive Income Phantom (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Net fair value (decrease) increase, tax | $ 0 | $ 0 | $ 0 |
Income taxes | 47.4 | 27.2 | $ 199.7 |
Amounts Reclassified from Accumulated Other Comprehensive Loss | Gains and Losses on Cash Flow Hedges | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Net fair value (decrease) increase, tax | 0 | 0 | |
Income taxes | 0.3 | 0.3 | |
Reclassification from AOCI, Current Period, Tax | 0 | 0 | |
Amounts Reclassified from Accumulated Other Comprehensive Loss | Unrealized Gains and Losses on Marketable Securities | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Net fair value (decrease) increase, tax | 0 | ||
Income taxes | 0 | ||
Reclassification from AOCI, Current Period, Tax | 0 | ||
Amounts Reclassified from Accumulated Other Comprehensive Loss | Defined Benefit Pension and Postretirement Items | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Net fair value (decrease) increase, tax | (0.1) | 0.3 | |
Income taxes | 0 | 0 | |
Reclassification from AOCI, Current Period, Tax | $ 0.1 | $ 0.1 |
Segments and Related Informat_3
Segments and Related Information (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | ||
Segment Reporting Information [Line Items] | ||||||||||||
Regulated and Unregulated Operating Revenue | $ 1,231.7 | $ 1,344.6 | $ 1,185 | $ 1,350.5 | $ 1,271.6 | $ 1,351.8 | $ 1,187.7 | $ 1,310.8 | $ 5,111.8 | $ 5,121.9 | $ 5,102 | |
Depreciation and amortization | 791.3 | 741.6 | 700.6 | |||||||||
Total interest charges and financing costs | 220.9 | 214.3 | 213.3 | |||||||||
Income tax expense (benefit) | 47.4 | 27.2 | 199.7 | |||||||||
Net income (loss) | $ 124.9 | $ 208.6 | $ 95.9 | $ 113.2 | $ 87 | $ 201.2 | $ 92.4 | $ 111.7 | 542.6 | 492.3 | 490.1 | |
Electricity, US Regulated | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Revenues Including Intersegment Revenues | 4,507.2 | 4,508.8 | 4,542.3 | |||||||||
Depreciation and amortization | 742.1 | 697.8 | 661.3 | |||||||||
Total interest charges and financing costs | 205.3 | 199.5 | 199.8 | |||||||||
Income tax expense (benefit) | 36.1 | 16.4 | 179.9 | |||||||||
Net income (loss) | 491 | 450.4 | 462.5 | |||||||||
Natural Gas, US Regulated | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Revenues Including Intersegment Revenues | 572.1 | 583.6 | 532.4 | |||||||||
Depreciation and amortization | 48.8 | 43.3 | 38.7 | |||||||||
Total interest charges and financing costs | 15.6 | 14.8 | 13.5 | |||||||||
Income tax expense (benefit) | 12.4 | 10.2 | 10 | |||||||||
Net income (loss) | 40 | 34.2 | 28.4 | |||||||||
All Other | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Depreciation and amortization | 0.4 | 0.5 | 0.6 | |||||||||
Total interest charges and financing costs | 0 | 0 | 0 | |||||||||
Income tax expense (benefit) | (1.1) | 0.6 | 9.8 | |||||||||
Net income (loss) | 11.6 | 7.7 | (0.8) | |||||||||
Operating Segments | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Regulated and Unregulated Operating Revenue | [1] | 5,113.2 | 5,123.2 | 5,103.1 | ||||||||
Operating Segments | Electricity, US Regulated | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Operating revenue, Regulated Electric | [1] | 4,506.6 | 4,508 | 4,541.7 | ||||||||
Operating Segments | Natural Gas, US Regulated | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Operating revenue, Regulated Natural Gas | [1] | 571.3 | 583.1 | 531.9 | ||||||||
Operating Segments | All Other | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Unregulated Operating Revenue | [1] | 33.9 | 30.8 | 28.4 | ||||||||
Intersegment Eliminations | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Regulated and Unregulated Operating Revenue | (1.4) | (1.3) | (1.1) | |||||||||
Intersegment Eliminations | Electricity, US Regulated | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Operating revenue, Regulated Electric | 0.6 | 0.8 | 0.6 | |||||||||
Intersegment Eliminations | Natural Gas, US Regulated | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Operating revenue, Regulated Natural Gas | $ 0.8 | $ 0.5 | $ 0.5 | |||||||||
[1] | Operating revenues include $457.4 million , $473.7 million , and $490.2 million of intercompany revenue for the years ended Dec. 31, 2019 , 2018 and 2017 , respectively. See Note 13 for further information. |
Related Party Transactions (Det
Related Party Transactions (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Operating expenses | |||
Interest expense | $ 0.7 | $ 0.3 | $ 0 |
Accounts Receivable and Payable with Affiliates [Abstract] | |||
Accounts receivable | 43.8 | 11 | |
Accounts payable | 76 | 109.7 | |
NSP-Wisconsin | |||
Accounts Receivable and Payable with Affiliates [Abstract] | |||
Accounts receivable | 7.9 | 11 | |
Accounts payable | 0 | 0 | |
PSCo | |||
Accounts Receivable and Payable with Affiliates [Abstract] | |||
Accounts receivable | 0 | 0 | |
Accounts payable | 18.8 | 17.9 | |
SPS | |||
Accounts Receivable and Payable with Affiliates [Abstract] | |||
Accounts receivable | 0 | 0 | |
Accounts payable | 4.2 | 4.7 | |
Other subsidiaries of Xcel Energy Inc. | |||
Accounts Receivable and Payable with Affiliates [Abstract] | |||
Accounts receivable | 35.9 | 0 | |
Accounts payable | 53 | 87.1 | |
Purchased Power | |||
Operating expenses | |||
Costs and Expenses, Related Party | 60.5 | 61.1 | 66.8 |
Transmission Expense | |||
Operating expenses | |||
Costs and Expenses, Related Party | 116.2 | 96.8 | 110.5 |
Other Expense | |||
Operating expenses | |||
Costs and Expenses, Related Party | 533.2 | 534.8 | 539.4 |
Electricity, US Regulated | |||
Operating revenues | |||
Operating Revenue from Related Parties | 457.4 | 473.7 | 490.2 |
Natural Gas, US Regulated | |||
Operating revenues | |||
Operating Revenue from Related Parties | $ 0.5 | $ 0 | $ 0 |
Summarized Quarterly Financia_3
Summarized Quarterly Financial Data (Unaudited) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Regulated and Unregulated Operating Revenue | $ 1,231.7 | $ 1,344.6 | $ 1,185 | $ 1,350.5 | $ 1,271.6 | $ 1,351.8 | $ 1,187.7 | $ 1,310.8 | $ 5,111.8 | $ 5,121.9 | $ 5,102 |
Operating Income | 181.3 | 291 | 147.3 | 167.3 | 135.5 | 259.5 | 150.1 | 171.4 | 786.9 | 716.5 | 882.7 |
Net income | $ 124.9 | $ 208.6 | $ 95.9 | $ 113.2 | $ 87 | $ 201.2 | $ 92.4 | $ 111.7 | $ 542.6 | $ 492.3 | $ 490.1 |
Schedule II, Valuation and Qu_2
Schedule II, Valuation and Qualifying Accounts (Details) - Allowance for Bad Debts - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward] | |||
Balance at Jan. 1 | $ 23.5 | $ 21.3 | $ 20 |
Charged to costs and expenses | 13 | 16.2 | 15.7 |
Charged to other accounts | 6.5 | 4.1 | 3.8 |
Deductions from reserves | (20) | (18.1) | (18.2) |
Balance at Dec. 31 | $ 23 | $ 23.5 | $ 21.3 |