Cover Page
Cover Page - USD ($) | 12 Months Ended | ||
Dec. 31, 2020 | Jan. 31, 2021 | Jun. 30, 2020 | |
Entity Information [Line Items] | |||
Document Type | 10-K | ||
Document Annual Report | true | ||
Document Period End Date | Dec. 31, 2020 | ||
Document Transition Report | false | ||
Entity File Number | 001-01245 | ||
Entity Registrant Name | WISCONSIN ELECTRIC POWER COMPANY | ||
Entity Tax Identification Number | 39-0476280 | ||
Entity Incorporation, State or Country Code | WI | ||
Entity Address, Address Line One | 231 West Michigan Street | ||
Entity Address, Address Line Two | P.O. Box 2046 | ||
Entity Address, City or Town | Milwaukee | ||
Entity Address, State or Province | WI | ||
Entity Address, Postal Zip Code | 53201 | ||
City Area Code | 414 | ||
Local Phone Number | 221-2345 | ||
Entity Well-known Seasoned Issuer | No | ||
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 | ||
ICFR Auditor Attestation Flag | false | ||
Entity Shell Company | false | ||
Entity Public Float | $ 0 | ||
Entity Common Stock, Shares Outstanding | 33,289,327 | ||
Documents Incorporated by Reference | Portions of Wisconsin Electric Power Company's Definitive Information Statement on Schedule 14C for its Annual Meeting of Shareholders, to be held on April 29, 2021, are incorporated by reference into Part III hereof. | ||
Entity Central Index Key | 0000107815 | ||
Current Fiscal Year End Date | --12-31 | ||
Document Fiscal Year Focus | 2020 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
Serial preferred stock, 3.60% Series | |||
Entity Information [Line Items] | |||
Title of 12(g) Security | Serial Preferred Stock, 3.60% Series, $100 Par Value | ||
No Trading Symbol Flag | true | ||
Six Per Cent. Preferred Stock | |||
Entity Information [Line Items] | |||
Title of 12(g) Security | Six Per Cent. Preferred Stock, $100 Par Value | ||
No Trading Symbol Flag | true |
Consolidated Income Statements
Consolidated Income Statements - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Income Statement [Abstract] | |||
Operating revenues | $ 3,367 | $ 3,496.7 | $ 3,625 |
Operating expenses | |||
Cost of sales | 1,074.7 | 1,190.7 | 1,262.1 |
Other operation and maintenance | 902 | 1,053.1 | 1,502.4 |
Depreciation and amortization | 426.9 | 384.4 | 348.1 |
Property and revenue taxes | 102.9 | 108.3 | 109.9 |
Total operating expenses | 2,506.5 | 2,736.5 | 3,222.5 |
Operating income | 860.5 | 760.2 | 402.5 |
Other income, net | 18.5 | 22.7 | 20.2 |
Interest expense | 467.5 | 477.4 | 120.1 |
Other expense | (449) | (454.7) | (99.9) |
Income before income taxes | 411.5 | 305.5 | 302.6 |
Income tax expense (benefit) | 44.7 | (57.8) | (56.9) |
Net income | 366.8 | 363.3 | 359.5 |
Preferred stock dividend requirements | 1.2 | 1.2 | 1.2 |
Net income attributed to common shareholder | $ 365.6 | $ 362.1 | $ 358.3 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Current Assets | ||
Cash and cash equivalents | $ 7.2 | $ 19.1 |
Accounts receivable and unbilled revenues, net of reserves of $59.3 and $38.1 respectively | 466.1 | 434.6 |
Accounts receivable from related parties | 67.9 | 86.5 |
Materials, supplies, and inventories | 219.5 | 229.8 |
Prepaid taxes | 98.5 | 104.4 |
Other | 36.4 | 33.6 |
Total current assets | 895.6 | 908 |
Long-term assets | ||
Property, plant, and equipment, net of accumulated depreciation and amortization of $4,849.2 and $4,564.0, respectively | 9,789.9 | 9,586.7 |
Regulatory assets | 2,803.3 | 2,755.2 |
Other | 116.4 | 110.9 |
Long-term assets | 12,709.6 | 12,452.8 |
Total Assets | 13,605.2 | 13,360.8 |
Current Liabilities | ||
Short-term debt | 292 | 115.5 |
Current portion of long-term debt | 300 | 0 |
Current portion of finance lease obligations | 66.8 | 57.8 |
Accounts payable | 261.2 | 267.6 |
Accounts payable to related parties | 172 | 184.5 |
Accrued payroll and benefits | 43.3 | 51.3 |
Accrued taxes | 25 | 12.3 |
Other | 97.1 | 105.6 |
Current liabilities | 1,257.4 | 794.6 |
Long-term liabilities | ||
Long-term debt | 2,461.2 | 2,759.2 |
Finance lease obligations | 2,774.4 | 2,783.1 |
Deferred income taxes | 1,357.2 | 1,347.4 |
Regulatory liabilities | 1,703.7 | 1,744.2 |
Pension and OPEB obligations | 85.9 | 59.8 |
Other | 272.8 | 281 |
Long-term liabilities | 8,655.2 | 8,974.7 |
Commitments and contingencies (Note 19) | ||
Common shareholder's equity | ||
Common stock – $10 par value; 65,000,000 shares authorized; 33,289,327 shares outstanding | 332.9 | 332.9 |
Additional paid in capital | 1,060.1 | 929.5 |
Retained earnings | 2,269.2 | 2,298.7 |
Total Common Shareholders' Equity | 3,662.2 | 3,561.1 |
Preferred stock | 30.4 | 30.4 |
Total liabilities and equity | $ 13,605.2 | $ 13,360.8 |
Consolidated Balance Sheets Par
Consolidated Balance Sheets Parenthetical (Parentheticals) - USD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Statement of Financial Position [Abstract] | ||
Accounts receivable and unbilled revenues, reserves | $ 59.3 | $ 38.1 |
Property, plant, and equipment, accumulated depreciation and amortization | $ 4,849.2 | $ 4,564 |
Common stock, par value | $ 10 | $ 10 |
Common stock, shares authorized | 65,000,000 | 65,000,000 |
Common stock, shares outstanding | 33,289,327 | 33,289,327 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Statement of Cash Flows [Abstract] | |||
Net income | $ 366.8 | $ 363.3 | $ 359.5 |
Reconciliation to cash provided by operating activities | |||
Depreciation and amortization | 426.9 | 384.4 | 348.1 |
Deferred income taxes and ITCs, net | (63.7) | (131.2) | (0.7) |
Contributions and payments related to pension and OPEB plans | (3.9) | (5.5) | (6.3) |
Payments for liabilities transferred to affiliates | 0 | (4.5) | (10.1) |
Change In | |||
Accounts receivable and unbilled revenues | (8.7) | 60.3 | 34.8 |
Materials, supplies, and inventories | 10.3 | 11.6 | 9.3 |
Prepaid taxes | 5.9 | 34 | (28.3) |
Other current assets | 1.4 | (5.2) | 13.5 |
Accounts payable | (25.9) | (22.4) | 13.2 |
Accrued taxes | 12.7 | (1.3) | (41.1) |
Other current liabilities | (11.6) | (1.1) | (5.2) |
Other, net | 56.9 | 172 | 275.5 |
Net cash provided by operating activities | 767.1 | 854.4 | 962.2 |
Investing Activities | |||
Capital expenditures | (663.6) | (590.6) | (603.2) |
Payments for assets transferred from affiliates | 0 | 0 | (59.8) |
Insurance proceeds received for property damage | 22.2 | 0 | 0 |
Other, net | 10.6 | 13.7 | 22.6 |
Net cash used in investing activities | (630.8) | (576.9) | (640.4) |
Financing Activities | |||
Change in short-term debt | 176.5 | (19.4) | (76) |
Issuance of long-term debt | 0 | 300 | 300 |
Retirement of long-term debt | 0 | (250) | (250) |
Payments for finance lease obligations | (58.3) | (50.5) | 0 |
Equity contribution from parent | 130 | 105 | 28 |
Payment of dividends to parent | (395) | (360) | (310) |
Other, net | (1.4) | (3.7) | (5.9) |
Net cash used in financing activities | (148.2) | (278.6) | (313.9) |
Net change in cash and cash equivalents | (11.9) | (1.1) | 7.9 |
Cash and cash equivalents at beginning of year | 19.1 | 20.2 | 12.3 |
Cash and cash equivalents at end of year | $ 7.2 | $ 19.1 | $ 20.2 |
Consolidated Statements of Equi
Consolidated Statements of Equity - USD ($) $ in Millions | Total | Total common shareholder's equity | Common stock | Additional paid-in capital | Retained earnings | Preferred stock | UMERC transfer | UMERC transferTotal common shareholder's equity | UMERC transferCommon stock | UMERC transferAdditional paid-in capital | UMERC transferRetained earnings | UMERC transferPreferred stock |
Balance at Dec. 31, 2017 | $ 3,414.3 | $ 3,383.9 | $ 332.9 | $ 802.7 | $ 2,248.3 | $ 30.4 | ||||||
Equity | ||||||||||||
Net income attributed to common shareholder | 358.3 | 358.3 | 0 | 0 | 358.3 | 0 | ||||||
Payment of dividends to parent | (310) | (310) | 0 | 0 | (310) | 0 | ||||||
Equity contribution from parent | 28 | 28 | 0 | 28 | 0 | 0 | ||||||
Stock-based compensation and other | 0.6 | 0.6 | 0 | 0.6 | 0 | 0 | ||||||
Balance at Dec. 31, 2018 | 3,491.2 | 3,460.8 | 332.9 | 831.3 | 2,296.6 | 30.4 | ||||||
Equity | ||||||||||||
Net income attributed to common shareholder | 362.1 | 362.1 | 0 | 0 | 362.1 | 0 | ||||||
Payment of dividends to parent | (360) | (360) | 0 | 0 | (360) | 0 | ||||||
Equity contribution from parent | 105 | 105 | 0 | 105 | 0 | 0 | ||||||
Transfer of net assets to UMERC | $ (7.3) | $ (7.3) | $ 0 | $ (7.3) | $ 0 | $ 0 | ||||||
Stock-based compensation and other | 0.5 | 0.5 | 0 | 0.5 | 0 | 0 | ||||||
Balance at Dec. 31, 2019 | 3,591.5 | 3,561.1 | 332.9 | 929.5 | 2,298.7 | 30.4 | ||||||
Equity | ||||||||||||
Net income attributed to common shareholder | 365.6 | 365.6 | 0 | 0 | 365.6 | 0 | ||||||
Payment of dividends to parent | (395) | (395) | 0 | 0 | (395) | 0 | ||||||
Equity contribution from parent | 130 | 130 | 0 | 130 | 0 | 0 | ||||||
Stock-based compensation and other | 0.5 | 0.5 | 0 | 0.6 | (0.1) | 0 | ||||||
Balance at Dec. 31, 2020 | $ 3,692.6 | $ 3,662.2 | $ 332.9 | $ 1,060.1 | $ 2,269.2 | $ 30.4 |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2020 | |
Accounting Policies [Abstract] | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (a) Nature of Operations —We are an electric, natural gas, and steam utility company that serves electric and natural gas customers in Wisconsin, and steam customers in metropolitan Milwaukee, Wisconsin. Prior to April 1, 2019, we also provided electric service to Tilden, who owns an iron ore mine in the Upper Peninsula of Michigan. This customer was transferred to UMERC on April 1, 2019 after UMERC's new natural gas-fired generation in the Upper Peninsula of Michigan began commercial operation. WEC Energy Group owns all of our outstanding common stock. As used in these notes, the term "financial statements" refers to the consolidated financial statements. This includes the income statements, balance sheets, statements of cash flows, and statements of equity, unless otherwise noted. (b) Basis of Presentation —We prepare our financial statements in conformity with GAAP. We make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates. (c) Cash and Cash Equivalents —Cash and cash equivalents include marketable debt securities with an original maturity of three months or less. (d) Operating Revenues —The following discussion includes our significant accounting policies related to operating revenues. For additional required disclosures on disaggregation of operating revenues, see Note 3, Operating Revenues. Revenues from Contracts with Customers Electric Utility Operating Revenues Electricity sales to residential and commercial and industrial customers are generally accomplished through requirements contracts, which provide for the delivery of as much electricity as the customer needs. These contracts represent discrete deliveries of electricity and consist of one distinct performance obligation satisfied over time, as the electricity is delivered and consumed by the customer simultaneously. For our residential and commercial and industrial customers, our performance obligation is bundled to consist of both the sale and the delivery of the electric commodity. The transaction price of the performance obligations for residential and commercial and industrial customers is valued using the rates, charges, terms, and conditions of service included in our tariffs, which have been approved by the PSCW. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on the quantity of electricity delivered each month. Our retail electric rates in Wisconsin include base amounts for fuel and purchased power costs, which also impact our revenues. The electric fuel rules set by the PSCW allow us to defer, for subsequent rate recovery or refund, under- or over-collections of actual fuel and purchased power costs beyond a 2% price variance from the costs included in the rates charged to customers. We monitor the deferral of under-collected costs to ensure that it does not cause us to earn a greater ROE than authorized by the PSCW. In addition, our residential tariffs include a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. See Note 21, Regulatory Environment, for more information on how COVID-19 has affected our cost recovery mechanism. Wholesale customers who resell power can choose to either bundle capacity and electricity services together under one contract with a supplier or purchase capacity and electricity separately from multiple suppliers. Furthermore, wholesale customers can choose to have us provide generation to match the customer's load, similar to requirements contracts, or they can purchase specified quantities of electricity and capacity. Contracts with wholesale customers that include capacity bundled with the delivery of electricity contain two performance obligations, as capacity and electricity are often transacted separately in the marketplace at the wholesale level. When recognizing revenue associated with these contracts, the transaction price is allocated to each performance obligation based on its relative standalone selling price. Revenue is recognized as control of each individual component is transferred to the customer. Electricity is the primary product sold by our electric operations and represents a single performance obligation satisfied over time through discrete deliveries to a customer. Revenue from electricity sales is generally recognized as units are produced and delivered to the customer within the production month. Capacity represents the reservation of an electric generating facility and conveys the ability to call on a plant to produce electricity when needed by the customer. The nature of our performance obligation as it relates to capacity is to stand ready to deliver power. This represents a single performance obligation transferred over time, which generally represents a monthly obligation. Accordingly, capacity revenue is recognized on a monthly basis. The transaction price of the performance obligations for wholesale customers is valued using the rates, charges, terms, and conditions of service, which have been approved by the FERC. These wholesale rates include recovery of fuel and purchased power costs from customers on a one-for-one basis. For the majority of our wholesale customers, the price billed for energy and capacity is a formula-based rate. Formula-based rates initially set a customer's current year rates based on the previous year’s expenses. This is a predetermined formula derived from the utility’s costs and a reasonable rate of return. Because these rates are eventually trued up to reflect actual, current-year costs, they represent a form of variable consideration in certain circumstances. The variable consideration is estimated and recognized over time as wholesale customers receive and consume the capacity and electricity services. We are an active participant in the MISO Energy Markets, where we bid our generation into the Day Ahead and Real Time markets and procure electricity for our retail and wholesale customers at prices determined by the MISO Energy Markets. Purchase and sale transactions are recorded using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded as purchased power in cost of sales and net sales in a single hour are recorded as resale revenues on our income statements. For resale revenues, our performance obligation is created only when electricity is sold into the MISO Energy Markets. For all of our customers, consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days. Natural Gas Utility Operating Revenues We recognize natural gas utility operating revenues under requirements contracts with residential, commercial and industrial, and transportation customers served under our tariffs. Tariffs provide our customers with the standard terms and conditions, including rates, related to the services offered. Requirements contracts provide for the delivery of as much natural gas as the customer needs. These requirements contracts represent discrete deliveries of natural gas and constitute a single performance obligation satisfied over time. Our performance obligation is both created and satisfied with the transfer of control of natural gas upon delivery to the customer. For most of our customers, natural gas is delivered and consumed by the customer simultaneously. A performance obligation can be bundled to consist of both the sale and the delivery of the natural gas commodity. In certain of our service territories, customers can purchase the commodity from a third party. In this case, the performance obligation only includes the delivery of the natural gas to the customer. The transaction price of the performance obligations for our natural gas customers is valued using rates, charges, terms, and conditions of service included in our tariffs, which have been approved by the PSCW. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on natural gas delivered each month. Our tariffs include various rate mechanisms that allow us to recover or refund changes in prudently incurred costs from rate case-approved amounts. Our rates include a one-for-one recovery mechanism for natural gas commodity costs. We defer any difference between actual natural gas costs incurred and costs recovered through rates as a current asset or liability. The deferred balance is returned to or recovered from customers at intervals throughout the year. In addition, our residential tariffs include a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. See Note 21, Regulatory Environment, for more information on how COVID-19 has affected our cost recovery mechanism. Consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days. Other Operating Revenues Alternative Revenues Alternative revenues are created from programs authorized by regulators that allow us to record additional revenues by adjusting rates in the future, usually as a surcharge applied to future billings, in response to past activities or completed events. We record alternative revenues when the regulator-specified conditions for recognition have been met. We reverse these alternative revenues as the customer is billed, at which time this revenue is presented as revenues from contracts with customers. Our only alternative revenue program relates to the wholesale electric service that we provide to customers under market-based rates and FERC formula rates. The customer is charged a base rate each year based upon a formula using prior year actual costs and customer demand. A true-up is calculated based on the difference between the amount billed to customers for the demand component of their rates and what the actual cost of service was for the year. The true-up can result in an amount that we will recover from or refund to the customer. We consider the true-up portion of the wholesale electric revenues to be alternative revenues. (e) Credit Losses —The following discussion includes our significant accounting policies related to credit losses. For additional required disclosures on credit losses, see Note 4, Credit Losses. Effective January 1, 2020, we adopted FASB ASU 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, using the modified retrospective transition method. This ASU amends the impairment model to utilize an expected loss methodology in place of the incurred loss methodology for financial instruments, including trade receivables. The amendment requires entities to consider a broader range of information to estimate expected credit losses, which may result in earlier recognition of loss. The cumulative effect of adopting this standard was not significant to our financial statements. Our exposure to credit losses is related to our accounts receivable and unbilled revenue balances, which are generated from the sale of electricity and natural gas by our regulated utility operations. Our regulated utility operations are included in our utility segment. No accounts receivable and unbilled revenue balances were reported in the other segment at December 31, 2020. We evaluate the collectability of our accounts receivable and unbilled revenue balances considering a combination of factors. For some of our larger customers and also in circumstances where we become aware of a specific customer's inability to meet its financial obligations to us, we record a specific allowance for credit losses against amounts due in order to reduce the net recognized receivable to the amount we reasonably believe will be collected. For all other customers, we use the accounts receivable aging method to calculate an allowance for credit losses. Using this method, we classify accounts receivable into different aging buckets and calculate a reserve percentage for each aging bucket based upon historical loss rates. The calculated reserve percentages are updated on at least an annual basis, in order to ensure recent macroeconomic, political, and regulatory trends are captured in the calculation, to the extent possible. Risks identified that we do not believe are reflected in the calculated reserve percentages, are assessed on a quarterly basis to determine whether further adjustments are required. We monitor our ongoing credit exposure through active review of counterparty accounts receivable balances against contract terms and due dates. Our activities include timely account reconciliation, dispute resolution and payment confirmation. To the extent possible, we work with customers with past due balances to negotiate payment plans, but will disconnect customers for non-payment as allowed by the PSCW if necessary, and employ collection agencies and legal counsel to pursue recovery of defaulted receivables. For our larger customers, detailed credit review procedures may be performed in advance of any sales being made. We sometimes require letters of credit, parental guarantees, prepayments or other forms of credit assurance from our larger customers to mitigate credit risk. See Note 21, Regulatory Environment, for information on certain regulatory actions that were and/or are being taken for the purpose of ensuring that essential utility services are available to our customers during the COVID-19 pandemic. (f) Materials, Supplies, and Inventories —Our inventory as of December 31 consisted of: (in millions) 2020 2019 Materials and supplies $ 136.5 $ 148.3 Fossil fuel 57.1 51.1 Natural gas in storage 25.9 30.4 Total $ 219.5 $ 229.8 Substantially all materials and supplies, fossil fuel, and natural gas in storage inventories are recorded using the weighted-average cost method of accounting. (g) Regulatory Assets and Liabilities —The economic effects of regulation can result in regulated companies recording costs and revenues that are allowed in the rate-making process in a period different from the period they would have been recognized by a nonregulated company. When this occurs, regulatory assets and regulatory liabilities are recorded on the balance sheet. Regulatory assets represent deferred costs probable of recovery from customers that would have otherwise been charged to expense. Regulatory liabilities represent amounts that are expected to be refunded to customers in future rates or future costs already collected from customers in rates. The recovery or refund of regulatory assets and liabilities is based on specific periods determined by our regulators or occurs over the normal operating period of the related assets and liabilities. If a previously recorded regulatory asset is no longer probable of recovery, the regulatory asset is reduced to the amount considered probable of recovery, and the reduction is charged to expense in the current period. See Note 5, Regulatory Assets and Liabilities, for more information. (h) Property, Plant, and Equipment —We record property, plant, and equipment at cost. Cost includes material, labor, overhead, and both debt and equity components of AFUDC. Additions to and significant replacements of property are charged to property, plant, and equipment at cost; minor items are charged to other operation and maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired. We record straight-line depreciation expense over the estimated useful life of utility property using depreciation rates approved by the PSCW that include estimates for salvage value and removal costs. Annual utility composite depreciation rates were 3.19%, 3.11%, and 3.18% in 2020, 2019, and 2018, respectively. We capitalize certain costs related to software developed or obtained for internal use and record these costs to amortization expense over the estimated useful life of the related software, which ranges from 5 to 15 years. If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statement. Third parties reimburse us for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs are recorded as a reduction to property, plant, and equipment. (i) Allowance for Funds Used During Construction —AFUDC is included in utility plant accounts and represents the cost of borrowed funds (AFUDC – Debt) used during plant construction, and a return on shareholders' capital (AFUDC – Equity) used for construction purposes. AFUDC – Debt is recorded as a reduction of interest expense, and AFUDC – Equity is recorded in other income, net. Approximately 50% of our retail jurisdictional CWIP expenditures are subject to the AFUDC calculation. Our average AFUDC retail rates were 8.68% for 2020, and 8.45% for 2019 and 2018. Our average AFUDC wholesale rates were 5.39%, 5.11%, and 3.63% for 2020, 2019, and 2018, respectively. We recorded the following AFUDC for the years ended December 31: (in millions) 2020 2019 2018 AFUDC – Debt $ 2.6 $ 1.5 $ 1.5 AFUDC – Equity 7.0 3.7 3.9 (j) Asset Impairment —We periodically assess the recoverability of certain long-lived assets when factors indicate the carrying value of such assets may be impaired or such assets are planned to be sold. These assessments require significant assumptions and judgments by management. Long-lived assets that would be subject to an impairment assessment generally include any assets within regulated operations that may not be fully recovered from our customers as a result of regulatory decisions that will be made in the future. An impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds the fair value of the asset. The carrying amount of an asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. An impairment loss is measured as the excess of the carrying amount of the asset in comparison to the fair value of the asset. (l) Stock-Based Compensation —Our employees participate in the WEC Energy Group stock-based compensation plans. In accordance with the WEC Energy Group shareholder approved Omnibus Stock Incentive Plan, WEC Energy Group provides long-term incentives through its equity interests to its non-employee directors, officers, and other key employees. The plan provides for the granting of stock options, restricted stock, performance shares, and other stock-based awards. Awards may be paid in WEC Energy Group common stock, cash, or a combination thereof. The number of shares of WEC Energy Group common stock authorized for issuance under the plan was 34.3 million. Stock-based compensation expense is allocated to us based on the outstanding awards held by our employees and our allocation of labor costs. Awards classified as equity awards are measured based on their grant-date fair value. Awards classified as liability awards are recorded at fair value each reporting period. We account for forfeitures as they occur, rather than estimating potential future forfeitures and recording them over the vesting period. Stock Options Our employees are granted WEC Energy Group non-qualified stock options that generally vest on a cliff-basis after three years. The exercise price of a stock option under the plan cannot be less than 100% of the fair market value of WEC Energy Group common stock on the grant date. Historically, all stock options have been granted with an exercise price equal to the fair market value of WEC Energy Group common stock on the date of the grant. Options vest immediately upon retirement, death, or disability; however, they may not be exercised within six months of the grant date except in the event of a change in control. Options expire no later than 10 years from the date of grant. WEC Energy Group stock options are classified as equity awards. The fair value of each stock option was calculated using a binomial option-pricing model. The following table shows the estimated weighted-average fair value per stock option granted to our employees along with the weighted-average assumptions used in the valuation models: 2020 2019 2018 Stock options granted 59,511 59,404 81,730 Estimated weighted-average fair value per stock option $ 10.82 $ 8.60 $ 7.26 Assumptions used to value the options: Risk-free interest rate 1.6% – 1.9% 2.5% – 2.7% 1.6% – 2.5% Dividend yield 3.0 % 3.6 % 3.5 % Expected volatility 16.0 % 17.0 % 18.0 % Expected life (years) 8.6 8.5 5.1 The risk-free interest rate was based on the United States Treasury interest rate with a term consistent with the expected life of the stock options. The dividend yield was based on WEC Energy Group's dividend rate at the time of the grant and historical stock prices. Expected volatility and expected life assumptions were based on WEC Energy Group's historical experience. Restricted Shares WEC Energy Group restricted shares granted to our employees have a vesting period of three years with one-third of the award vesting on each anniversary of the grant date. The restricted shares are classified as equity awards. Performance Units Officers and other key employees are granted performance units under the WEC Energy Group Performance Unit Plan. Under the plan, the ultimate number of units that will be awarded is dependent on WEC Energy Group's total shareholder return (stock price appreciation plus dividends) as compared to the total shareholder return of a peer group of companies over three years, as well as other performance metrics as may be determined by the Compensation Committee. Participants may earn between 0% and 175% of the performance unit award based on WEC Energy Group's total shareholder return. Pursuant to the terms of the plan, these percentages can be adjusted upwards or downwards based on WEC Energy Group's performance against additional performance measures, if any, adopted by the Compensation Committee. Performance units also accrue forfeitable dividend equivalents in the form of additional performance units. All grants of performance units are settled in cash and are accounted for as liability awards accordingly. The fair value of the performance units reflects our estimate of the final expected value of the awards, which is based on WEC Energy Group's stock price and performance achievement under the terms of the award. Stock-based compensation costs are generally recorded over the performance period, which is three years. See Note 8, Common Equity, for more information on WEC Energy Group's stock-based compensation plans. (m) Leases —In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which revised the previous guidance (Topic 840) regarding accounting for leases. Revisions include requiring a lessee to recognize a lease asset and a lease liability on its balance sheet for each lease, including operating leases with an initial term greater than 12 months. In addition, required quantitative and qualitative disclosures related to lease agreements were expanded. As required, we adopted Topic 842 effective January 1, 2019. We utilized the following practical expedients, which were available under ASU 2016-02, in our adoption of the new lease guidance. • We did not reassess whether any expired or existing contracts were leases or contained leases. • We did not reassess the lease classification for any expired or existing leases (that is, all leases that were classified as operating leases in accordance with Topic 840 continue to be classified as operating leases, and all leases that were classified as capital leases in accordance with Topic 840 are classified as finance leases). • We did not reassess the accounting for initial direct costs for any existing leases. We did not elect the practical expedient allowing entities to account for the nonlease components in lease contracts as part of the single lease component to which they were related. Instead, in accordance with ASC 842-10-15-31, our policy is to account for each lease component separately from the nonlease components of the contract. We did not elect the practical expedient to use hindsight in determining the lease term and in assessing impairment of our right of use assets. No impairment losses were included in the measurement of our right of use assets upon our adoption of Topic 842. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842, which is an amendment to ASU 2016-02. Land easements (also commonly referred to as rights of way) represent the right to use, access or cross another entity's land for a specified purpose. This guidance permits an entity to elect a transitional practical expedient, to be applied consistently, to not evaluate under Topic 842 land easements that were already in existence or had expired at the time of the entity's adoption of Topic 842. Once Topic 842 is adopted, an entity is required to apply Topic 842 prospectively to all new (or modified) land easements to determine whether the arrangement should be accounted for as a lease. We elected this practical expedient, resulting in none of our land easements being treated as leases upon our adoption of Topic 842. In July 2018, the FASB issued ASU 2018-11, Leases (Topic 842): Targeted Improvements, which amends ASU 2016-02 and allows entities the option to initially apply Topic 842 at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption, if required. We used the optional transition method to apply this guidance as of January 1, 2019, rather than as of the earliest period presented. We did not require a cumulative-effect adjustment upon adoption of Topic 842. Right of use assets and related lease liabilities related to our operating leases that were recorded upon adoption of Topic 842 were each $13.0 million. Regarding our finance leases, while the adoption of Topic 842 changed the classification of expense related to these leases on a prospective basis, it had no impact on the total amount of lease expense recorded, and did not impact the finance lease assets and related liability amounts recorded on our balance sheets. Significant Judgments and Other Information We are currently party to several easement agreements that allow us access to land we do not own for the purpose of constructing and maintaining certain electric power and natural gas equipment. The majority of payments we make related to easements relate to our wind parks. We have not classified our easements as leases because we view the entire parcel of land specified in our easement agreements to be the identified asset, not just that portion of the parcel that contains our easement. As such, we have concluded that we do not control the use of an identified asset related to our easement agreements, nor do we obtain substantially all of the economic benefits associated with these shared-use assets. As of February 25, 2021, we have not entered into any material leases that have not yet commenced. See Note 12, Leases, for more information. (n) Income Taxes —We follow the liability method in accounting for income taxes. Accounting guidance for income taxes requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax balances to reflect tax rate changes. We are required to assess the likelihood that our deferred tax assets would expire before being realized. If we conclude that certain deferred tax assets are likely to expire before being realized, a valuation allowance would be established against those assets. GAAP requires that, if we conclude in a future period that it is more likely than not that some or all of the deferred tax assets would be realized before expiration, we reverse the related valuation allowance in that period. Any change to the allowance, as a result of a change in judgment about the realization of deferred tax assets, is reported in income tax expense. ITCs associated with regulated operations are deferred and amortized over the life of the assets. We are included in WEC Energy Group's consolidated federal and state income tax returns. In accordance with our tax allocation agreement with WEC Energy Group, we are allocated income tax payments and refunds based upon our separate tax computation. See Note 13, Income Taxes, for more information. We recognize interest and penalties accrued related to unrecognized tax benefits in income tax expense in our income statements. (o) Fair Value Measurements —Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods. Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. When possible, we base the valuations of our derivative assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally-developed inputs. (p) Derivative Instruments —We use derivatives as part of our risk management program to manage the risks associated with the price volatility of purchased power, generation, and natural gas costs for the benefit of our customers. Our approach is non-speculative and designed to mitigate risk. Our regulated hedging programs are approved by the PSCW. We record derivative instruments on our balance sheets as assets or liabilities measured at fair value, unless they qualify f |
Related Parties
Related Parties | 12 Months Ended |
Dec. 31, 2020 | |
Related Party Transactions [Abstract] | |
RELATED PARTIES | RELATED PARTIES We routinely enter into transactions with related parties, including WEC Energy Group, its other subsidiaries, ATC, and other affiliated entities. We provide and receive services, property, and other items of value to and from our parent, WEC Energy Group, and other subsidiaries of WEC Energy Group pursuant to an AIA that became effective in 2017. The AIA was approved by the appropriate regulators, including the PSCW. In accordance with the AIA, WBS provides several categories of services to us (including financial, human resource, and administrative services). We pay ATC for transmission and other related services it provides. In addition, we provide a variety of operational, maintenance, and project management work for ATC, which is reimbursed by ATC. Services are billed to and from ATC under agreements approved by the PSCW, at each of our fully allocated costs. We are also required to initially fund the construction of transmission infrastructure upgrades needed for new generation projects. ATC owns these transmission assets and reimburses us for these costs when the new generation is placed in service. Our balance sheets included the following receivables and payables for services provided to or received from ATC: (in millions) 2020 2019 Accounts receivable Services provided to ATC $ 1.2 $ 1.7 Amounts due from ATC for transmission infrastructure upgrades 1.6 (1) — Accounts payable Services received from ATC 19.2 19.9 (1) The transmission infrastructure upgrades related to the construction of our new solar project, Badger Hollow II. The following table shows activity associated with our related party transactions for the years ended December 31: (in millions) 2020 2019 2018 Transactions with WPS Natural gas related purchases from WPS (1) $ 1.5 $ 2.0 $ 1.9 Charges to WPS for services and other items (2) 12.5 13.2 17.8 Charges from WPS for services and other items (2) 8.3 9.3 10.9 Transactions with WG Natural gas related purchases from WG (1) 5.7 5.4 5.3 Charges to WG for services and other items (2) 42.3 41.1 59.0 (6) Charges from WG for services and other items (2) 31.7 30.1 32.6 Transactions with UMERC Electric sales to UMERC (3) — 7.9 29.6 Charges to UMERC for services and other items (2) 9.8 10.5 15.8 Transactions with Bluewater Storage service fees 12.9 14.2 15.0 Natural gas related sales to Bluewater (1) 2.6 2.3 — Charges to Bluewater for services and other items (2) 3.0 0.2 — Transactions with We Power Lease payments and other lease-related charges from We Power (4) 404.3 401.1 396.5 Charges to We Power for services and other items (2) 4.5 7.1 10.6 Transactions with WBS Charges to WBS for services and other items (2) 67.8 102.6 61.5 Charges from WBS for services and other items (2) 152.9 205.3 243.4 (5) Transactions with ATC Charges to ATC for services and construction 15.6 14.9 13.9 Charges from ATC for network transmission services 229.3 230.6 232.0 Net refund from ATC related to FERC ROE orders 7.3 — — Refund from ATC related to a FERC audit — — 15.4 (1) Includes amounts related to the purchase or sale of natural gas and/or pipeline capacity. (2) Includes amounts charged for services, pass through costs, asset and liability transfers, and other items in accordance with the approved AIAs. As required by FERC regulations for centralized service companies, WBS renders services at cost. Services provided by any regulated subsidiary to another regulated subsidiary or WBS are priced at cost, and any services provided by a regulated subsidiary to a nonregulated subsidiary are priced at the greater of cost or fair market value. (3) On March 31, 2019, UMERC's new natural gas-fired generation in the Upper Peninsula of Michigan began commercial operation. Prior to its generating units achieving commercial operation, UMERC purchased a portion of its power from us. (4) We make lease payments to We Power, another subsidiary of WEC Energy Group, for PWGS Units 1 and 2 and ERGS Units 1 and 2. See Note 12, Leases, for more information. (5) Includes $10.0 million for the transfer of certain benefit-related liabilities to WBS and $59.8 million for the transfer of certain software assets from WBS. (6) Includes $5.3 million for the transfer of certain software assets to WG. Transfer of Net Assets to Upper Michigan Energy Resources Corporation |
Operating Revenues
Operating Revenues | 12 Months Ended |
Dec. 31, 2020 | |
Revenue from Contract with Customer [Abstract] | |
OPERATING REVENUES | OPERATING REVENUES For more information about our significant accounting policies related to operating revenues, see Note 1(d), Operating Revenues. Disaggregation of Operating Revenues The following tables present our operating revenues disaggregated by revenue source for our utility segment. We do not have any revenues associated with our other segment. We disaggregate revenues into categories that depict how the nature, amount, timing, and uncertainty of revenues and cash flows are affected by economic factors. For our utility segment, revenues are further disaggregated by electric and natural gas operations and then by customer class. Each customer class within our electric and natural gas operations have different expectations of service, energy and demand requirements, and can be impacted differently by regulatory activities within their jurisdictions. Wisconsin Electric Power Company Consolidated Year Ended December 31 (in millions) 2020 2019 2018 Electric utility $ 3,000.2 $ 3,088.3 $ 3,212.7 Natural gas utility 358.6 399.0 405.1 Total revenues from contracts with customers 3,358.8 3,487.3 3,617.8 Other operating revenues 8.2 9.4 7.2 Total operating revenues $ 3,367.0 $ 3,496.7 $ 3,625.0 Revenues from Contracts with Customers Electric Utility Operating Revenues The following table disaggregates electric utility operating revenues into customer class: Electric Utility Operating Revenues Year Ended December 31 (in millions) 2020 2019 2018 Residential $ 1,289.2 $ 1,206.7 $ 1,220.8 Small commercial and industrial 955.4 1,010.9 1,020.0 Large commercial and industrial 527.3 583.9 656.6 Other 19.9 20.6 20.7 Total retail revenues 2,791.8 2,822.1 2,918.1 Wholesale 78.8 93.8 108.5 Resale 108.4 132.7 153.7 Steam 21.3 23.3 24.1 Other utility revenues (0.1) 16.4 8.3 Total electric utility operating revenues $ 3,000.2 $ 3,088.3 $ 3,212.7 Natural Gas Utility Operating Revenues The following table disaggregates natural gas utility operating revenues into customer class: Natural Gas Utility Operating Revenues Year Ended December 31 (in millions) 2020 2019 2018 Residential $ 238.4 $ 261.7 $ 264.3 Commercial and industrial 97.1 121.2 126.3 Total retail revenues 335.5 382.9 390.6 Transport 16.3 13.6 13.4 Other utility revenues (1) 6.8 2.5 1.1 Total natural gas utility operating revenues $ 358.6 $ 399.0 $ 405.1 (1) Includes amounts collected from customers for purchased gas adjustment costs. Other Operating Revenues Other operating revenues consist of the following: Year Ended December 31 (in millions) 2020 2019 2018 Late payment charges (1) $ 5.6 $ 8.2 $ 8.2 Rental revenues 2.9 2.9 2.9 Alternative revenues (2) (0.3) (1.7) (3.9) Total other operating revenues $ 8.2 $ 9.4 $ 7.2 (1) The reduction in late payment charges is a result of a regulatory order from the PSCW in response to the COVID-19 pandemic, which includes the suspension of late payment charges during a designated time period. See Note 21, Regulatory Environment, for more information. (2) Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. Negative amounts can also result from revenues to be refunded to customers subject to wholesale true-ups, as discussed in Note 1(d), Operating Revenues. |
Credit Losses
Credit Losses | 12 Months Ended |
Dec. 31, 2020 | |
Credit Loss [Abstract] | |
CREDIT LOSSES | CREDIT LOSSES The table below shows our gross third-party receivable balances and related allowance for credit losses at December 31, 2020. (in millions) Accounts receivable and unbilled revenues $ 525.4 Allowance for credit losses 59.3 Accounts receivable and unbilled revenues, net (1) $ 466.1 Total accounts receivable, net – past due greater than 90 days (1) $ 56.3 Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1) 98.2 % (1) Our exposure to credit losses for certain regulated utility customers is mitigated by a regulatory mechanism we have in place. Specifically, our residential tariffs include a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. As a result, at December 31, 2020, $239.8 million, or 51.4%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses. In addition, we have received specific orders related to the deferral of certain costs (including credit losses) incurred as a result of the COVID-19 pandemic. The additional protections related to our December 31, 2020 accounts receivable and unbilled revenue balances provided by these orders are subject to prudency reviews and are still being assessed. They are not reflected in the percentage in the above table or this note. See Note 21, Regulatory Environment, for more information on these orders. A rollforward of the allowance for credit losses for the year ended December 31, 2020, is included below: (in millions) Balance at December 31, 2019 $ 38.1 Provision for credit losses 24.6 Provision for credit losses deferred for future recovery or refund 14.8 Write-offs charged against the allowance (38.8) Recoveries of amounts previously written off 20.6 Balance at December 31, 2020 $ 59.3 The increase in the allowance for credit losses at December 31, 2020, compared to December 31, 2019, was driven by higher past due accounts receivable balances, primarily related to our residential customers. This increase in accounts receivable balances in arrears was driven by economic disruptions caused by the COVID-19 pandemic, including higher unemployment rates. Also, as a result of the COVID-19 pandemic and related regulatory orders we have received, we were unable to disconnect any of our customers during the year ended December 31, 2020. See Note 21, Regulatory Environment, for more information. |
Regulatory Assets and Liabiliti
Regulatory Assets and Liabilities | 12 Months Ended |
Dec. 31, 2020 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
REGULATORY ASSETS AND LIABILITIES | REGULATORY ASSETS AND LIABILITIES The following regulatory assets were reflected on our balance sheets as of December 31: (in millions) 2020 2019 See Note Regulatory assets (1) (2) Finance leases $ 985.5 $ 930.5 12 Plant retirements 669.8 688.8 Pension and OPEB costs (3) 477.0 459.4 16 Income tax related items 392.6 403.2 13 SSR (4) 135.6 151.5 21 Securitization 105.2 100.0 21 Other, net 37.6 21.8 Total regulatory assets $ 2,803.3 $ 2,755.2 (1) Based on prior and current rate treatment, we believe it is probable that we will continue to recover from customers the regulatory assets in this table. In accordance with GAAP, our regulatory assets do not include the allowance for ROE that is capitalized for regulatory purposes. This allowance was $14.5 million and $9.9 million at December 31, 2020 and 2019, respectively. (2) As of December 31, 2020, we had $8.1 million of regulatory assets not earning a return, $8.9 million of regulatory assets earning a return based on short-term interest rates, and $135.6 million of regulatory assets earning a return based on long-term interest rates. The regulatory assets not earning a return relate to certain environmental remediation costs. The other regulatory assets in the table either earn a return at our weighted average cost of capital or the cash has not yet been expended, in which case the regulatory assets are offset by liabilities. (3) Primarily represents the unrecognized future pension and OPEB costs related to our defined benefit pension and OPEB plans. We are authorized recovery of these regulatory assets over the average remaining service life of each plan. (4) The rate order we received from the PSCW in December 2019 authorized recovery of the SSR regulatory asset over a 15-year period that began on January 1, 2020. The following regulatory liabilities were reflected on our balance sheets as of December 31: (in millions) 2020 2019 See Note Regulatory liabilities Income tax related items $ 806.7 $ 888.1 13 Removal costs (1) 677.2 654.7 Pension and OPEB benefits (2) 132.1 120.4 16 Electric transmission costs (3) (4) 61.7 38.6 Uncollectible expense 15.5 28.8 4 Energy efficiency programs (5) 2.9 15.8 Other, net 11.8 9.8 Total regulatory liabilities $ 1,707.9 $ 1,756.2 Balance sheet presentation Other current liabilities $ 4.2 $ 12.0 Regulatory liabilities 1,703.7 1,744.2 Total regulatory liabilities $ 1,707.9 $ 1,756.2 (1) Represents amounts collected from customers to cover the future cost of property, plant, and equipment removals that are not legally required. Legal obligations related to the removal of property, plant, and equipment are recorded as AROs. See Note 7, Asset Retirement Obligations, for more information on our legal obligations. (2) Primarily represents the unrecognized future pension and OPEB benefits related to our defined benefit pension and OPEB plans. We will amortize these regulatory liabilities into net periodic benefit cost over the average remaining service life of each plan. (3) Based on orders received from the PSCW, we were required to apply the refunds due to customers from our earnings sharing mechanism to our electric transmission escrow during 2019. As a result, $38.6 million of our earnings sharing refunds were reflected in our electric transmission regulatory liability at December 31, 2019. We had no refunds due to customers from our earnings sharing mechanism at December 31, 2020. (4) In accordance with the PSCW's approval of escrow accounting for our ATC and MISO network transmission expenses, we defer as a regulatory asset or liability the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. (5) Represents amounts refundable to customers related to programs designed to meet energy efficiency standards. Pleasant Prairie Power Plant The Pleasant Prairie power plant was retired on April 10, 2018. The net book value of this plant was $602.7 million at December 31, 2020, representing book value less cost of removal and accumulated depreciation. In addition, previously deferred unprotected tax benefits from the Tax Legislation related to the unrecovered balance of this plant were $19.6 million. The net amount of $583.1 million was classified as a regulatory asset on our balance sheets as a result of the retirement of the plant. This regulatory asset does not include certain other previously recorded deferred tax liabilities of $168.7 million related to the retired Pleasant Prairie power plant. Pursuant to our rate order issued by the PSCW in December 2019, we will continue to amortize this regulatory asset on a straight-line basis through 2039, using the composite depreciation rates approved by the PSCW before this plant was retired. Amortization is included in depreciation and amortization in the income statement. We have FERC approval to continue to collect the net book value of the Pleasant Prairie power plant using the approved composite depreciation rates, in addition to a return on the remaining net book value. Collection of the return of and on the net book value is no longer subject to refund as the FERC completed its prudency review and concluded that the retirement of this plant was prudent. We received approval from the PSCW in December 2019 to collect a full return of the net book value of the Pleasant Prairie power plant, and a return on all but $100 million of the net book value. In accordance with our PSCW rate order received in December 2019, we filed an application with the PSCW on July 20, 2020 requesting a financing order to securitize the remaining $100 million of the Pleasant Prairie power plant's book value, plus the carrying costs accrued on the $100 million during the securitization process and related fees. On November 17, 2020, the PSCW issued a written order approving this application. Presque Isle Power Plant Pursuant to MISO's April 2018 approval of the retirement of the PIPP, these units were retired on March 31, 2019, and the plant was reclassified to a regulatory asset on our balance sheets. After the retirement of the PIPP, a portion of the regulatory asset and related cost of removal reserve was transferred to UMERC for recovery from its retail customers. On our balance sheet, the net book value of the PIPP was $149.1 million at December 31, 2020, representing book value less cost of removal and accumulated depreciation. In addition, previously deferred unprotected tax benefits from the Tax Legislation related to our unrecovered balance of these units were $6.0 million, resulting in a net amount of $143.1 million at December 31, 2020. This regulatory asset does not include certain other previously recorded deferred tax liabilities of $42.8 million related to the retired PIPP. Effective with our rate order issued by the PSCW in December 2019, we received approval to collect a return of and on our share of the net book value of the PIPP, and as a result, will continue to amortize the regulatory assets on a straight-line basis through 2037, using the composite depreciation rates approved by the PSCW before the units were retired. Amortization is included in depreciation and amortization in the income statement. We have FERC approval to continue to collect the net book value of the PIPP using the approved composite depreciation rates, in addition to a return on the net book value. However, this approval is subject to refund pending the outcome of settlement proceedings. Severance Liability for Plant Retirements In December 2017, a severance liability of $25.8 million was recorded in other current liabilities on our balance sheets related to these plant retirements. Activity related to this severance liability for the years ended December 31 was as follows: (in millions) 2020 2019 2018 Severance liability at January 1 $ 2.1 $ 12.9 $ 25.8 Severance payments (0.1) (5.7) (9.9) Other (1.3) (5.1) (3.0) Total severance liability at December 31 $ 0.7 $ 2.1 $ 12.9 |
Property, Plant, and Equipment
Property, Plant, and Equipment | 12 Months Ended |
Dec. 31, 2020 | |
Property, Plant and Equipment [Abstract] | |
PROPERTY, PLANT, AND EQUIPMENT | PROPERTY, PLANT, AND EQUIPMENT Property, plant, and equipment consisted of the following at December 31: (in millions) 2020 2019 Electric – generation $ 3,612.8 $ 3,623.4 Electric – distribution 5,328.4 5,086.4 Natural gas – distribution, storage, and transmission 1,444.2 1,358.0 Other 864.6 814.7 Less: Accumulated depreciation 3,568.5 3,397.0 Net 7,681.5 7,485.5 CWIP 253.2 190.8 Net utility and non-utility property, plant, and equipment 7,934.7 7,676.3 Property under finance leases 3,135.9 3,077.4 Less: Accumulated amortization 1,280.7 1,167.0 Net leased facilities 1,855.2 1,910.4 Total property, plant, and equipment $ 9,789.9 $ 9,586.7 Public Service Building During a significant rain event in May 2020, an underground steam tunnel in downtown Milwaukee flooded and steam vented into our Public Service Building. The damage to the building from the flooding and steam was extensive and will require significant repairs and restorations. As of December 31, 2020, we have incurred $35.2 million of costs related to these repairs and restorations. We received $20.0 million of insurance proceeds to cover a portion of these costs and $2.7 million was recorded as a receivable for future insurance recoveries. The remaining $12.5 million of costs were included in other operation and maintenance expense. We anticipate that the majority of future capital expenditures required to restore the Public Service Building will either be covered by insurance or recovery will be requested from the PSCW. As such, we do not currently expect a significant impact to our future results of operations, and although we may experience differences between periods in the timing of cash flows, we also do not currently expect a significant impact to our long-term cash flows from this event. |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2020 | |
Asset Retirement Obligation Disclosure [Abstract] | |
ASSET RETIREMENT OBLIGATIONS | ASSET RETIREMENT OBLIGATIONS We have recorded AROs primarily for asbestos abatement at certain generation and substation facilities; the removal and dismantlement of biomass and hydro generation facilities; the dismantling of wind generation projects; and the closure of coal combustion residual landfills at our generation facilities. We establish regulatory assets and liabilities to record the differences between ongoing expense recognition under the ARO accounting rules and the rate-making practices for retirement costs authorized by the PSCW. On our balance sheets, AROs are recorded within other long-term liabilities. The following table shows changes to our AROs during the years ended December 31: (in millions) 2020 2019 2018 Balance as of January 1 $ 65.0 $ 70.7 $ 68.3 Accretion 2.3 3.6 3.3 Additions and revisions to estimated cash flows (11.1) (1) (8.4) (1) 1.0 Liabilities settled (1.7) (0.9) (1.9) Balance as of December 31 $ 54.5 $ 65.0 $ 70.7 |
Common Equity
Common Equity | 12 Months Ended |
Dec. 31, 2020 | |
Stockholders' Equity Note [Abstract] | |
COMMON EQUITY | COMMON EQUITY Stock-Based Compensation Plans The following table summarizes our pre-tax stock-based compensation expense, including amounts allocated from WBS, and the related tax benefit recognized in income for the years ended December 31: (in millions) 2020 2019 2018 Stock options $ 2.1 $ 1.7 $ 2.0 Restricted stock 2.7 2.7 3.0 Performance units 9.7 17.9 9.6 Stock-based compensation expense $ 14.5 $ 22.3 $ 14.6 Related tax benefit $ 4.0 $ 6.1 $ 4.0 Stock-based compensation costs capitalized during 2020, 2019, and 2018 were not significant. Stock Options The following is a summary of our employees' WEC Energy Group stock option activity during 2020: Stock Options Number of Options Weighted-Average Exercise Price Weighted-Average Remaining Contractual Life (in years) Aggregate Intrinsic Value (in millions) Outstanding as of January 1, 2020 626,261 $ 48.98 Granted 59,511 $ 91.49 Exercised (121,624) $ 42.60 Transferred (75,668) $ 47.30 Forfeited (3,367) $ 67.33 Outstanding as of December 31, 2020 485,113 $ 55.93 5.1 $ 17.5 Exercisable as of December 31, 2020 330,010 $ 46.45 3.7 $ 15.0 The aggregate intrinsic value of outstanding and exercisable options in the above table represents the total pre-tax intrinsic value that would have been received by the option holders had they exercised all of their options on December 31, 2020. This is calculated as the difference between WEC Energy Group's closing stock price on December 31, 2020, and the option exercise price, multiplied by the number of in-the-money stock options. The intrinsic value of options exercised during the years ended December 31, 2020, 2019, and 2018 was $7.1 million, $8.0 million, and $12.9 million, respectively. Cash received by WEC Energy Group from exercises of its options by our employees was $5.2 million, $6.3 million, and $10.0 million during the years ended December 31, 2020, 2019, and 2018, respectively. The actual tax benefit from option exercises for the same periods was approximately $1.9 million, $2.2 million, and $2.7 million, respectively. As of December 31, 2020, we expected to recognize approximately $0.8 million of unrecognized compensation cost related to unvested and outstanding WEC Energy Group stock options over the next 1.8 years on a weighted-average basis. During the first quarter of 2021, the Compensation Committee awarded 60,108 non-qualified WEC Energy Group stock options with an exercise price of $91.06 and a weighted-average grant date fair value of $13.20 per option to certain of our officers and other key employees under its normal schedule of awarding long-term incentive compensation. Restricted Shares The following is a summary of our employees' WEC Energy Group restricted stock activity during 2020: Restricted Shares Number of Shares Weighted-Average Grant Date Fair Value Outstanding and unvested as of January 1, 2020 9,736 $ 65.58 Granted 4,371 $ 91.49 Released (4,791) $ 63.95 Transferred 64 $ 66.78 Forfeited (748) $ 73.02 Outstanding and unvested as of December 31, 2020 8,632 $ 78.97 The intrinsic value of WEC Energy Group restricted stock held by our employees that was released was $0.4 million for each of the years ended December 31, 2020, 2019, and 2018. The actual tax benefit from released restricted shares was $0.1 million for each of the years ended December 31, 2020, 2019, and 2018. As of December 31, 2020, we expected to recognize approximately $1.1 million of unrecognized compensation cost related to unvested and outstanding WEC Energy Group restricted stock over the next 1.8 years on a weighted-average basis. During the first quarter of 2021, the Compensation Committee awarded 4,183 WEC Energy Group restricted shares to our officers and other key employees under its normal schedule of awarding long-term incentive compensation. The grant date fair value of these awards was $91.06 per share. Performance Units During 2020, 2019, and 2018, the Compensation Committee awarded 18,952; 22,452; and 32,650 WEC Energy Group performance units, respectively, to our officers and other key employees under the WEC Energy Group Performance Unit Plan. Performance units with an intrinsic value of $3.9 million, $2.3 million, and $2.0 million were settled during 2020, 2019, and 2018, respectively. The actual tax benefit from the distribution of performance units was approximately $0.9 million, $0.5 million, and $0.4 million for the years ended December 31, 2020, 2019, and 2018, respectively. At December 31, 2020, our employees held 59,530 WEC Energy Group performance units, including dividend equivalents. A liability of $5.5 million was recorded on our balance sheet at December 31, 2020 related to these outstanding units. As of December 31, 2020, we expected to recognize approximately $7.3 million of unrecognized compensation cost related to unvested and outstanding WEC Energy Group performance units over the next 1.6 years on a weighted-average basis. During the first quarter of 2021, performance units held by our employees with an intrinsic value of $3.0 million were settled. The actual tax benefit from the distribution of these awards was $0.7 million. In January 2021, the Compensation Committee also awarded 18,138 WEC Energy Group performance units to our officers and other key employees under its normal schedule of awarding long-term incentive compensation. Restrictions Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to WEC Energy Group in the form of cash dividends, loans, or advances. In addition, Wisconsin law prohibits us from making loans to or guaranteeing obligations of WEC Energy Group or its subsidiaries. In accordance with our most recent rate order, we may not pay common dividends above the test year forecasted amount reflected in our rate case, if it would cause our average common equity ratio, on a financial basis, to fall below our authorized level of 52.5%. A return of capital in excess of the test year amount can be paid by us at the end of the year provided that our average common equity ratio does not fall below the authorized level. We may not pay common dividends to WEC Energy Group under our Restated Articles of Incorporation if any dividends on our outstanding preferred stock have not been paid. In addition, pursuant to the terms of our 3.60% Serial Preferred Stock, our ability to declare common dividends would be limited to 75% or 50% of net income during a twelve month period if our common stock equity to total capitalization, as defined in the preferred stock designation, is less than 25% and 20%, respectively. See Note 10, Short-Term Debt and Lines of Credit, for a discussion of certain financial covenants related to our short-term debt obligations. As of December 31, 2020, our retained earnings were fully restricted. We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future. |
Preferred Stock
Preferred Stock | 12 Months Ended |
Dec. 31, 2020 | |
Class of Stock Disclosures [Abstract] | |
PREFERRED STOCK | PREFERRED STOCK The following table shows preferred stock authorized and outstanding at December 31, 2020 and 2019: (in millions, except share and per share amounts) Shares Authorized Shares Outstanding Redemption Price Per Share Total $100 par value, Six Per Cent. Preferred Stock 45,000 44,498 — $ 4.4 $100 par value, Serial Preferred Stock 3.60% Series 2,286,500 260,000 $ 101 26.0 $25 par value, Serial Preferred Stock 5,000,000 — — — Total $ 30.4 |
Short-Term Debt and Lines of Cr
Short-Term Debt and Lines of Credit | 12 Months Ended |
Dec. 31, 2020 | |
Short-term Debt [Abstract] | |
SHORT-TERM DEBT AND LINES OF CREDIT | SHORT-TERM DEBT AND LINES OF CREDIT The following table shows our short-term borrowings and their corresponding weighted-average interest rates as of December 31: (in millions, except percentages) 2020 2019 Commercial paper Amount outstanding at December 31 $ 292.0 $ 115.5 Average interest rate on amounts outstanding at December 31 0.21 % 2.03 % Our average amount of commercial paper borrowings based on daily outstanding balances during 2020 was $72.7 million, with a weighted-average interest rate during the period of 1.16%. We have entered into a bank back-up credit facility to maintain short-term credit liquidity which, among other terms, requires us to maintain, subject to certain exclusions, a total funded debt to capitalization ratio of 65% or less. As of December 31, 2020, we were in compliance with this ratio. The information in the table below relates to our revolving credit facility used to support our commercial paper borrowing program, including remaining available capacity under this facility as of December 31: (in millions) Maturity 2020 Revolving credit facility October 2022 $ 500.0 Less: Letters of credit issued inside credit facility $ 1.0 Commercial paper outstanding 292.0 Available capacity under existing agreement $ 207.0 This facility has a renewal provision for two extensions, subject to lender approval. Each extension is for a period of one year. Our bank back-up credit facility contains customary covenants, including certain limitations on our ability to sell assets. The credit facility also contains customary events of default, including payment defaults, material inaccuracy of representations and warranties, covenant defaults, bankruptcy proceedings, certain judgments, Employee Retirement Income Security Act of 1974 defaults and change of control. |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2020 | |
Debt Disclosure [Abstract] | |
LONG-TERM DEBT | LONG-TERM DEBT The following table is a summary of our long-term debt outstanding as of December 31: (in millions) Interest Rate Year Due 2020 2019 Debentures (unsecured) 2.95% 2021 300.0 300.0 2.05% 2024 300.0 300.0 3.10% 2025 250.0 250.0 6.50% 2028 150.0 150.0 5.625% 2033 335.0 335.0 5.70% 2036 300.0 300.0 3.65% 2042 250.0 250.0 4.25% 2044 250.0 250.0 4.30% 2045 250.0 250.0 4.30% 2048 300.0 300.0 6.875% 2095 100.0 100.0 Total 2,785.0 2,785.0 Unamortized debt issuance costs (7.4) (8.0) Unamortized discount, net (16.4) (17.8) Total long-term debt, including current portion 2,761.2 2,759.2 Current portion of long-term debt (300.0) — Total long-term debt 2,461.2 2,759.2 We amortize debt premiums, discounts and debt issuance costs over the life of the debt using the straight-line method and we include the costs in interest expense. The following table shows the future maturities of our long-term debt outstanding as of December 31, 2020: (in millions) 2021 $ 300.0 2022 — 2023 — 2024 300.0 2025 250.0 Thereafter 1,935.0 Total $ 2,785.0 |
Leases
Leases | 12 Months Ended |
Dec. 31, 2020 | |
Leases [Abstract] | |
LEASES | LEASES Obligations Under Operating Leases We have recorded right of use assets and lease liabilities associated with the following operating leases. • Land we are leasing related to our Rothschild biomass plant through June 2051. • Rail cars we are leasing to transport coal to various generating facilities through February 2021. • Various office space leases. The operating leases generally require us to pay property taxes, insurance premiums, and operating and maintenance costs associated with the leased property. Many of our leases contain options to renew past the initial term, as set forth in the lease agreement. Obligations Under Finance Leases We are the obligor under a power purchase contract with an unaffiliated third party and we lease power plants from We Power. Under finance lease accounting, we have recorded the leased plants and corresponding obligations as right of use assets and lease liabilities on our balance sheets. We treat these agreements as operating leases for rate-making purposes. Prior to our adoption of Topic 842 on January 1, 2019, we accounted for these finance leases under Topic 980-840, Regulated Operations – Leases, as follows: • We recorded our minimum lease payments under the power purchase contract as purchased power expense in cost of sales on our income statements. • We recorded our minimum lease payments under our leases with We Power as rent expense in other operation and maintenance in our income statements. • We recorded the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under finance lease accounting rules as a deferred regulatory asset on our balance sheets. In conjunction with our adoption of Topic 842, while the timing of expense recognition related to our finance leases did not change, the classification of the lease expense changed as follows: • Effective January 1, 2019, the minimum lease payments under the power purchase contract were no longer classified within cost of sales in our income statements, but were instead recorded as a component of depreciation and amortization and interest expense in accordance with Topic 980-842, Regulated Operations – Leases. • Similarly, the lease payments related to our leases with We Power were no longer classified within other operation and maintenance in our income statements, but were also divided between depreciation and amortization expense and interest expense in accordance with Topic 980-842. • In accordance with Topic 980-842, the timing of lease expense did not change for these finance leases upon adoption of Topic 842, and still resembled the expense recognition pattern of an operating lease, as the amortization of the right of use assets was modified from what would typically be recorded for a finance lease under Topic 842. • We continue to record the difference between the minimum lease payments and the sum of imputed interest and unadjusted amortization costs calculated under the finance lease accounting rules as a deferred regulatory asset on our balance sheets. Power Purchase Commitment In 1997, we entered into a 25-year power purchase contract with an unaffiliated independent power producer. The contract, for 236 MWs of firm capacity from a natural gas-fired cogeneration facility, includes zero minimum energy requirements. When the contract expires in 2022, we may, at our option and with proper notice, renew for another ten years, purchase the generating facility at fair market value, or allow the contract to expire. At lease inception we recorded this leased facility and corresponding obligation on our balance sheets at the estimated fair value of the plant's electric generating facilities. As previously discussed, we treat the long-term power purchase contract as an operating lease for rate-making purposes. We record the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under finance lease accounting rules as a deferred regulatory asset on our balance sheets. Minimum lease payments are a function of the 236 MWs of firm capacity we receive from the plant and the fixed monthly capacity rate published in the lease. Due to the timing and the amounts of the minimum lease payments, the regulatory asset increased to $78.5 million in 2009, at which time the regulatory asset began to be reduced to zero over the remaining life of the contract. The total obligation under the finance lease was $12.1 million at December 31, 2020, and will decrease to zero over the remaining life of the contract. Port Washington Generating Station We are leasing PWGS 1 and PWGS 2, two 545 MW natural gas-fired generation units, which were placed in service in July 2005 and May 2008, respectively, from We Power under PSCW approved leases. We are amortizing the leased units on a straight-line basis over the original 25-year term of the leases. The lease payments are expected to be recovered through our rates, as supported by Wisconsin's 2001 leased generation law. Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $129.5 million in the year 2021 for PWGS 1 and to approximately $126.8 million in the year 2023 for PWGS 2, at which time the regulatory assets will be reduced to zero over the remaining lives of the contracts. The total obligation under the finance leases for the units was $598.9 million as of December 31, 2020, and will decrease to zero over the remaining lives of the contracts. The only variability associated with the PWGS lease payments relates to the potential for future changes in We Power's tax or interest rates, as the positive or negative impact of these changes is generally passed along to us, and subsequently to our customers. Because variability in the lease payments is dependent upon a rate (interest rate or tax rate), the lease payments are considered unavoidable under Topic 842, and are included in the measurement of the right of use asset and lease liability, consistent with how they were treated under Topic 840. When the PWGS 1 and PWGS 2 contracts expire in 2030 and 2033, respectively, we may, at our option and with proper notice, choose to renew one or both contracts for up to three consecutive renewal terms (each renewal term would approximate 80% of the then remaining economic useful life of the respective generation unit), purchase one or both generating facilities at fair market value, or allow the contracts to expire. Elm Road Generating Station We are leasing ER 1, ER 2, and the common facilities, which are also utilized by our OC 5 through OC 8 generating units, from We Power under PSCW approved leases. We are amortizing the leased units on a straight-line basis over the 30-year term of the leases. ER 1 and ER 2 were placed in service in February 2010 and January 2011, respectively. The lease payments are expected to be recovered through our rates, as supported by Wisconsin's 2001 leased generation law. Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $528.2 million in the year 2028 for ER 1 and to approximately $436.1 million in the year 2029 for ER 2, at which time the regulatory assets will be reduced to zero over the remaining lives of the contracts. The total obligation under the finance leases was $2,207.1 million as of December 31, 2020, and will decrease to zero over the remaining lives of the contracts. The only variability associated with the ERGS lease payments relates to the potential for future changes in We Power's tax or interest rates, as the positive or negative impact of these changes are generally passed along to us, and subsequently to our customers. Because variability in the lease payments is dependent upon a rate (interest rate or tax rate), the lease payments are considered unavoidable under Topic 842, and are included in the measurement of the right of use asset and lease liability, consistent with how they were treated under Topic 840. When the ER 1 and ER 2 contracts expire in 2040 and 2041, respectively, we may, at our option and with proper notice, choose to renew one or both contracts for up to three consecutive renewal terms (each renewal term would approximate 80% of the then remaining economic useful life of the respective generation unit), purchase one or both generating facilities at fair market value, or allow the contracts to expire. Badger Hollow Solar Park II Related to our investment in Badger Hollow II, we, along with an unaffiliated utility, entered into several land leases in Iowa County, Wisconsin that commenced in the second quarter of 2020. The leases are for a total of approximately 1,500 acres of land. Each lease has an initial construction term that ends upon achieving commercial operation, then automatically extends for 25 years with an option for an additional 25-year extension. We expect the optional extension to be exercised, and, as a result, the land leases are being amortized over the extended term of the leases. The lease payments will be recovered through rates. We treat these land lease contracts as operating leases for rate-making purposes. Our total obligation under the finance leases for Badger Hollow II was $23.1 million as of December 31, 2020, and will decrease to zero over the remaining lives of the leases. Amounts Recognized in the Financial Statements The components of lease expense and supplemental cash flow information related to our leases for the year ended December 31 are as follows: (in millions) 2020 2019 2018 Finance lease expense Amortization of right of use assets (1) $ 59.2 $ 20.6 Interest on lease liabilities (2) 347.1 350.9 Capital lease expense (3) $ 371.0 Operating lease expense (4) 2.6 2.6 2.7 Total lease expense $ 408.9 $ 374.1 $ 373.7 Other information Cash paid for amounts included in the measurement of lease liabilities Operating cash flows for finance/capital leases (5) $ 347.1 $ 350.9 $ 381.4 Operating cash flows for operating leases $ 2.6 $ 2.6 $ 2.7 Financing cash flows for finance leases (5) $ 58.3 $ 50.5 Non-cash activities: Right of use assets obtained in exchange for finance lease liabilities $ 22.8 $ — Right of use assets obtained in exchange for operating lease liabilities $ — $ 13.0 Weighted-average remaining lease term – finance leases 18.0 years 18.6 years Weighted-average remaining lease term – operating leases 29.9 years 25.0 years Weighted-average discount rate – finance leases (6) 13.8 % 13.9 % Weighted average discount rate – operating leases (6) 4.6 % 4.5 % (1) Amortization of right of use assets was included as a component of depreciation and amortization expense for the years ended December 31, 2020 and 2019. (2) Interest on lease liabilities was included as a component of interest expense for the years ended December 31, 2020 and 2019. (3) Capital lease expense related to the long-term PPA was included in cost of sales and total capital lease cost related to the PWGS and ERGS units was included in other operation and maintenance for the year ended December 31, 2018. (4) Operating lease expense was included as a component of operation and maintenance for the years ended December 31, 2020, 2019, and 2018. (5) Prior to our adoption of Topic 842 on January 1, 2019, all cash flows related to finance leases were recorded as a component of operating cash flows. (6) Because our operating leases do not provide an implicit rate of return, we used the fully collateralized incremental borrowing rates based upon information available for similarly rated companies in determining the present value of lease payments for our operating leases. For our PPA and the PWGS and ERGS units that meet the definition of a finance lease, the rate implicit in the lease was readily determinable. For our solar land leases that are finance leases, we used the fully collateralized incremental borrowing rates based upon information available for similarly rated companies in determining the present value of lease payments. The following table summarizes our finance lease right of use assets, which were included in property, plant and equipment on our balance sheets: (in millions) December 31, 2020 December 31, 2019 Long-term power purchase commitment Under finance lease $ 140.3 $ 140.3 Accumulated amortization (132.3) (126.6) Total long-term power purchase commitment $ 8.0 $ 13.7 PWGS Under finance lease $ 749.4 $ 742.7 Accumulated amortization (399.6) (367.6) Total PWGS $ 349.8 $ 375.1 ERGS Under finance lease $ 2,223.4 $ 2,194.4 Accumulated amortization (748.6) (672.8) Total ERGS $ 1,474.8 $ 1,521.6 Badger Hollow II land leases Under finance leases $ 22.8 $ — Accumulated amortization (0.2) — Total Badger Hollow II land leases $ 22.6 $ — Total finance lease right of use assets $ 1,855.2 $ 1,910.4 Right of use assets related to operating leases were $8.4 million and $10.6 million at December 31, 2020 and 2019, respectively, and were included in other long-term assets on our balance sheets. Future minimum lease payments under our finance and operating leases and the present value of our net minimum lease payments as of December 31, 2020, were as follows: (in millions) Total Operating Leases Power Purchase Commitment PWGS ERGS Badger Hollow II Total Finance Leases 2021 $ 0.7 9.4 $ 99.4 $ 297.9 $ 0.3 $ 407.0 2022 0.5 4.2 99.4 297.8 0.3 401.7 2023 0.5 — 99.4 297.6 0.7 397.7 2024 0.5 — 99.3 297.6 0.7 397.6 2025 0.5 — 99.1 297.5 0.7 397.3 Thereafter 12.7 — 589.4 4,316.5 55.0 4,960.9 Total minimum lease payments 15.4 13.6 1,086.0 5,804.9 57.7 6,962.2 Less: Interest (7.0) (1.5) (487.1) (3,597.8) (34.6) (4,121.0) Present value of minimum lease payments 8.4 12.1 598.9 2,207.1 23.1 2,841.2 Less: Short-term lease liabilities (0.3) (8.1) (28.9) (29.8) — (66.8) Long-term lease liabilities $ 8.1 $ 4.0 $ 570.0 $ 2,177.3 $ 23.1 $ 2,774.4 Short-term and long-term lease liabilities related to operating leases were included in other current liabilities and other long-term liabilities on the balance sheets, respectively. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2020 | |
Income Tax Disclosure [Abstract] | |
INCOME TAXES | INCOME TAXES Income Tax Expense (Benefit) The following table is a summary of income tax expense (benefit) for each of the years ended December 31: (in millions) 2020 2019 2018 Current tax expense (benefit) $ 112.2 $ 73.4 $ (56.2) Deferred income tax expense (benefit), net (66.0) (128.9) 0.1 ITC, net (1.5) (2.3) (0.8) Total income tax expense (benefit) $ 44.7 $ (57.8) $ (56.9) Statutory Rate Reconciliation The provision for income taxes for each of the years ended December 31 differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes as a result of the following: 2020 2019 2018 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Amount Effective Tax Rate Statutory federal income tax $ 86.2 21.0 % $ 63.9 21.0 % $ 63.3 21.0 % State income taxes net of federal tax benefit 26.5 6.5 % 20.2 6.6 % 19.6 6.5 % Federal excess deferred tax amortization – Wisconsin unprotected (1) (42.7) (10.4) % — — % — — % Federal excess deferred tax amortization (2) (23.2) (5.7) % (16.1) (5.3) % (15.5) (5.1) % Wind PTCs (11.1) (2.7) % (9.3) (3.0) % (9.4) (3.1) % AFUDC – Equity (1.5) (0.4) % (0.8) (0.3) % (0.8) (0.3) % ITC restored (1.5) (0.4) % (2.3) (0.8) % (0.8) (0.3) % Domestic production activities deferral 6.3 1.5 % 6.1 2.0 % 6.1 2.0 % Tax repairs (3) 3.3 0.8 % (122.9) (40.1) % (120.7) (39.9) % Other, net 2.4 0.7 % 3.4 1.0 % 1.3 0.4 % Total income tax expense (benefit) $ 44.7 10.9 % $ (57.8) (18.9) % $ (56.9) (18.8) % (1) In accordance with the rate order received from the PSCW in December 2019, we are amortizing these unprotected deferred tax benefits over periods ranging from two years to four years, to reduce near-term rate impacts to our customers. The decrease in income tax expense related to the amortization of the deferred tax benefits is offset by a decrease in revenue as the benefits are returned to customers, resulting in no impact on net income. (2) The Tax Legislation required us to remeasure our deferred income taxes and we began to amortize the resulting excess protected deferred income taxes beginning in 2018 in accordance with normalization requirements. The decrease in income tax expense related to the amortization of the deferred tax benefits is offset by a decrease in revenue as the benefits are returned to customers, resulting in no impact on net income. (3) In accordance with a settlement agreement with the PSCW, we flowed through the tax benefit of our repair related deferred tax liabilities in 2018 and 2019, to maintain certain regulatory asset balances at their December 31, 2017 levels.The flow through treatment of the repair related deferred tax liabilities offsets the negative income statement impact of holding the regulatory assets level, resulting in no impact to net income. In 2020, in accordance with the settlement agreement, we started collecting the payback of the tax repairs benefit that was flowed through to customers. Customers will pay back all of the benefits over the next fifty years. See Note 21, Regulatory Environment, for more information about the impact of the Tax Legislation and the Wisconsin rate order. Deferred Income Tax Assets and Liabilities The components of deferred income taxes as of December 31 were as follows: (in millions) 2020 2019 Deferred tax assets Tax gross up – regulatory items $ 132.6 $ 152.7 Deferred revenues 124.6 126.8 Future tax benefits 14.8 41.0 Other 82.3 64.5 Total deferred tax assets $ 354.3 $ 385.0 Deferred tax liabilities Property-related $ 1,334.4 $ 1,368.9 Deferred costs – Plant retirements 237.4 215.5 Employee benefits and compensation 49.3 55.8 Deferred costs – SSR 47.7 51.1 Other 42.7 41.1 Total deferred tax liabilities 1,711.5 1,732.4 Deferred tax liability, net $ 1,357.2 $ 1,347.4 Consistent with rate-making treatment, deferred taxes in the table above are offset for temporary differences that have related regulatory assets and liabilities. The components of net deferred tax assets associated with federal and state tax benefit carryforwards as of December 31, 2020 and 2019 are summarized in the tables below: 2020 (in millions) Gross Value Deferred Tax Effect Earliest Year of Expiration Future tax benefits as of December 31, 2020 Federal tax credit $ — $ 14.8 2040 Balance as of December 31, 2020 $ — $ 14.8 2019 (in millions) Gross Value Deferred Tax Effect Earliest Year of Expiration Future tax benefits as of December 31, 2019 Federal tax credit $ — $ 37.1 2037 State net operating loss 52.4 3.3 2035 Other state benefits — 0.6 2019 Balance as of December 31, 2019 $ 52.4 $ 41.0 Unrecognized Tax Benefits We had no unrecognized tax benefits at December 31, 2020 and 2019. We do not expect any unrecognized tax benefits to affect our effective tax rate in periods after December 31, 2020. For the years ended December 31, 2020, 2019, and 2018, we recognized no interest expense related to unrecognized tax benefits in our income statements. For the years ended December 31, 2020, 2019, and 2018, we recognized no penalties related to unrecognized tax benefits in our income statements. For the years ended December 31, 2020 and 2019, we had no interest accrued and no penalties accrued related to unrecognized tax benefits on our balance sheets. We do not anticipate any significant increases in the total amount of unrecognized tax benefits within the next 12 months. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2020 | |
Fair Value Disclosures [Abstract] | |
FAIR VALUE MEASUREMENTS | FAIR VALUE MEASUREMENTS The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy: December 31, 2020 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 3.0 $ 0.8 $ — $ 3.8 FTRs — — 1.1 1.1 Coal contracts — 1.4 — 1.4 Total derivative assets $ 3.0 $ 2.2 $ 1.1 $ 6.3 Derivative liabilities Natural gas contracts $ 2.9 $ 0.6 $ — $ 3.5 Coal contracts — 0.6 — 0.6 Total derivative liabilities $ 2.9 $ 1.2 $ — $ 4.1 December 31, 2019 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 0.4 $ — $ — $ 0.4 FTRs — — 1.5 1.5 Coal contracts — 0.1 — 0.1 Total derivative assets $ 0.4 $ 0.1 $ 1.5 $ 2.0 Derivative liabilities Natural gas contracts $ 5.2 $ — $ — $ 5.2 Coal contracts — 0.2 — 0.2 Total derivative liabilities $ 5.2 $ 0.2 $ — $ 5.4 The derivative assets and liabilities listed in the tables above include options, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. They also include FTRs, which are used to manage electric transmission congestion costs in the MISO Energy Markets. The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy at December 31: (in millions) 2020 2019 2018 Balance at the beginning of the period $ 1.5 $ 4.4 $ 2.4 Purchases 3.1 6.8 9.4 Settlements (3.5) (9.7) (7.4) Balance at the end of the period $ 1.1 $ 1.5 $ 4.4 Fair Value of Financial Instruments The following table shows the financial instruments included on our balance sheets that are not recorded at fair value: December 31, 2020 December 31, 2019 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock $ 30.4 $ 32.3 $ 30.4 $ 29.5 Long-term debt, including current portion 2,761.2 3,451.8 2,759.2 3,209.5 The fair values of our long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy. |
Derivative Instruments
Derivative Instruments | 12 Months Ended |
Dec. 31, 2020 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
DERIVATIVE INSTRUMENTS | DERIVATIVE INSTRUMENTS The following table shows our derivative assets and derivative liabilities, along with their classification on our balance sheets. None of our derivatives are designated as hedging instruments. December 31, 2020 December 31, 2019 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Other current Natural gas contracts $ 3.7 $ 3.2 $ 0.4 $ 5.1 FTRs 1.1 — 1.5 — Coal contracts 1.4 0.5 — 0.2 Total other current 6.2 3.7 1.9 5.3 Other long-term Natural gas contracts 0.1 0.3 — 0.1 Coal contracts — 0.1 0.1 — Total other long-term 0.1 0.4 0.1 0.1 Total $ 6.3 $ 4.1 $ 2.0 $ 5.4 Realized gains (losses) on derivatives are primarily recorded in cost of sales on the income statements. Our estimated notional sales volumes and realized gains (losses) were as follows for the years ended: December 31, 2020 December 31, 2019 December 31, 2018 (in millions) Volumes Gains (Losses) Volumes Gains (Losses) Volumes Gains Natural gas contracts 62.1 Dth $ (15.1) 61.6 Dth $ (11.3) 53.4 Dth $ 9.7 Petroleum products contracts — gallons — — gallons — 4.2 gallons 1.2 FTRs 20.9 MWh 2.5 21.7 MWh 8.7 21.2 MWh 3.4 Total $ (12.6) $ (2.6) $ 14.3 At December 31, 2020 and 2019, we had posted cash collateral of $6.7 million and $8.5 million, respectively, in our margin accounts. The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets: December 31, 2020 December 31, 2019 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 6.3 $ 4.1 $ 2.0 $ 5.4 Gross amount not offset on the balance sheet (2.9) (2.9) (0.4) (5.2) (1) Net amount $ 3.4 $ 1.2 $ 1.6 $ 0.2 |
Employee Benefits
Employee Benefits | 12 Months Ended |
Dec. 31, 2020 | |
Retirement Benefits [Abstract] | |
EMPLOYEE BENEFITS | EMPLOYEE BENEFITS Pension and Other Postretirement Employee Benefits We participate in WEC Energy Group's defined benefit pension plans and OPEB plans that cover substantially all of our employees. We are responsible for our share of the plan assets and obligations. The benefits for a portion of these plans are funded through irrevocable trusts, as allowed for income tax purposes. Our balance sheets reflect only the liabilities associated with our past and current employees and our share of the plan assets and obligations. We also offer medical, dental, and life insurance benefits to active employees and their dependents. We expense the costs of these benefits as incurred. Generally, employees who started with us after 1995 receive a benefit based on a percentage of their annual salary plus an interest credit, while employees who started before 1996 receive a benefit based upon years of service and final average salary. Management employees hired after December 31, 2014, and certain new represented employees hired after May 1, 2017, receive an annual company contribution to their 401(k) savings plan instead of being enrolled in the defined benefit plans. We use a year-end measurement date to measure the funded status of all of the pension and OPEB plans. Due to the regulated nature of our business, we have concluded that substantially all of the unrecognized costs resulting from the recognition of the funded status of the pension and OPEB plans qualify as a regulatory asset. The following tables provide a reconciliation of the changes in our share of the plans' benefit obligations and fair value of assets: Pension Benefits OPEB Benefits (in millions) 2020 2019 2020 2019 Change in benefit obligation Obligation at January 1 $ 1,148.3 $ 1,099.4 $ 207.3 $ 227.7 Service cost 12.5 12.6 4.2 4.5 Interest cost 37.7 45.2 6.8 9.5 Participant contributions — — 6.9 6.1 Plan amendments — — (2.5) 2.7 Net transfer from/to affiliates 0.5 (1) (5.3) (1) 0.2 (1) — Actuarial loss (gain) 94.1 81.5 (1.9) (29.8) Benefit payments (80.0) (85.1) (17.5) (16.2) Federal subsidy on benefits paid N/A N/A 1.2 1.1 Transfer — — 1.4 (2) 1.7 (2) Obligation at December 31 $ 1,213.1 $ 1,148.3 $ 206.1 $ 207.3 Change in fair value of plan assets Fair value at January 1 $ 1,094.6 $ 1,019.8 $ 228.5 $ 201.5 Actual return on plan assets 108.3 156.7 27.0 35.4 Employer contributions 3.9 3.8 — 1.7 Participant contributions — — 6.9 6.1 Net transfer from/to affiliates 0.4 (1) (0.6) (1) — — Benefit payments (80.0) (85.1) (17.5) (16.2) Fair value at December 31 $ 1,127.2 $ 1,094.6 $ 244.9 $ 228.5 Funded status at December 31 $ (85.9) $ (53.7) $ 38.8 $ 21.2 (1) Benefit obligations and plan assets were moved along with our employees who were transferred from/to affiliated entities. (2) Represents a premium medical account that was transferred into the OPEB benefit obligation. In 2020 and 2019, we had actuarial losses related to our pension benefit obligations of $94.1 million and $81.5 million, respectively, which were primarily due to decreases in our discount rates. The discount rate for our pension benefits was 2.63%, 3.39%, and 4.30% in 2020, 2019, and 2018, respectively. The 2020 actuarial gain related to our OPEB benefit obligation was not significant. In 2019, we had an actuarial gain related to our OPEB benefit obligation of $29.8 million, which was primarily due to better than expected claims and premiums experience, the use of new mortality tables, and the repeal of certain health insurance related taxes. These gains were partially offset by a decrease in our discount rate. The discount rate for our OPEB benefits was 3.40% and 4.30%, in 2019 and 2018, respectively. The amounts recognized on our balance sheets at December 31 related to the funded status of the benefit plans were as follows: Pension Benefits OPEB Benefits (in millions) 2020 2019 2020 2019 Other long-term assets $ — $ 6.1 $ 38.8 $ 21.2 Pension and OPEB obligations 85.9 59.8 — — Total net (liabilities) assets $ (85.9) $ (53.7) $ 38.8 $ 21.2 The accumulated benefit obligation for all defined benefit pension plans was $1,212.0 million and $1,147.0 million as of December 31, 2020 and 2019, respectively. The following table shows information for the pension plans with an accumulated benefit obligation in excess of plan assets. Amounts presented are as of December 31: (in millions) 2020 2019 Accumulated benefit obligation $ 1,212.0 $ 1,039.5 Fair value of plan assets 1,127.2 980.9 The following table shows information for pension plans with a projected benefit obligation in excess of plan assets. Amounts presented are as of December 31: (in millions) 2020 2019 Projected benefit obligation $ 1,213.1 $ 1,040.7 Fair value of plan assets 1,127.2 980.9 We do not have any OPEB plans with an accumulated benefit obligation in excess of plan assets. The following table shows the amounts that have not yet been recognized in our net periodic benefit cost as of December 31: Pension Benefits OPEB Benefits (in millions) 2020 2019 2020 2019 Net regulatory assets (liabilities) Net actuarial loss (gain) $ 475.1 $ 460.1 $ (117.9) $ (115.3) Prior service credits (2.2) (2.3) (3.4) (1.5) Total $ 472.9 $ 457.8 $ (121.3) $ (116.8) The components of net periodic benefit cost (credit) (including amounts capitalized to our balance sheets) for the years ended December 31 were as follows: Pension Benefits OPEB Benefits (in millions) 2020 2019 2018 2020 2019 2018 Service cost $ 12.5 $ 12.6 $ 13.2 $ 4.2 $ 4.5 $ 6.9 Interest cost 37.7 45.2 42.3 6.8 9.5 11.1 Expected return on plan assets (69.4) (72.4) (75.2) (15.7) (14.3) (15.5) Plan settlement 2.4 — — — — — Amortization of prior service cost (credit) (0.1) 0.5 0.8 (0.6) (1.9) (2.2) Amortization of net actuarial loss (gain) 37.8 28.0 38.0 (10.6) (2.1) — Net periodic benefit cost (credit) $ 20.9 $ 13.9 $ 19.1 $ (15.9) $ (4.3) $ 0.3 The weighted-average assumptions used to determine the benefit obligations for the plans were as follows for the years ended December 31: Pension Benefits OPEB Benefits 2020 2019 2020 2019 Discount rate 2.63% 3.39% 2.65% 3.40% Rate of compensation increase 4.00% 4.00% N/A N/A Interest credit rate 5.16% 5.16% N/A N/A Assumed medical cost trend rate (Pre 65) N/A N/A 5.85% 6.00% Ultimate trend rate (Pre 65) N/A N/A 5.00% 5.00% Year ultimate trend rate is reached (Pre 65) N/A N/A 2028 2028 Assumed medical cost trend rate (Post 65) N/A N/A 5.86% 6.04% Ultimate trend rate (Post 65) N/A N/A 5.00% 5.00% Year ultimate trend rate is reached (Post 65) N/A N/A 2028 2028 The weighted-average assumptions used to determine the net periodic benefit cost for the plans were as follows for the years ended December 31: Pension Benefits 2020 2019 2018 Discount rate 3.37% 4.30% 3.65% Expected return on plan assets 6.75% 7.00% 7.00% Rate of compensation increase 4.00% 3.40% 3.40% Interest credit rate 5.16% 5.18% 5.18% OPEB Benefits 2020 2019 2018 Discount rate 3.40% 4.30% 3.65% Expected return on plan assets 7.00% 7.25% 7.25% Assumed medical cost trend rate (Pre 65) 6.00% 6.25% 6.50% Ultimate trend rate (Pre 65) 5.00% 5.00% 5.00% Year ultimate trend rate is reached (Pre 65) 2028 2024 2024 Assumed medical cost trend rate (Post 65) 6.04% 6.12% 6.18% Ultimate trend rate (Post 65) 5.00% 5.00% 5.00% Year ultimate trend rate is reached (Post 65) 2028 2028 2028 WEC Energy Group consults with its investment advisors on an annual basis to help forecast expected long-term returns on plan assets by reviewing historical returns as well as calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the fund. For 2021, the expected return on asset assumption is 6.75% for the pension plan and 7.00% for the OPEB plan. Plan Assets Current pension trust assets and amounts which are expected to be contributed to the trusts in the future are expected to be adequate to meet pension payment obligations to current and future retirees. The Investment Trust Policy Committee oversees investment matters related to all of our funded benefit plans. The Committee works with external actuaries and investment consultants on an on-going basis to establish and monitor investment strategies and target asset allocations. Forecasted cash flows for plan liabilities are regularly updated based on annual valuation results. Target allocations are determined utilizing projected benefit payment cash flows and risk analyses of appropriate investments. They are intended to reduce risk, provide long-term financial stability for the plans and maintain funded levels which meet long-term plan obligations while preserving sufficient liquidity for near-term benefit payments. Our pension trust target asset allocations are 35% equity investments, 55% fixed income investments, and 10% private equity and real estate investments. The two OPEB trusts' target asset allocations are 50% equity investments and 50% fixed income investments, and 70% equity investments and 30% fixed income investments, respectively. Equity securities include investments in large-cap, mid-cap, and small-cap companies. Fixed income securities include corporate bonds of companies from diversified industries, mortgage and other asset backed securities, commercial paper, and United States Treasuries. Pension and OPEB plan investments are recorded at fair value. See Note 1(o), Fair Value Measurements, for more information regarding the fair value hierarchy and the classification of fair value measurements based on the types of inputs used. The following tables summarize the fair values of our investments by asset class: December 31, 2020 Pension Plan Assets OPEB Assets (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Asset Class Equity securities: United States equity $ 134.5 $ — $ — $ 134.5 $ 36.5 $ — $ — $ 36.5 International equity 106.0 — — 106.0 31.4 — — 31.4 Fixed income securities: (1) United States bonds — 516.5 — 516.5 26.3 58.8 — 85.1 International bonds — 43.6 — 43.6 — 4.3 — 4.3 $ 240.5 $ 560.1 $ — $ 800.6 $ 94.2 $ 63.1 $ — $ 157.3 Investments measured at net asset value $ 326.6 $ 87.6 Total $ 240.5 $ 560.1 $ — $ 1,127.2 $ 94.2 $ 63.1 $ — $ 244.9 (1) This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries. December 31, 2019 Pension Plan Assets OPEB Assets (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Asset Class Equity securities: United States equity $ 103.3 $ — $ — $ 103.3 $ 27.9 $ — $ — $ 27.9 International equity 98.4 — — 98.4 28.5 — — 28.5 Fixed income securities: (1) United States bonds 49.1 438.9 — 488.0 23.1 52.6 — 75.7 International bonds 27.7 29.2 — 56.9 5.8 2.9 — 8.7 $ 278.5 $ 468.1 $ — $ 746.6 $ 85.3 $ 55.5 $ — $ 140.8 Investments measured at net asset value $ 348.0 $ 87.7 Total $ 278.5 $ 468.1 $ — $ 1,094.6 $ 85.3 $ 55.5 $ — $ 228.5 (1) This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries. Cash Flows We expect to contribute $3.5 million to the pension plans and $0.1 million to the OPEB plans in 2021, dependent upon various factors affecting us, including our liquidity position and possible tax law changes. The following table shows the payments, reflecting expected future service, that we expect to make for pension and OPEB over the next 10 years: (in millions) Pension Benefits OPEB Benefits 2021 $ 87.8 $ 11.4 2022 84.5 11.3 2023 83.5 11.4 2024 80.0 11.1 2025 77.9 11.0 2026-2030 342.9 54.4 Savings Plans WEC Energy Group sponsors 401(k) savings plans that allow substantially all of our full-time employees to contribute a portion of their pre-tax and/or after-tax income in accordance with plan-specified guidelines. A percentage of employee contributions are matched by us through a contribution into the employee's savings plan account, up to certain limits. The 401(k) savings plans include an Employee Stock Ownership Plan. Certain employees receive an employer retirement contribution, which amounts are contributed to an employee's savings plan account. Total costs incurred under all of these plans was $11.4 million in 2020 and $11.9 million in both 2019 and 2018. |
Segment Information
Segment Information | 12 Months Ended |
Dec. 31, 2020 | |
Segment Reporting [Abstract] | |
SEGMENT INFORMATION | SEGMENT INFORMATION Effective December 31, 2020, we changed our measure of segment profitability from operating income to net income attributed to common shareholder. At December 31, 2020, we reported two segments, which are described below. Our utility segment includes our electric utility operations, including steam operations, and our natural gas utility operations. • Our electric utility operations are engaged in the generation, distribution, and sale of electricity to customers in southeastern Wisconsin (including metropolitan Milwaukee), east central Wisconsin, and northern Wisconsin. In addition, our steam operations produce, distribute, and sell steam to customers in metropolitan Milwaukee. Prior to April 1, 2019, we also provided electric service to Tilden, who owns an iron ore mine in the Upper Peninsula of Michigan. This customer was transferred to UMERC on April 1, 2019. • Our natural gas utility operations are engaged in the purchase, distribution, and sale of natural gas to retail customers and the transportation of customer-owned natural gas in southeastern, east central, and northern Wisconsin. Our non-utility operations are reported in the other segment. No items were reported in the other segment for any of the years presented. Prior to October 2018, our other segment included Bostco, our non-utility subsidiary that was originally formed to develop and invest in real estate. In March 2017, we sold substantially all of the remaining assets of Bostco, and Bostco was dissolved in October 2018. |
Variable Interest Entities
Variable Interest Entities | 12 Months Ended |
Dec. 31, 2020 | |
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Determination Methodology and Factors [Abstract] | |
VARIABLE INTEREST ENTITIES | VARIABLE INTEREST ENTITIES The primary beneficiary of a variable interest entity must consolidate the entity's assets and liabilities. In addition, certain disclosures are required for significant interest holders in variable interest entities. We assess our relationships with potential variable interest entities, such as our coal suppliers, natural gas suppliers, coal transporters, natural gas transporters, and other counterparties related to PPAs, investments, and joint ventures. In making this assessment, we consider, along with other factors, the potential that our contracts or other arrangements provide subordinated financial support, the obligation to absorb the entity's losses, the right to receive residual returns of the entity, and the power to direct the activities that most significantly impact the entity's economic performance. Power Purchase Agreement We have a PPA that represents a variable interest. This agreement is for 236 MWs of firm capacity from a natural gas-fired cogeneration facility, and we account for it as a finance lease. The agreement includes no minimum energy requirements over the remaining term of approximately one year. We have examined the risks of the entity, including operations, maintenance, dispatch, financing, fuel costs, and other factors, and have determined that we are not the primary beneficiary of the entity. We do not hold an equity or debt interest in the entity, and there is no residual guarantee associated with the PPA. We have $13.6 million of required capacity payments over the remaining term of this agreement. We believe that the required capacity payments under this contract will continue to be recoverable in rates, and our maximum exposure to loss is limited to these capacity payments. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2020 | |
Commitments and Contingencies Disclosure [Abstract] | |
COMMITMENTS AND CONTINGENCIES | COMMITMENTS AND CONTINGENCIES We have significant commitments and contingencies arising from our operations, including those related to unconditional purchase obligations, environmental matters, and enforcement and litigation matters. Unconditional Purchase Obligations We have obligations to distribute and sell electricity and natural gas to our customers and expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. The following table shows our minimum future commitments related to these purchase obligations as of December 31, 2020. Payments Due By Period (in millions) Date Contracts Extend Through Total Amounts Committed 2021 2022 2023 2024 2025 Later Years Electric utility: Nuclear 2033 $ 7,843.9 $ 501.1 $ 531.2 $ 563.1 $ 596.8 $ 632.6 $ 5,019.1 Coal supply and transportation 2023 548.9 226.8 176.4 145.7 — — — Purchased power 2051 59.6 12.3 10.5 7.6 3.6 2.3 23.3 Natural gas utility supply and transportation 2048 582.9 64.9 66.0 57.4 47.3 25.2 322.1 Total $ 9,035.3 $ 805.1 $ 784.1 $ 773.8 $ 647.7 $ 660.1 $ 5,364.5 Environmental Matters Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as SO 2 , NOx, fine particulates, mercury, and GHGs; water intake and discharges; management of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites. We have continued to pursue a proactive strategy to manage our environmental compliance obligations, including: • the development of additional sources of renewable electric energy supply; • the addition of improvements for water quality matters such as treatment technologies to meet regulatory discharge limits and improvements to our cooling water intake systems; • the addition of emission control equipment to existing facilities to comply with ambient air quality standards and federal clean air rules; • the protection of wetlands and waterways, threatened and endangered species, and cultural resources associated with utility construction projects; • the retirement of older coal-fired power plants and conversion to modern, efficient, natural gas generation, super-critical pulverized coal generation, and/or replacement with renewable generation; • the beneficial use of ash and other products from coal-fired and biomass generating units; • the remediation of former manufactured gas plant sites; and • the reduction of methane emissions across our natural gas distribution system by upgrading infrastructure. Air Quality National Ambient Air Quality Standards After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, creating a more stringent standard than the 2008 NAAQS. The 2015 ozone standard lowered the 8-hour limit for ground-level ozone. In December 2020, the EPA completed its 5-year review of the ozone standard and issued a final decision to retain, without any changes, the existing 2015 standard. The EPA issued final nonattainment area designations for the 2015 standard in April 2018. The following counties within our service territory were designated as partial nonattainment: Kenosha, Sheboygan, and Northern Milwaukee/Ozaukee. This re-designation was challenged in the D.C. Circuit Court of Appeals in Clean Wisconsin et al. v. U.S. Environmental Protection Agency. Petitioners in that case have argued that additional portions of Milwaukee, Waukesha, Ozaukee, and Washington Counties (among others) should be designated as nonattainment for ozone. In November 2019, the D.C. Circuit Court of Appeals heard oral arguments for that case. A decision was issued in July 2020 remanding the rule to the EPA for further evaluation. We expect that any subsequent EPA re-designation, if necessary, would take place in 2021. The State of Wisconsin submitted the "infrastructure" portion of its state implementation plan outlining how it will implement, maintain, and enforce the 2015 ozone standard. The plan is subject to EPA review and approval. Additionally, in January 2021, the WDNR issued a notice that it had prepared a draft economic impact analysis for proposed rules related to incorporating the 2015 standards into the state administrative code. We believe we are well positioned to meet the requirements associated with the ozone standard and do not expect to incur significant costs to comply with associated state or federal rules. In addition to the 2015 ozone standard, in December 2020, the EPA completed its 5-year review of the 2012 standard for particulate matter, including fine particulate matter. The EPA determined that no revisions were necessary to the current standard. All counties within our service territory are in attainment with the 2012 standards; however, we expect that the decision to retain the 2012 standards with no changes will be challenged by certain states and non-governmental organizations. Climate Change The ACE rule, effective since September 2019, was vacated by the D.C. Circuit Court of Appeals in January 2021. The ACE rule replaced the CPP and provided existing coal-fired generating units with standards for achieving GHG emission reductions. It is unclear what steps the EPA will take next. The EPA could either revive an updated version of the CPP or draft a new rule to regulate GHG emissions. In December 2018, the EPA proposed to revise the NSPS for GHG emissions from new, modified, and reconstructed fossil-fueled power plants. In the proposed rule, the EPA determined that the BSER for new, modified, and reconstructed coal units is highly efficient generation that would be equivalent to supercritical steam conditions for larger units and subcritical steam conditions for smaller units. This proposed BSER would replace the determination from the previous rule, which identified BSER as partial carbon capture and storage. In January 2021, the EPA finalized the NSPS but did not address the BSER as proposed in 2018. Instead, the EPA shifted the focus to finalizing a significant contribution finding for purposes of regulating source categories for GHG emissions. While the EPA confirmed that EGUs remain a listed source category, the EPA concluded that no other source category should be listed. The EPA based its conclusion on the fact that no other source category, except for EGUs, should contribute to GHG emissions above a 3% threshold. BSER may be addressed in a future action by the EPA. If the rule is not repealed, it will become effective in March 2021. Despite this uncertainty, WEC Energy Group continues to move forward on the ESG Progress Plan which is heavily focused on reducing GHG emissions. The ESG Progress Plan, which includes us, includes the retirement of older, fossil-fueled generation, to be replaced with the construction of zero-carbon-emitting renewable generation and natural gas-fired generation. In 2019, WEC Energy Group met and surpassed its original goal to reduce CO 2 emissions by 40% below 2005 levels by 2030. In July 2020, WEC Energy Group announced new goals to reduce CO 2 emissions from its electric generation by 70% below 2005 levels by 2030 and to be net carbon neutral by 2050. WEC Energy Group added a near-term goal in November 2020 to reduce CO 2 emissions by 55% below 2005 levels by 2025. We have already retired approximately 1,500 MW of coal-fired generation since the beginning of 2018. As part of the ESG Progress Plan, WEC Energy Group expects to retire approximately 1,800 MW of additional fossil-fueled generation by 2025 and to invest in low-cost renewable energy in Wisconsin. WEC Energy Group's plan is to replace a portion of the retired capacity by building and owning a combination of natural gas-fired generation and zero-carbon-emitting renewable generation facilities. WEC Energy Group also has a goal to decrease the rate of methane emissions from the natural gas distribution lines in its network by 30% per mile by the year 2030 from a 2011 baseline. WEC Energy Group was over half way toward meeting that goal at the end of 2020 . We are required to report our CO 2 equivalent emissions from the electric generating facilities we operate under the EPA Greenhouse Gases Reporting Program. Based upon our preliminary analysis of the data, we estimate that we will report CO 2 equivalent emissions of approximately 14.7 million metric tonnes to the EPA for 2020. The level of CO 2 and other GHG emissions varies from year to year and is dependent on the level of electric generation and mix of fuel sources, which is determined primarily by demand, the availability of the generating units, the unit cost of fuel consumed, and how our units are dispatched by MISO. We are also required to report CO 2 equivalent emissions related to the natural gas that our natural gas operations distribute and sell. Based upon our preliminary analysis of the data, we estimate that we will report CO 2 equivalent emissions of approximately 3.9 million metric tonnes to the EPA for 2020. National Emission Standards for Hazardous Air Pollutants – Major Source Classification In November 2020, the EPA published a final rule to eliminate the "once-in-always-in" policy regarding major and area source classifications under the National Emission Standards for Hazardous Air Pollutants. The final rule revised the definition of "major source" to allow for the reclassification as an area source when the source's potential to emit hazardous air pollutants meets certain criteria. Technical corrections to this final rule were published in December 2020. We do not expect the revisions to the major source classification will have a material impact on our financial condition or results of operations. Cross-State Air Pollution Rule Update Rule Revision In 2015, the EPA determined that several upwind states had failed to submit state implementation plans that addressed their "Good Neighbor" obligations (i.e., the states projected NOx emissions significantly contribute to a continuing downwind nonattainment and/or maintenance problem); therefore, by statute, the EPA was required to issue a federal implementation plan. In October 2020, the EPA proposed a CSAPR update rule revision that keeps nine of the 21 CSAPR affected states (including Wisconsin) as a Group 2 NOx ozone season trading program source and found that the prior CSAPR update is sufficient to meet its "Good Neighbor" obligations. No further NOx reductions would be needed within these nine states. We do not expect that the proposed rule, if finalized, will have a material impact on our financial condition or results of operations. Water Quality Clean Water Act Cooling Water Intake Structure Rule In August 2014, the EPA issued a final regulation under Section 316(b) of the Clean Water Act that requires the location, design, construction, and capacity of cooling water intake structures at existing power plants to reflect the BTA for minimizing adverse environmental impacts. The rule became effective in October 2014 and applies to all of our existing generating facilities with cooling water intake structures, except for the ERGS units, which were permitted under the rules governing new facilities. We have received BTA determinations for OC 5 through OC 8 and VAPP. Although we currently believe that existing technology at the PWGS satisfies the BTA requirements, final determinations will not be made until the discharge permit is renewed for this facility, which is expected to be in 2021. We anticipate that the permit renewal will be include a final BTA determination to address all of the Section 316(b) rule requirements. As a result of past capital investments completed to address Section 316(b) compliance, we believe our fleet overall is well positioned to meet the regulation and do not expect to incur significant additional costs to comply with this regulation. Steam Electric Effluent Limitation Guidelines The EPA's final 2015 ELG rule took effect in January 2016 and was modified in 2020 to revise the treatment technology requirements related to BATW and wet FGD wastewaters at existing facilities. The latest compliance date under the ELG rule is December 31, 2023. This rule created new requirements for several types of power plant wastewaters. The two new requirements that affect us relate to discharge limits for BATW and wet FGD wastewater. As a result of past capital investments, we believe our fleet is well positioned to meet the existing ELG regulations. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. There will, however, need to be modifications to the BATW systems at OC 7 and OC 8. Wastewater treatment system modifications will be required for wet FGD discharges and site wastewater from the OCPP and ERGS units. Based on engineering cost estimates, we expect that compliance with the ELG rule will require approximately $100 million in capital investment. Land Quality Manufactured Gas Plant Remediation We have identified sites at which we or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. We are responsible for the environmental remediation of these sites. We are also working with various state jurisdictions in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure. The future costs for detailed site investigation, future remediation, and monitoring are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation. Historically, our regulators have allowed us to recover incurred costs, net of insurance recoveries and recoveries from potentially responsible parties, associated with the remediation of manufactured gas plant sites. Accordingly, we have established regulatory assets for costs associated with these sites. We have established the following regulatory assets and reserves for manufactured gas plant sites as of December 31: (in millions) 2020 2019 Regulatory assets $ 18.5 $ 22.1 Reserves for future environmental remediation (1) 10.3 12.1 (1) Recorded within other long-term liabilities on our balance sheets. Renewables, Efficiency, and Conservation Wisconsin Legislation In 2005, Wisconsin enacted Act 141, which established a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources annually. We have achieved our required renewable energy percentage of 8.27% by constructing various wind parks, a biomass facility, and by also relying on renewable energy purchases. We continue to review our renewable energy portfolio and acquire cost-effective renewables as needed to meet our requirements on an ongoing basis. The PSCW administers the renewable program related to Act 141, and we fund the program, along with other utilities, based on 1.2% of our annual retail operating revenues. Enforcement and Litigation Matters We are involved in legal and administrative proceedings before various courts and agencies with respect to matters arising in the ordinary course of business. Although we are unable to predict the outcome of these matters, management believes that appropriate reserves have been established and that final settlement of these actions will not have a material impact on our financial condition or results of operations. |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | 12 Months Ended |
Dec. 31, 2020 | |
Supplemental Cash Flow Information [Abstract] | |
SUPPLEMENTAL CASH FLOW INFORMATION | SUPPLEMENTAL CASH FLOW INFORMATION Year Ended December 31 (in millions) 2020 2019 2018 Cash paid for interest, net of amount capitalized (1) $ 464.7 $ 475.2 $ 115.0 Cash paid for income taxes, net 101.2 45.8 17.7 Significant non-cash investing and financing transactions: Accounts payable related to construction costs 43.0 36.1 14.0 Receivable related to insurance proceeds for property damage (2) 2.7 — — (1) On January 1, 2019, we adopted ASU 2016-02, Leases (Topic 842). This ASU required us to prospectively change the classification of our finance lease payments on the income statement. As a result, during 2020 and 2019, we classified the interest component of our finance lease payments as cash paid for interest since it was included in interest expense on the income statement. However, prior to our adoption of Topic 842, the interest component was not considered cash paid for interest since it was not included in interest expense on the income statement. See Note 12, Leases, for more information on Topic 842 and our finance leases. (2) See Note 6, Property, Plant, and Equipment, for more information. |
Regulatory Environment
Regulatory Environment | 12 Months Ended |
Dec. 31, 2020 | |
Regulated Operations [Abstract] | |
REGULATORY ENVIRONMENT | REGULATORY ENVIRONMENT Coronavirus Disease – 2019 The global outbreak of COVID-19 was declared a pandemic by the WHO and the CDC. COVID-19 has spread globally, including throughout the United States and, in turn, our service territory. In response to the COVID-19 pandemic, Wisconsin declared a public health emergency and issued a shelter-in-place order, which has since been lifted. On March 24, 2020, the PSCW issued two orders requiring certain actions to ensure that essential utility services were, and continue to be, available to our customers. The first order required all public utilities in the state of Wisconsin, including us, to temporarily suspend disconnections, the assessment of late fees, and deposit requirements for all customer classes. In addition, it required utilities to reconnect customers that were previously disconnected, offer deferred payment arrangements to all customers, and streamline the application process for customers applying for utility service. In the second order issued on March 24, 2020, the PSCW authorized Wisconsin utilities to defer expenditures and certain foregone revenues resulting from compliance with the first order, and expenditures as otherwise incurred to ensure safe, reliable, and affordable access to utility services during the declared public health emergency. The PSCW has affirmed that this authorization for deferral includes the incremental increase in uncollectible expense above what is currently being recovered in rates. As we already have a cost recovery mechanism in place to recover uncollectible expense for residential customers, this new deferral only impacts the recovery of uncollectible expense for our commercial and industrial customers. See Note 4, Credit Losses, for information regarding changes to our allowance for credit losses related to COVID-19. As of December 31, 2020, amounts deferred related to the COVID-19 pandemic were not significant. The PSCW will review the recoverability and examine the prudency of any deferred amounts in future rate proceedings. On June 26, 2020, the PSCW issued a written order providing a timeline for the lifting of the temporary provisions required in the first March 24, 2020 order. Utilities were allowed to disconnect commercial and industrial customers and require deposits for new service as of July 25, 2020 and July 31, 2020, respectively. After August 15, 2020, utilities were no longer required to offer deferred payment arrangements to all customers. Additionally, utilities were authorized to reinstate late fees except for the period between the first order and this supplemental order. We resumed charging late payment fees in late August 2020. Late payment fees were not charged on outstanding balances that were billed between the first order and late August 2020. The PSCW extended the moratorium on disconnections of residential customers until November 1, 2020. In accordance with Wisconsin regulations, utilities are generally not allowed to disconnect residential customers for non-payment during the winter moratorium, which began on November 1 and ends on April 15. Utilities are allowed to continue assessing late fees during the winter moratorium. Tax Cuts and Jobs Act of 2017 Due to the Tax Legislation, we deferred for return to ratepayers, through future refunds, bill credits, or reductions in other regulatory assets, the estimated tax benefit of $1,102 million that resulted from the revaluation of deferred taxes. The Tax Legislation also reduced the corporate federal tax rate from a maximum of 35% to a 21% rate, effective January 1, 2018. In May 2018, the PSCW issued an order regarding the benefits associated with the Tax Legislation. The PSCW order required our electric utility operations to use 80% of the current 2018 and 2019 tax benefits to reduce our transmission regulatory asset. The remaining 20% was returned to electric customers in the form of bill credits. For our natural gas utility operations, the PSCW indicated that 100% of the current 2018 and 2019 tax benefits should be returned to natural gas customers in the form of bill credits. Regarding the net tax benefit associated with the revaluation of deferred taxes, amortization required in accordance with normalization accounting was used to reduce our transmission regulatory asset for our electric utility operations and was deferred for our natural gas utility operations. The timing and method of returning the remaining net tax benefit associated with the revaluation of deferred taxes was addressed in our rate order issued by the PSCW in December 2019. See the 2020 and 2021 Rates discussion below for more information. We previously served one retail electric customer in Michigan, and we reached a settlement with that customer. That settlement was approved by the MPSC in May 2018 and addressed all base rate impacts of the Tax Legislation, which were returned to the customer through bill credits. 2020 and 2021 Rates In March 2019, we filed an application with the PSCW to increase our retail electric, natural gas, and steam rates, effective January 1, 2020. In August 2019, we filed an application with the PSCW for approval of a settlement agreement entered into with certain intervenors to resolve several outstanding issues in our rate case. In December 2019, the PSCW issued a written order that approved the settlement agreement without material modification and addressed the remaining outstanding issues that were not included in the settlement agreement. The new rates became effective January 1, 2020. The final order reflects the following: 2020 Effective rate increase Electric (1) $ 15.3 million / 0.5% Gas (2) $ 10.4 million / 2.8% Steam $ 1.9 million / 8.6% ROE 10.0% Common equity component average on a financial basis 52.5% (1) Amount is net of certain deferred tax benefits from the Tax Legislation that were utilized to reduce near-term rate impact. The rate order reflects the majority of the unprotected deferred tax benefits from the Tax Legislation being amortized evenly over two years, which results in approximately $65 million of tax benefits being amortized in each of 2020 and 2021. The unprotected deferred tax benefits related to the unrecovered balances of our recently retired plants and our SSR regulatory asset were used to reduce the related regulatory asset. Unprotected deferred tax benefits by their nature are eligible to be returned to customers in a manner and timeline determined to be appropriate by the PSCW. (2) Amount includes certain deferred tax expense from the Tax Legislation. The rate order reflects all of the unprotected deferred tax expense from the Tax Legislation being amortized evenly over four years, which results in approximately $5 million of previously deferred tax expense being amortized each year. Unprotected deferred tax expense by its nature is eligible to be recovered from customers in a manner and timeline determined to be appropriate by the PSCW. In accordance with our rate order, we filed an application with the PSCW on July 20, 2020 requesting a financing order to securitize $100 million of Pleasant Prairie power plant's book value, plus the carrying costs accrued on the $100 million during the securitization process and related fees. On November 17, 2020, the PSCW issued a written order approving the application. The securitization will reduce the carrying costs for the $100 million, benefiting customers. We will continue having an earnings sharing mechanism through 2021. The earnings sharing mechanism was modified from its previous structure to one that is consistent with other Wisconsin investor-owned utilities. Under the new earnings sharing mechanism, if we earn above our authorized ROE: (i) we retain 100.0% of earnings for the first 25 basis points above the authorized ROE; (ii) 50.0% of the next 50 basis points is refunded to customers; and (iii) 100.0% of any remaining excess earnings is refunded to customers. In addition, the rate order also requires us to maintain residential and small commercial electric and natural gas customer fixed charges at previously authorized rates and to maintain the status quo for our electric market-based rate programs for large industrial customers through 2021. 2018 and 2019 Rates During April 2017, we, along with WPS and WG, filed an application with the PSCW for approval of a settlement agreement we made with several of our commercial and industrial customers regarding 2018 and 2019 base rates. In September 2017, the PSCW issued an order that approved the settlement agreement, which froze base rates through 2019 for our electric, natural gas, and steam customers. Based on the PSCW order, our authorized ROE remained at 10.2%, and our capital cost structure remained unchanged through 2019. In addition to freezing base rates, the settlement agreement extended and expanded the electric real-time market pricing program options for large commercial and industrial customers and mitigated the continued growth of certain escrowed costs during the base rate freeze period by accelerating the recognition of certain tax benefits. We were flowing through the tax benefit of our repair-related deferred tax liabilities in 2018 and 2019, to maintain certain regulatory asset balances at their December 31, 2017 levels. While we would typically follow the normalization accounting method and utilize the tax benefits of the deferred tax liabilities in rate making as an offset to rate base, benefiting customers over time, the federal tax code does allow for passing these tax repair-related benefits to ratepayers much sooner using the flow through accounting method. The flow through treatment of the repair-related deferred tax liabilities offset the negative income statement impact of holding the regulatory assets level, resulting in no change to net income. Pursuant to the settlement agreement, we also agreed to keep our earnings sharing mechanism in place through 2019. Under this earnings sharing mechanism, if we earned above our authorized ROE, 50% of the first 50 basis points of additional utility earnings were required to be refunded to customers. All utility earnings above the first 50 basis points were also required to be refunded to customers. Liquefied Natural Gas Facility In November, 2019, we filed an application with the PSCW requesting approval to construct a LNG facility. If approved, the facility would provide us with approximately one Bcf of natural gas supply to meet anticipated peak demand without requiring the construction of additional interstate pipeline capacity. This facility is expected to reduce the likelihood of constraints on our natural gas system during the highest demand days of winter. The project is estimated to cost approximately $185 million. A decision from the PSCW is expected in 2021, and commercial operation of the LNG facility is targeted for the end of 2023. Solar Generation Project In August 2019, we, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire an ownership interest in a proposed solar project, Badger Hollow II, that will be located in Iowa County, Wisconsin. Once constructed, we will own 100 MW of this project. Our share of the cost of this project is estimated to be $130 million. The PSCW issued a written order approving the acquisition of this project in March 2020. Commercial operation of Badger Hollow II is targeted for December 2022. |
Other Income, Net
Other Income, Net | 12 Months Ended |
Dec. 31, 2020 | |
Other Income and Expenses [Abstract] | |
OTHER INCOME, NET | OTHER INCOME, NET Total other income, net was as follows for the years ended December 31: (in millions) 2020 2019 2018 Non-service components of net periodic benefit costs $ 11.8 $ 9.2 $ 5.7 AFUDC – Equity 7.0 3.7 3.9 Other, net (0.3) 9.8 10.6 Other income, net $ 18.5 $ 22.7 $ 20.2 |
Quarterly Financial Information
Quarterly Financial Information (Unaudited) | 12 Months Ended |
Dec. 31, 2020 | |
Quarterly Financial Information Disclosure [Abstract] | |
QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | QUARTERLY FINANCIAL INFORMATION (Unaudited) (in millions) First Quarter Second Quarter Third Quarter Fourth Quarter Total 2020 Operating revenues $ 871.0 $ 769.5 $ 900.2 $ 826.3 $ 3,367.0 Operating income 247.0 188.6 244.6 180.3 860.5 Net income attributed to common shareholder 118.7 70.6 114.6 61.7 365.6 2019 Operating revenues $ 960.8 $ 791.7 $ 884.1 $ 860.1 $ 3,496.7 Operating income 222.9 182.6 201.1 153.6 760.2 Net income attributed to common shareholder 114.7 84.9 100.6 61.9 362.1 |
New Accounting Pronouncements
New Accounting Pronouncements | 12 Months Ended |
Dec. 31, 2020 | |
Accounting Standards Update and Change in Accounting Principle [Abstract] | |
NEW ACCOUNTING PRONOUNCEMENTS | NEW ACCOUNTING PRONOUNCEMENTS Cloud Computing In August 2018, the FASB issued ASU 2018-15, Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract. The standard allows entities who are customers in hosting arrangements that are service contracts to apply the existing internal-use software guidance to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. The guidance specifies classification for capitalizing implementation costs and related amortization expense within the financial statements and requires additional disclosures. The adoption of ASU 2018-15, effective January 1, 2020, did not have a significant impact on our financial statements and related disclosures. Disclosure Requirements for Defined Benefit Plans In August 2018, the FASB issued ASU 2018-14, Disclosure Framework: Changes to the Disclosure Requirements for Defined Benefit Plans. The pronouncement modifies the disclosure requirements for defined benefit pension and OPEB plans. The guidance removes disclosures that are no longer considered cost beneficial, clarifies the specific requirements of disclosures and adds disclosure requirements identified as relevant. The modifications affect annual period disclosures and must be applied on a retrospective basis to all periods presented. We adopted the disclosure provisions of ASU 2018-14, effective December 31, 2020. These disclosure modifications are included in Note 16, Employee Benefits. Simplifying the Accounting for Income Taxes In December 2019, the FASB issued ASU 2019-12, Simplifying the Accounting for Income Taxes. The new standard removes certain exceptions for performing intraperiod allocation and calculating income taxes in interim periods and also adds guidance to reduce complexity in certain areas, including recognizing deferred taxes for tax goodwill and allocating taxes to members of a consolidated group. The guidance was effective for annual and interim periods beginning after December 15, 2020. The adoption of ASU 2019-12, effective January 1, 2021, did not have a significant impact on our financial statements and related disclosures. Reference Rate Reform In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met. The amendments apply only to contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform. The amendments are effective for all entities as of March 12, 2020 through December 31, 2022. We are currently evaluating the impact this guidance may have on our financial statements and related disclosures. |
Schedule II - Valuation and Qua
Schedule II - Valuation and Qualifying Accounts | 12 Months Ended |
Dec. 31, 2020 | |
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract] | |
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | SCHEDULE II WISCONSIN ELECTRIC POWER COMPANY VALUATION AND QUALIFYING ACCOUNTS Allowance for Doubtful Accounts (in millions) Balance at Beginning of Period Expense (1) Deferral Net Write-offs (2) Balance at End of Period December 31, 2020 $ 38.1 $ 24.6 $ 14.8 $ (18.2) $ 59.3 December 31, 2019 40.9 32.7 (12.6) (22.9) 38.1 December 31, 2018 39.5 32.3 (9.1) (21.8) 40.9 (1) Net of recoveries. (2) Represents amounts written off to the reserve, net of adjustments to regulatory assets. |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2020 | |
Accounting Policies [Abstract] | |
Nature of operations | We are an electric, natural gas, and steam utility company that serves electric and natural gas customers in Wisconsin, and steam customers in metropolitan Milwaukee, Wisconsin. Prior to April 1, 2019, we also provided electric service to Tilden, who owns an iron ore mine in the Upper Peninsula of Michigan. This customer was transferred to UMERC on April 1, 2019 after UMERC's new natural gas-fired generation in the Upper Peninsula of Michigan began commercial operation. WEC Energy Group owns all of our outstanding common stock. |
Consolidation | As used in these notes, the term "financial statements" refers to the consolidated financial statements. This includes the income statements, balance sheets, statements of cash flows, and statements of equity, unless otherwise noted. |
Segment reporting | Through October 2018, we had one wholly owned subsidiary, Bostco. In March 2017, we sold substantially all of the remaining assets of Bostco, and, in October 2018, Bostco was dissolved. The financial statements include our accounts and the accounts of our former wholly owned subsidiary. |
Investments | Investments in companies not controlled by us, but over which we have significant influence regarding the operating and financial policies of the investee, are accounted for using the equity method. |
Use of estimates | We prepare our financial statements in conformity with GAAP. We make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates. |
Cash and cash equivalents | Cash and cash equivalents include marketable debt securities with an original maturity of three months or less. |
Operating revenues | The following discussion includes our significant accounting policies related to operating revenues. For additional required disclosures on disaggregation of operating revenues, see Note 3, Operating Revenues. Revenues from Contracts with Customers Electric Utility Operating Revenues Electricity sales to residential and commercial and industrial customers are generally accomplished through requirements contracts, which provide for the delivery of as much electricity as the customer needs. These contracts represent discrete deliveries of electricity and consist of one distinct performance obligation satisfied over time, as the electricity is delivered and consumed by the customer simultaneously. For our residential and commercial and industrial customers, our performance obligation is bundled to consist of both the sale and the delivery of the electric commodity. The transaction price of the performance obligations for residential and commercial and industrial customers is valued using the rates, charges, terms, and conditions of service included in our tariffs, which have been approved by the PSCW. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on the quantity of electricity delivered each month. Our retail electric rates in Wisconsin include base amounts for fuel and purchased power costs, which also impact our revenues. The electric fuel rules set by the PSCW allow us to defer, for subsequent rate recovery or refund, under- or over-collections of actual fuel and purchased power costs beyond a 2% price variance from the costs included in the rates charged to customers. We monitor the deferral of under-collected costs to ensure that it does not cause us to earn a greater ROE than authorized by the PSCW. In addition, our residential tariffs include a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. See Note 21, Regulatory Environment, for more information on how COVID-19 has affected our cost recovery mechanism. Wholesale customers who resell power can choose to either bundle capacity and electricity services together under one contract with a supplier or purchase capacity and electricity separately from multiple suppliers. Furthermore, wholesale customers can choose to have us provide generation to match the customer's load, similar to requirements contracts, or they can purchase specified quantities of electricity and capacity. Contracts with wholesale customers that include capacity bundled with the delivery of electricity contain two performance obligations, as capacity and electricity are often transacted separately in the marketplace at the wholesale level. When recognizing revenue associated with these contracts, the transaction price is allocated to each performance obligation based on its relative standalone selling price. Revenue is recognized as control of each individual component is transferred to the customer. Electricity is the primary product sold by our electric operations and represents a single performance obligation satisfied over time through discrete deliveries to a customer. Revenue from electricity sales is generally recognized as units are produced and delivered to the customer within the production month. Capacity represents the reservation of an electric generating facility and conveys the ability to call on a plant to produce electricity when needed by the customer. The nature of our performance obligation as it relates to capacity is to stand ready to deliver power. This represents a single performance obligation transferred over time, which generally represents a monthly obligation. Accordingly, capacity revenue is recognized on a monthly basis. The transaction price of the performance obligations for wholesale customers is valued using the rates, charges, terms, and conditions of service, which have been approved by the FERC. These wholesale rates include recovery of fuel and purchased power costs from customers on a one-for-one basis. For the majority of our wholesale customers, the price billed for energy and capacity is a formula-based rate. Formula-based rates initially set a customer's current year rates based on the previous year’s expenses. This is a predetermined formula derived from the utility’s costs and a reasonable rate of return. Because these rates are eventually trued up to reflect actual, current-year costs, they represent a form of variable consideration in certain circumstances. The variable consideration is estimated and recognized over time as wholesale customers receive and consume the capacity and electricity services. We are an active participant in the MISO Energy Markets, where we bid our generation into the Day Ahead and Real Time markets and procure electricity for our retail and wholesale customers at prices determined by the MISO Energy Markets. Purchase and sale transactions are recorded using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded as purchased power in cost of sales and net sales in a single hour are recorded as resale revenues on our income statements. For resale revenues, our performance obligation is created only when electricity is sold into the MISO Energy Markets. For all of our customers, consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days. Natural Gas Utility Operating Revenues We recognize natural gas utility operating revenues under requirements contracts with residential, commercial and industrial, and transportation customers served under our tariffs. Tariffs provide our customers with the standard terms and conditions, including rates, related to the services offered. Requirements contracts provide for the delivery of as much natural gas as the customer needs. These requirements contracts represent discrete deliveries of natural gas and constitute a single performance obligation satisfied over time. Our performance obligation is both created and satisfied with the transfer of control of natural gas upon delivery to the customer. For most of our customers, natural gas is delivered and consumed by the customer simultaneously. A performance obligation can be bundled to consist of both the sale and the delivery of the natural gas commodity. In certain of our service territories, customers can purchase the commodity from a third party. In this case, the performance obligation only includes the delivery of the natural gas to the customer. The transaction price of the performance obligations for our natural gas customers is valued using rates, charges, terms, and conditions of service included in our tariffs, which have been approved by the PSCW. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on natural gas delivered each month. Our tariffs include various rate mechanisms that allow us to recover or refund changes in prudently incurred costs from rate case-approved amounts. Our rates include a one-for-one recovery mechanism for natural gas commodity costs. We defer any difference between actual natural gas costs incurred and costs recovered through rates as a current asset or liability. The deferred balance is returned to or recovered from customers at intervals throughout the year. In addition, our residential tariffs include a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. See Note 21, Regulatory Environment, for more information on how COVID-19 has affected our cost recovery mechanism. Consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days. Other Operating Revenues Alternative Revenues Alternative revenues are created from programs authorized by regulators that allow us to record additional revenues by adjusting rates in the future, usually as a surcharge applied to future billings, in response to past activities or completed events. We record alternative revenues when the regulator-specified conditions for recognition have been met. We reverse these alternative revenues as the customer is billed, at which time this revenue is presented as revenues from contracts with customers. Our only alternative revenue program relates to the wholesale electric service that we provide to customers under market-based rates and FERC formula rates. The customer is charged a base rate each year based upon a formula using prior year actual costs and customer demand. A true-up is calculated based on the difference between the amount billed to customers for the demand component of their rates and what the actual cost of service was for the year. The true-up can result in an amount that we will recover from or refund to the customer. We consider the true-up portion of the wholesale electric revenues to be alternative revenues. |
Credit Losses | The following discussion includes our significant accounting policies related to credit losses. For additional required disclosures on credit losses, see Note 4, Credit Losses. Effective January 1, 2020, we adopted FASB ASU 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, using the modified retrospective transition method. This ASU amends the impairment model to utilize an expected loss methodology in place of the incurred loss methodology for financial instruments, including trade receivables. The amendment requires entities to consider a broader range of information to estimate expected credit losses, which may result in earlier recognition of loss. The cumulative effect of adopting this standard was not significant to our financial statements. Our exposure to credit losses is related to our accounts receivable and unbilled revenue balances, which are generated from the sale of electricity and natural gas by our regulated utility operations. Our regulated utility operations are included in our utility segment. No accounts receivable and unbilled revenue balances were reported in the other segment at December 31, 2020. We evaluate the collectability of our accounts receivable and unbilled revenue balances considering a combination of factors. For some of our larger customers and also in circumstances where we become aware of a specific customer's inability to meet its financial obligations to us, we record a specific allowance for credit losses against amounts due in order to reduce the net recognized receivable to the amount we reasonably believe will be collected. For all other customers, we use the accounts receivable aging method to calculate an allowance for credit losses. Using this method, we classify accounts receivable into different aging buckets and calculate a reserve percentage for each aging bucket based upon historical loss rates. The calculated reserve percentages are updated on at least an annual basis, in order to ensure recent macroeconomic, political, and regulatory trends are captured in the calculation, to the extent possible. Risks identified that we do not believe are reflected in the calculated reserve percentages, are assessed on a quarterly basis to determine whether further adjustments are required. We monitor our ongoing credit exposure through active review of counterparty accounts receivable balances against contract terms and due dates. Our activities include timely account reconciliation, dispute resolution and payment confirmation. To the extent possible, we work with customers with past due balances to negotiate payment plans, but will disconnect customers for non-payment as allowed by the PSCW if necessary, and employ collection agencies and legal counsel to pursue recovery of defaulted receivables. For our larger customers, detailed credit review procedures may be performed in advance of any sales being made. We sometimes require letters of credit, parental guarantees, prepayments or other forms of credit assurance from our larger customers to mitigate credit risk. See Note 21, Regulatory Environment, for information on certain regulatory actions that were and/or are being taken for the purpose of ensuring that essential utility services are available to our customers during the COVID-19 pandemic. |
Materials, supplies and inventories | Substantially all materials and supplies, fossil fuel, and natural gas in storage inventories are recorded using the weighted-average cost method of accounting. |
Regulatory assets and liabilities | The economic effects of regulation can result in regulated companies recording costs and revenues that are allowed in the rate-making process in a period different from the period they would have been recognized by a nonregulated company. When this occurs, regulatory assets and regulatory liabilities are recorded on the balance sheet. Regulatory assets represent deferred costs probable of recovery from customers that would have otherwise been charged to expense. Regulatory liabilities represent amounts that are expected to be refunded to customers in future rates or future costs already collected from customers in rates. The recovery or refund of regulatory assets and liabilities is based on specific periods determined by our regulators or occurs over the normal operating period of the related assets and liabilities. If a previously recorded regulatory asset is no longer probable of recovery, the regulatory asset is reduced to the amount considered probable of recovery, and the reduction is charged to expense in the current period. |
Property, plant, and equipment | We record property, plant, and equipment at cost. Cost includes material, labor, overhead, and both debt and equity components of AFUDC. Additions to and significant replacements of property are charged to property, plant, and equipment at cost; minor items are charged to other operation and maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired. We record straight-line depreciation expense over the estimated useful life of utility property using depreciation rates approved by the PSCW that include estimates for salvage value and removal costs. Annual utility composite depreciation rates were 3.19%, 3.11%, and 3.18% in 2020, 2019, and 2018, respectively. We capitalize certain costs related to software developed or obtained for internal use and record these costs to amortization expense over the estimated useful life of the related software, which ranges from 5 to 15 years. If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statement. Third parties reimburse us for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs are recorded as a reduction to property, plant, and equipment. |
AFUDC | AFUDC is included in utility plant accounts and represents the cost of borrowed funds (AFUDC – Debt) used during plant construction, and a return on shareholders' capital (AFUDC – Equity) used for construction purposes. AFUDC – Debt is recorded as a reduction of interest expense, and AFUDC – Equity is recorded in other income, net.Approximately 50% of our retail jurisdictional CWIP expenditures are subject to the AFUDC calculation. Our average AFUDC retail rates were 8.68% for 2020, and 8.45% for 2019 and 2018. Our average AFUDC wholesale rates were 5.39%, 5.11%, and 3.63% for 2020, 2019, and 2018, respectively. |
Asset impairment | We periodically assess the recoverability of certain long-lived assets when factors indicate the carrying value of such assets may be impaired or such assets are planned to be sold. These assessments require significant assumptions and judgments by management. Long-lived assets that would be subject to an impairment assessment generally include any assets within regulated operations that may not be fully recovered from our customers as a result of regulatory decisions that will be made in the future. An impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds the fair value of the asset. The carrying amount of an asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. An impairment loss is measured as the excess of the carrying amount of the asset in comparison to the fair value of the asset.When it becomes probable that a generating unit will be retired before the end of its useful life, we assess whether the generating unit meets the criteria for abandonment accounting. Generating units that are considered probable of abandonment are expected to cease operations in the near term, significantly before the end of their original estimated useful lives. If a generating unit meets the applicable criteria to be considered probable of abandonment, and the unit has been abandoned, we assess the likelihood of recovery of the remaining net book value of that generating unit at the end of each reporting period. If it becomes probable that regulators will disallow full recovery as well as a return on the remaining net book value of a generating unit that is either abandoned or probable of being abandoned, an impairment loss may be required. An impairment loss would be recorded if the remaining net book value of the generating unit is greater than the present value of the amount expected to be recovered from ratepayers, using an incremental borrowing rate. |
Asset retirement obligations | We recognize, at fair value, legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and normal operation of the assets. An ARO liability is recorded, when incurred, for these obligations as long as the fair value can be reasonably estimated, even if the timing or method of settling the obligation is unknown. The associated retirement costs are capitalized as part of the related long-lived asset and are depreciated over the useful life of the asset. The ARO liabilities are accreted each period using the credit-adjusted risk-free interest rates associated with the expected settlement dates of the AROs. These rates are determined when the obligations are incurred. Subsequent changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or a decrease to the carrying amount of the liability and the associated capitalized retirement costs. We recognize regulatory assets or liabilities for the timing differences between when we recover an ARO in rates and when we recognize the associated retirement costs. |
Stock-based compensation | Our employees participate in the WEC Energy Group stock-based compensation plans. In accordance with the WEC Energy Group shareholder approved Omnibus Stock Incentive Plan, WEC Energy Group provides long-term incentives through its equity interests to its non-employee directors, officers, and other key employees. The plan provides for the granting of stock options, restricted stock, performance shares, and other stock-based awards. Awards may be paid in WEC Energy Group common stock, cash, or a combination thereof. The number of shares of WEC Energy Group common stock authorized for issuance under the plan was 34.3 million. Stock-based compensation expense is allocated to us based on the outstanding awards held by our employees and our allocation of labor costs. Awards classified as equity awards are measured based on their grant-date fair value. Awards classified as liability awards are recorded at fair value each reporting period. We account for forfeitures as they occur, rather than estimating potential future forfeitures and recording them over the vesting period. Stock Options Our employees are granted WEC Energy Group non-qualified stock options that generally vest on a cliff-basis after three years. The exercise price of a stock option under the plan cannot be less than 100% of the fair market value of WEC Energy Group common stock on the grant date. Historically, all stock options have been granted with an exercise price equal to the fair market value of WEC Energy Group common stock on the date of the grant. Options vest immediately upon retirement, death, or disability; however, they may not be exercised within six months of the grant date except in the event of a change in control. Options expire no later than 10 years from the date of grant. WEC Energy Group stock options are classified as equity awards. The fair value of each stock option was calculated using a binomial option-pricing model. The following table shows the estimated weighted-average fair value per stock option granted to our employees along with the weighted-average assumptions used in the valuation models: 2020 2019 2018 Stock options granted 59,511 59,404 81,730 Estimated weighted-average fair value per stock option $ 10.82 $ 8.60 $ 7.26 Assumptions used to value the options: Risk-free interest rate 1.6% – 1.9% 2.5% – 2.7% 1.6% – 2.5% Dividend yield 3.0 % 3.6 % 3.5 % Expected volatility 16.0 % 17.0 % 18.0 % Expected life (years) 8.6 8.5 5.1 The risk-free interest rate was based on the United States Treasury interest rate with a term consistent with the expected life of the stock options. The dividend yield was based on WEC Energy Group's dividend rate at the time of the grant and historical stock prices. Expected volatility and expected life assumptions were based on WEC Energy Group's historical experience. Restricted Shares WEC Energy Group restricted shares granted to our employees have a vesting period of three years with one-third of the award vesting on each anniversary of the grant date. The restricted shares are classified as equity awards. Performance Units Officers and other key employees are granted performance units under the WEC Energy Group Performance Unit Plan. Under the plan, the ultimate number of units that will be awarded is dependent on WEC Energy Group's total shareholder return (stock price appreciation plus dividends) as compared to the total shareholder return of a peer group of companies over three years, as well as other performance metrics as may be determined by the Compensation Committee. Participants may earn between 0% and 175% of the performance unit award based on WEC Energy Group's total shareholder return. Pursuant to the terms of the plan, these percentages can be adjusted upwards or downwards based on WEC Energy Group's performance against additional performance measures, if any, adopted by the Compensation Committee. Performance units also accrue forfeitable dividend equivalents in the form of additional performance units. All grants of performance units are settled in cash and are accounted for as liability awards accordingly. The fair value of the performance units reflects our estimate of the final expected value of the awards, which is based on WEC Energy Group's stock price and performance achievement under the terms of the award. Stock-based compensation costs are generally recorded over the performance period, which is three years. |
Stock-based compensation - forfeitures | We account for forfeitures as they occur, rather than estimating potential future forfeitures and recording them over the vesting period |
Leases | In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which revised the previous guidance (Topic 840) regarding accounting for leases. Revisions include requiring a lessee to recognize a lease asset and a lease liability on its balance sheet for each lease, including operating leases with an initial term greater than 12 months. In addition, required quantitative and qualitative disclosures related to lease agreements were expanded. As required, we adopted Topic 842 effective January 1, 2019. We utilized the following practical expedients, which were available under ASU 2016-02, in our adoption of the new lease guidance. • We did not reassess whether any expired or existing contracts were leases or contained leases. • We did not reassess the lease classification for any expired or existing leases (that is, all leases that were classified as operating leases in accordance with Topic 840 continue to be classified as operating leases, and all leases that were classified as capital leases in accordance with Topic 840 are classified as finance leases). • We did not reassess the accounting for initial direct costs for any existing leases. We did not elect the practical expedient allowing entities to account for the nonlease components in lease contracts as part of the single lease component to which they were related. Instead, in accordance with ASC 842-10-15-31, our policy is to account for each lease component separately from the nonlease components of the contract. We did not elect the practical expedient to use hindsight in determining the lease term and in assessing impairment of our right of use assets. No impairment losses were included in the measurement of our right of use assets upon our adoption of Topic 842. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842, which is an amendment to ASU 2016-02. Land easements (also commonly referred to as rights of way) represent the right to use, access or cross another entity's land for a specified purpose. This guidance permits an entity to elect a transitional practical expedient, to be applied consistently, to not evaluate under Topic 842 land easements that were already in existence or had expired at the time of the entity's adoption of Topic 842. Once Topic 842 is adopted, an entity is required to apply Topic 842 prospectively to all new (or modified) land easements to determine whether the arrangement should be accounted for as a lease. We elected this practical expedient, resulting in none of our land easements being treated as leases upon our adoption of Topic 842. In July 2018, the FASB issued ASU 2018-11, Leases (Topic 842): Targeted Improvements, which amends ASU 2016-02 and allows entities the option to initially apply Topic 842 at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption, if required. We used the optional transition method to apply this guidance as of January 1, 2019, rather than as of the earliest period presented. We did not require a cumulative-effect adjustment upon adoption of Topic 842. Right of use assets and related lease liabilities related to our operating leases that were recorded upon adoption of Topic 842 were each $13.0 million. Regarding our finance leases, while the adoption of Topic 842 changed the classification of expense related to these leases on a prospective basis, it had no impact on the total amount of lease expense recorded, and did not impact the finance lease assets and related liability amounts recorded on our balance sheets. Significant Judgments and Other Information We are currently party to several easement agreements that allow us access to land we do not own for the purpose of constructing and maintaining certain electric power and natural gas equipment. The majority of payments we make related to easements relate to our wind parks. We have not classified our easements as leases because we view the entire parcel of land specified in our easement agreements to be the identified asset, not just that portion of the parcel that contains our easement. As such, we have concluded that we do not control the use of an identified asset related to our easement agreements, nor do we obtain substantially all of the economic benefits associated with these shared-use assets. As of February 25, 2021, we have not entered into any material leases that have not yet commenced. |
Income taxes | We follow the liability method in accounting for income taxes. Accounting guidance for income taxes requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax balances to reflect tax rate changes. We are required to assess the likelihood that our deferred tax assets would expire before being realized. If we conclude that certain deferred tax assets are likely to expire before being realized, a valuation allowance would be established against those assets. GAAP requires that, if we conclude in a future period that it is more likely than not that some or all of the deferred tax assets would be realized before expiration, we reverse the related valuation allowance in that period. Any change to the allowance, as a result of a change in judgment about the realization of deferred tax assets, is reported in income tax expense. ITCs associated with regulated operations are deferred and amortized over the life of the assets. We are included in WEC Energy Group's consolidated federal and state income tax returns. In accordance with our tax allocation agreement with WEC Energy Group, we are allocated income tax payments and refunds based upon our separate tax computation. See Note 13, Income Taxes, for more information. We recognize interest and penalties accrued related to unrecognized tax benefits in income tax expense in our income statements. |
Fair value measurements | Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods. Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. |
Derivative instruments | We use derivatives as part of our risk management program to manage the risks associated with the price volatility of purchased power, generation, and natural gas costs for the benefit of our customers. Our approach is non-speculative and designed to mitigate risk. Our regulated hedging programs are approved by the PSCW. We record derivative instruments on our balance sheets as assets or liabilities measured at fair value, unless they qualify for the normal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy related physical and financial contracts in our regulated operations that qualify as derivatives, the PSCW allows the effects of fair value accounting to be offset to regulatory assets and liabilities. We classify derivative assets and liabilities as current or long-term on our balance sheets based on the maturities of the underlying contracts. Cash flows from derivative activities are presented in the same category as the item being hedged within operating activities on our statements of cash flows. |
Guarantees | We follow the guidance of the Guarantees Topic of the FASB ASC, which requires, under certain circumstances, that the guarantor recognize a liability for the fair value of the obligation undertaken in issuing the guarantee at its inception. |
Employee benefits | The costs of pension and OPEB plans are expensed over the periods during which employees render service. These costs are distributed among WEC Energy Group's subsidiaries based on current employment status and actuarial calculations, as applicable. Our regulators allow recovery in rates for our net periodic benefit cost calculated under GAAP. |
Customer deposits and credit balances | When utility customers apply for new service, they may be required to provide a deposit for the service. Customer deposits are recorded within other current liabilities on our balance sheets.Utility customers can elect to be on a budget plan. Under this type of plan, a monthly installment amount is calculated based on estimated annual usage. During the year, the monthly installment amount is reviewed by comparing it to actual usage. If necessary, an adjustment is made to the monthly amount. Annually, the budget plan is reconciled to actual annual usage. Payments in excess of actual customer usage are recorded within other current liabilities on our balance sheets. |
Environmental remediation costs | We are subject to federal and state environmental laws and regulations that in the future may require us to pay for environmental remediation at sites where we have been, or may be, identified as a potentially responsible party. Loss contingencies may exist for the remediation of hazardous substances at various potential sites, including coal combustion residual landfills and manufactured gas plant sites. See Note 7, Asset Retirement Obligations, for more information regarding coal combustion residual landfills and Note 19, Commitments and Contingencies, for more information regarding manufactured gas plant sites. We record environmental remediation liabilities when site assessments indicate remediation is probable and we can reasonably estimate the loss or a range of losses. The estimate includes both our share of the liability and any additional amounts that will not be paid by other potentially responsible parties or the government. When possible, we estimate costs using site-specific information but also consider historical experience for costs incurred at similar sites. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws governing the remediation process may change, as well as site conditions, potentially affecting the cost of remediation. We have received approval to defer certain environmental remediation costs, as well as estimated future costs, through a regulatory asset. The recovery of deferred costs is subject to the PSCW's approval. We review our estimated costs of remediation annually for our manufactured gas plant sites and coal combustion residual landfills. We adjust the liabilities and related regulatory assets, as appropriate, to reflect the new cost estimates. Any material changes in cost estimates are adjusted throughout the year. |
Customer concentrations of credit risk | The geographic concentration of our customers did not contribute significantly to our overall exposure to credit risk. We periodically review customers' credit ratings, financial statements, and historical payment performance and require them to provide collateral or other security as needed. Our credit risk exposure is mitigated by our recovery mechanisms for uncollectible expense discussed in Note 1(d), Operating Revenues. As a result, we did not have any significant concentrations of credit risk at December 31, 2020. In addition, there were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2020. |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Accounting Policies [Abstract] | |
Schedule of inventory | Our inventory as of December 31 consisted of: (in millions) 2020 2019 Materials and supplies $ 136.5 $ 148.3 Fossil fuel 57.1 51.1 Natural gas in storage 25.9 30.4 Total $ 219.5 $ 229.8 |
Allowance for funds used during construction | We recorded the following AFUDC for the years ended December 31: (in millions) 2020 2019 2018 AFUDC – Debt $ 2.6 $ 1.5 $ 1.5 AFUDC – Equity 7.0 3.7 3.9 |
Schedule of assumptions used to estimate the fair value of stock options granted | The following table shows the estimated weighted-average fair value per stock option granted to our employees along with the weighted-average assumptions used in the valuation models: 2020 2019 2018 Stock options granted 59,511 59,404 81,730 Estimated weighted-average fair value per stock option $ 10.82 $ 8.60 $ 7.26 Assumptions used to value the options: Risk-free interest rate 1.6% – 1.9% 2.5% – 2.7% 1.6% – 2.5% Dividend yield 3.0 % 3.6 % 3.5 % Expected volatility 16.0 % 17.0 % 18.0 % Expected life (years) 8.6 8.5 5.1 |
Related Parties (Tables)
Related Parties (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Related Party Transactions [Abstract] | |
Schedule of related party transactions balance sheet information | Our balance sheets included the following receivables and payables for services provided to or received from ATC: (in millions) 2020 2019 Accounts receivable Services provided to ATC $ 1.2 $ 1.7 Amounts due from ATC for transmission infrastructure upgrades 1.6 (1) — Accounts payable Services received from ATC 19.2 19.9 (1) The transmission infrastructure upgrades related to the construction of our new solar project, Badger Hollow II. |
Schedule of activity associated with related party transactions | The following table shows activity associated with our related party transactions for the years ended December 31: (in millions) 2020 2019 2018 Transactions with WPS Natural gas related purchases from WPS (1) $ 1.5 $ 2.0 $ 1.9 Charges to WPS for services and other items (2) 12.5 13.2 17.8 Charges from WPS for services and other items (2) 8.3 9.3 10.9 Transactions with WG Natural gas related purchases from WG (1) 5.7 5.4 5.3 Charges to WG for services and other items (2) 42.3 41.1 59.0 (6) Charges from WG for services and other items (2) 31.7 30.1 32.6 Transactions with UMERC Electric sales to UMERC (3) — 7.9 29.6 Charges to UMERC for services and other items (2) 9.8 10.5 15.8 Transactions with Bluewater Storage service fees 12.9 14.2 15.0 Natural gas related sales to Bluewater (1) 2.6 2.3 — Charges to Bluewater for services and other items (2) 3.0 0.2 — Transactions with We Power Lease payments and other lease-related charges from We Power (4) 404.3 401.1 396.5 Charges to We Power for services and other items (2) 4.5 7.1 10.6 Transactions with WBS Charges to WBS for services and other items (2) 67.8 102.6 61.5 Charges from WBS for services and other items (2) 152.9 205.3 243.4 (5) Transactions with ATC Charges to ATC for services and construction 15.6 14.9 13.9 Charges from ATC for network transmission services 229.3 230.6 232.0 Net refund from ATC related to FERC ROE orders 7.3 — — Refund from ATC related to a FERC audit — — 15.4 (1) Includes amounts related to the purchase or sale of natural gas and/or pipeline capacity. (2) Includes amounts charged for services, pass through costs, asset and liability transfers, and other items in accordance with the approved AIAs. As required by FERC regulations for centralized service companies, WBS renders services at cost. Services provided by any regulated subsidiary to another regulated subsidiary or WBS are priced at cost, and any services provided by a regulated subsidiary to a nonregulated subsidiary are priced at the greater of cost or fair market value. (3) On March 31, 2019, UMERC's new natural gas-fired generation in the Upper Peninsula of Michigan began commercial operation. Prior to its generating units achieving commercial operation, UMERC purchased a portion of its power from us. (4) We make lease payments to We Power, another subsidiary of WEC Energy Group, for PWGS Units 1 and 2 and ERGS Units 1 and 2. See Note 12, Leases, for more information. (5) Includes $10.0 million for the transfer of certain benefit-related liabilities to WBS and $59.8 million for the transfer of certain software assets from WBS. (6) Includes $5.3 million for the transfer of certain software assets to WG. |
Operating Revenues (Tables)
Operating Revenues (Tables) - Utility | 12 Months Ended |
Dec. 31, 2020 | |
Disaggregation of Operating Revenues | |
Operating revenues disaggregated by revenue source | The following tables present our operating revenues disaggregated by revenue source for our utility segment. We do not have any revenues associated with our other segment. We disaggregate revenues into categories that depict how the nature, amount, timing, and uncertainty of revenues and cash flows are affected by economic factors. For our utility segment, revenues are further disaggregated by electric and natural gas operations and then by customer class. Each customer class within our electric and natural gas operations have different expectations of service, energy and demand requirements, and can be impacted differently by regulatory activities within their jurisdictions. Wisconsin Electric Power Company Consolidated Year Ended December 31 (in millions) 2020 2019 2018 Electric utility $ 3,000.2 $ 3,088.3 $ 3,212.7 Natural gas utility 358.6 399.0 405.1 Total revenues from contracts with customers 3,358.8 3,487.3 3,617.8 Other operating revenues 8.2 9.4 7.2 Total operating revenues $ 3,367.0 $ 3,496.7 $ 3,625.0 |
Revenues from contracts with customers | Electric | |
Disaggregation of Operating Revenues | |
Operating revenues disaggregated by revenue source | The following table disaggregates electric utility operating revenues into customer class: Electric Utility Operating Revenues Year Ended December 31 (in millions) 2020 2019 2018 Residential $ 1,289.2 $ 1,206.7 $ 1,220.8 Small commercial and industrial 955.4 1,010.9 1,020.0 Large commercial and industrial 527.3 583.9 656.6 Other 19.9 20.6 20.7 Total retail revenues 2,791.8 2,822.1 2,918.1 Wholesale 78.8 93.8 108.5 Resale 108.4 132.7 153.7 Steam 21.3 23.3 24.1 Other utility revenues (0.1) 16.4 8.3 Total electric utility operating revenues $ 3,000.2 $ 3,088.3 $ 3,212.7 |
Revenues from contracts with customers | Natural gas | |
Disaggregation of Operating Revenues | |
Operating revenues disaggregated by revenue source | The following table disaggregates natural gas utility operating revenues into customer class: Natural Gas Utility Operating Revenues Year Ended December 31 (in millions) 2020 2019 2018 Residential $ 238.4 $ 261.7 $ 264.3 Commercial and industrial 97.1 121.2 126.3 Total retail revenues 335.5 382.9 390.6 Transport 16.3 13.6 13.4 Other utility revenues (1) 6.8 2.5 1.1 Total natural gas utility operating revenues $ 358.6 $ 399.0 $ 405.1 (1) Includes amounts collected from customers for purchased gas adjustment costs. |
Other operating revenues | |
Disaggregation of Operating Revenues | |
Operating revenues disaggregated by revenue source | Other operating revenues consist of the following: Year Ended December 31 (in millions) 2020 2019 2018 Late payment charges (1) $ 5.6 $ 8.2 $ 8.2 Rental revenues 2.9 2.9 2.9 Alternative revenues (2) (0.3) (1.7) (3.9) Total other operating revenues $ 8.2 $ 9.4 $ 7.2 (1) The reduction in late payment charges is a result of a regulatory order from the PSCW in response to the COVID-19 pandemic, which includes the suspension of late payment charges during a designated time period. See Note 21, Regulatory Environment, for more information. (2) Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. Negative amounts can also result from revenues to be refunded to customers subject to wholesale true-ups, as discussed in Note 1(d), Operating Revenues. |
Credit Losses (Tables)
Credit Losses (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Credit Loss [Abstract] | |
Schedule of gross receivables and related allowances for credit losses | The table below shows our gross third-party receivable balances and related allowance for credit losses at December 31, 2020. (in millions) Accounts receivable and unbilled revenues $ 525.4 Allowance for credit losses 59.3 Accounts receivable and unbilled revenues, net (1) $ 466.1 Total accounts receivable, net – past due greater than 90 days (1) $ 56.3 Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1) 98.2 % (1) Our exposure to credit losses for certain regulated utility customers is mitigated by a regulatory mechanism we have in place. Specifically, our residential tariffs include a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. As a result, at December 31, 2020, $239.8 million, or 51.4%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses. In addition, we have received specific orders related to the deferral of certain costs (including credit losses) incurred as a result of the COVID-19 pandemic. The additional protections related to our December 31, 2020 accounts receivable and unbilled revenue balances provided by these orders are subject to prudency reviews and are still being assessed. They are not reflected in the percentage in the above table or this note. See Note 21, Regulatory Environment, for more information on these orders. |
Rollforward of the allowances for credit losses | A rollforward of the allowance for credit losses for the year ended December 31, 2020, is included below: (in millions) Balance at December 31, 2019 $ 38.1 Provision for credit losses 24.6 Provision for credit losses deferred for future recovery or refund 14.8 Write-offs charged against the allowance (38.8) Recoveries of amounts previously written off 20.6 Balance at December 31, 2020 $ 59.3 |
Regulatory Assets and Liabili_2
Regulatory Assets and Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Schedule of regulatory assets | The following regulatory assets were reflected on our balance sheets as of December 31: (in millions) 2020 2019 See Note Regulatory assets (1) (2) Finance leases $ 985.5 $ 930.5 12 Plant retirements 669.8 688.8 Pension and OPEB costs (3) 477.0 459.4 16 Income tax related items 392.6 403.2 13 SSR (4) 135.6 151.5 21 Securitization 105.2 100.0 21 Other, net 37.6 21.8 Total regulatory assets $ 2,803.3 $ 2,755.2 (1) Based on prior and current rate treatment, we believe it is probable that we will continue to recover from customers the regulatory assets in this table. In accordance with GAAP, our regulatory assets do not include the allowance for ROE that is capitalized for regulatory purposes. This allowance was $14.5 million and $9.9 million at December 31, 2020 and 2019, respectively. (2) As of December 31, 2020, we had $8.1 million of regulatory assets not earning a return, $8.9 million of regulatory assets earning a return based on short-term interest rates, and $135.6 million of regulatory assets earning a return based on long-term interest rates. The regulatory assets not earning a return relate to certain environmental remediation costs. The other regulatory assets in the table either earn a return at our weighted average cost of capital or the cash has not yet been expended, in which case the regulatory assets are offset by liabilities. (3) Primarily represents the unrecognized future pension and OPEB costs related to our defined benefit pension and OPEB plans. We are authorized recovery of these regulatory assets over the average remaining service life of each plan. (4) The rate order we received from the PSCW in December 2019 authorized recovery of the SSR regulatory asset over a 15-year period that began on January 1, 2020. |
Schedule of regulatory liabilities | The following regulatory liabilities were reflected on our balance sheets as of December 31: (in millions) 2020 2019 See Note Regulatory liabilities Income tax related items $ 806.7 $ 888.1 13 Removal costs (1) 677.2 654.7 Pension and OPEB benefits (2) 132.1 120.4 16 Electric transmission costs (3) (4) 61.7 38.6 Uncollectible expense 15.5 28.8 4 Energy efficiency programs (5) 2.9 15.8 Other, net 11.8 9.8 Total regulatory liabilities $ 1,707.9 $ 1,756.2 Balance sheet presentation Other current liabilities $ 4.2 $ 12.0 Regulatory liabilities 1,703.7 1,744.2 Total regulatory liabilities $ 1,707.9 $ 1,756.2 (1) Represents amounts collected from customers to cover the future cost of property, plant, and equipment removals that are not legally required. Legal obligations related to the removal of property, plant, and equipment are recorded as AROs. See Note 7, Asset Retirement Obligations, for more information on our legal obligations. (2) Primarily represents the unrecognized future pension and OPEB benefits related to our defined benefit pension and OPEB plans. We will amortize these regulatory liabilities into net periodic benefit cost over the average remaining service life of each plan. (3) Based on orders received from the PSCW, we were required to apply the refunds due to customers from our earnings sharing mechanism to our electric transmission escrow during 2019. As a result, $38.6 million of our earnings sharing refunds were reflected in our electric transmission regulatory liability at December 31, 2019. We had no refunds due to customers from our earnings sharing mechanism at December 31, 2020. (4) In accordance with the PSCW's approval of escrow accounting for our ATC and MISO network transmission expenses, we defer as a regulatory asset or liability the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. (5) Represents amounts refundable to customers related to programs designed to meet energy efficiency standards. |
Schedule of activity related to severance liability | Activity related to this severance liability for the years ended December 31 was as follows: (in millions) 2020 2019 2018 Severance liability at January 1 $ 2.1 $ 12.9 $ 25.8 Severance payments (0.1) (5.7) (9.9) Other (1.3) (5.1) (3.0) Total severance liability at December 31 $ 0.7 $ 2.1 $ 12.9 |
Property, Plant, and Equipment
Property, Plant, and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment -Balances | Property, plant, and equipment consisted of the following at December 31: (in millions) 2020 2019 Electric – generation $ 3,612.8 $ 3,623.4 Electric – distribution 5,328.4 5,086.4 Natural gas – distribution, storage, and transmission 1,444.2 1,358.0 Other 864.6 814.7 Less: Accumulated depreciation 3,568.5 3,397.0 Net 7,681.5 7,485.5 CWIP 253.2 190.8 Net utility and non-utility property, plant, and equipment 7,934.7 7,676.3 Property under finance leases 3,135.9 3,077.4 Less: Accumulated amortization 1,280.7 1,167.0 Net leased facilities 1,855.2 1,910.4 Total property, plant, and equipment $ 9,789.9 $ 9,586.7 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of changes to asset retirement obligations | The following table shows changes to our AROs during the years ended December 31: (in millions) 2020 2019 2018 Balance as of January 1 $ 65.0 $ 70.7 $ 68.3 Accretion 2.3 3.6 3.3 Additions and revisions to estimated cash flows (11.1) (1) (8.4) (1) 1.0 Liabilities settled (1.7) (0.9) (1.9) Balance as of December 31 $ 54.5 $ 65.0 $ 70.7 |
Common Equity (Tables)
Common Equity (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Stockholders' Equity Note [Abstract] | |
Schedule of stock-based compensation expense and related deferred tax benefit recognized in income | The following table summarizes our pre-tax stock-based compensation expense, including amounts allocated from WBS, and the related tax benefit recognized in income for the years ended December 31: (in millions) 2020 2019 2018 Stock options $ 2.1 $ 1.7 $ 2.0 Restricted stock 2.7 2.7 3.0 Performance units 9.7 17.9 9.6 Stock-based compensation expense $ 14.5 $ 22.3 $ 14.6 Related tax benefit $ 4.0 $ 6.1 $ 4.0 |
Schedule of stock option activity | The following is a summary of our employees' WEC Energy Group stock option activity during 2020: Stock Options Number of Options Weighted-Average Exercise Price Weighted-Average Remaining Contractual Life (in years) Aggregate Intrinsic Value (in millions) Outstanding as of January 1, 2020 626,261 $ 48.98 Granted 59,511 $ 91.49 Exercised (121,624) $ 42.60 Transferred (75,668) $ 47.30 Forfeited (3,367) $ 67.33 Outstanding as of December 31, 2020 485,113 $ 55.93 5.1 $ 17.5 Exercisable as of December 31, 2020 330,010 $ 46.45 3.7 $ 15.0 |
Schedule of restricted stock activity | The following is a summary of our employees' WEC Energy Group restricted stock activity during 2020: Restricted Shares Number of Shares Weighted-Average Grant Date Fair Value Outstanding and unvested as of January 1, 2020 9,736 $ 65.58 Granted 4,371 $ 91.49 Released (4,791) $ 63.95 Transferred 64 $ 66.78 Forfeited (748) $ 73.02 Outstanding and unvested as of December 31, 2020 8,632 $ 78.97 |
Preferred Stock (Tables)
Preferred Stock (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Class of Stock Disclosures [Abstract] | |
Schedule of preferred stock by class | The following table shows preferred stock authorized and outstanding at December 31, 2020 and 2019: (in millions, except share and per share amounts) Shares Authorized Shares Outstanding Redemption Price Per Share Total $100 par value, Six Per Cent. Preferred Stock 45,000 44,498 — $ 4.4 $100 par value, Serial Preferred Stock 3.60% Series 2,286,500 260,000 $ 101 26.0 $25 par value, Serial Preferred Stock 5,000,000 — — — Total $ 30.4 |
Short-Term Debt and Lines of _2
Short-Term Debt and Lines of Credit (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Short-term Debt [Abstract] | |
Short-term debt balances and their corresponding weighted-average interest rates | The following table shows our short-term borrowings and their corresponding weighted-average interest rates as of December 31: (in millions, except percentages) 2020 2019 Commercial paper Amount outstanding at December 31 $ 292.0 $ 115.5 Average interest rate on amounts outstanding at December 31 0.21 % 2.03 % |
Schedule of Revolving Credit Facilities | The information in the table below relates to our revolving credit facility used to support our commercial paper borrowing program, including remaining available capacity under this facility as of December 31: (in millions) Maturity 2020 Revolving credit facility October 2022 $ 500.0 Less: Letters of credit issued inside credit facility $ 1.0 Commercial paper outstanding 292.0 Available capacity under existing agreement $ 207.0 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Debt Disclosure [Abstract] | |
Schedule of long-term debt instruments | The following table is a summary of our long-term debt outstanding as of December 31: (in millions) Interest Rate Year Due 2020 2019 Debentures (unsecured) 2.95% 2021 300.0 300.0 2.05% 2024 300.0 300.0 3.10% 2025 250.0 250.0 6.50% 2028 150.0 150.0 5.625% 2033 335.0 335.0 5.70% 2036 300.0 300.0 3.65% 2042 250.0 250.0 4.25% 2044 250.0 250.0 4.30% 2045 250.0 250.0 4.30% 2048 300.0 300.0 6.875% 2095 100.0 100.0 Total 2,785.0 2,785.0 Unamortized debt issuance costs (7.4) (8.0) Unamortized discount, net (16.4) (17.8) Total long-term debt, including current portion 2,761.2 2,759.2 Current portion of long-term debt (300.0) — Total long-term debt 2,461.2 2,759.2 |
Schedule of future maturities of long-term debt outstanding | The following table shows the future maturities of our long-term debt outstanding as of December 31, 2020: (in millions) 2021 $ 300.0 2022 — 2023 — 2024 300.0 2025 250.0 Thereafter 1,935.0 Total $ 2,785.0 |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Leases [Abstract] | |
Schedule of lease expense and supplemental cash flow information for leases | The components of lease expense and supplemental cash flow information related to our leases for the year ended December 31 are as follows: (in millions) 2020 2019 2018 Finance lease expense Amortization of right of use assets (1) $ 59.2 $ 20.6 Interest on lease liabilities (2) 347.1 350.9 Capital lease expense (3) $ 371.0 Operating lease expense (4) 2.6 2.6 2.7 Total lease expense $ 408.9 $ 374.1 $ 373.7 Other information Cash paid for amounts included in the measurement of lease liabilities Operating cash flows for finance/capital leases (5) $ 347.1 $ 350.9 $ 381.4 Operating cash flows for operating leases $ 2.6 $ 2.6 $ 2.7 Financing cash flows for finance leases (5) $ 58.3 $ 50.5 Non-cash activities: Right of use assets obtained in exchange for finance lease liabilities $ 22.8 $ — Right of use assets obtained in exchange for operating lease liabilities $ — $ 13.0 Weighted-average remaining lease term – finance leases 18.0 years 18.6 years Weighted-average remaining lease term – operating leases 29.9 years 25.0 years Weighted-average discount rate – finance leases (6) 13.8 % 13.9 % Weighted average discount rate – operating leases (6) 4.6 % 4.5 % (1) Amortization of right of use assets was included as a component of depreciation and amortization expense for the years ended December 31, 2020 and 2019. (2) Interest on lease liabilities was included as a component of interest expense for the years ended December 31, 2020 and 2019. (3) Capital lease expense related to the long-term PPA was included in cost of sales and total capital lease cost related to the PWGS and ERGS units was included in other operation and maintenance for the year ended December 31, 2018. (4) Operating lease expense was included as a component of operation and maintenance for the years ended December 31, 2020, 2019, and 2018. (5) Prior to our adoption of Topic 842 on January 1, 2019, all cash flows related to finance leases were recorded as a component of operating cash flows. (6) Because our operating leases do not provide an implicit rate of return, we used the fully collateralized incremental borrowing rates based upon information available for similarly rated companies in determining the present value of lease payments for our operating leases. For our PPA and the PWGS and ERGS units that meet the definition of a finance lease, the rate implicit in the lease was readily determinable. For our solar land leases that are finance leases, we used the fully collateralized incremental borrowing rates based upon information available for similarly rated companies in determining the present value of lease payments. |
Schedule of finance lease right of use assets | The following table summarizes our finance lease right of use assets, which were included in property, plant and equipment on our balance sheets: (in millions) December 31, 2020 December 31, 2019 Long-term power purchase commitment Under finance lease $ 140.3 $ 140.3 Accumulated amortization (132.3) (126.6) Total long-term power purchase commitment $ 8.0 $ 13.7 PWGS Under finance lease $ 749.4 $ 742.7 Accumulated amortization (399.6) (367.6) Total PWGS $ 349.8 $ 375.1 ERGS Under finance lease $ 2,223.4 $ 2,194.4 Accumulated amortization (748.6) (672.8) Total ERGS $ 1,474.8 $ 1,521.6 Badger Hollow II land leases Under finance leases $ 22.8 $ — Accumulated amortization (0.2) — Total Badger Hollow II land leases $ 22.6 $ — Total finance lease right of use assets $ 1,855.2 $ 1,910.4 |
Schedule of future minimum lease payments for operating and finance leases | Future minimum lease payments under our finance and operating leases and the present value of our net minimum lease payments as of December 31, 2020, were as follows: (in millions) Total Operating Leases Power Purchase Commitment PWGS ERGS Badger Hollow II Total Finance Leases 2021 $ 0.7 9.4 $ 99.4 $ 297.9 $ 0.3 $ 407.0 2022 0.5 4.2 99.4 297.8 0.3 401.7 2023 0.5 — 99.4 297.6 0.7 397.7 2024 0.5 — 99.3 297.6 0.7 397.6 2025 0.5 — 99.1 297.5 0.7 397.3 Thereafter 12.7 — 589.4 4,316.5 55.0 4,960.9 Total minimum lease payments 15.4 13.6 1,086.0 5,804.9 57.7 6,962.2 Less: Interest (7.0) (1.5) (487.1) (3,597.8) (34.6) (4,121.0) Present value of minimum lease payments 8.4 12.1 598.9 2,207.1 23.1 2,841.2 Less: Short-term lease liabilities (0.3) (8.1) (28.9) (29.8) — (66.8) Long-term lease liabilities $ 8.1 $ 4.0 $ 570.0 $ 2,177.3 $ 23.1 $ 2,774.4 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Income Tax Disclosure [Abstract] | |
Summary of income tax expense | The following table is a summary of income tax expense (benefit) for each of the years ended December 31: (in millions) 2020 2019 2018 Current tax expense (benefit) $ 112.2 $ 73.4 $ (56.2) Deferred income tax expense (benefit), net (66.0) (128.9) 0.1 ITC, net (1.5) (2.3) (0.8) Total income tax expense (benefit) $ 44.7 $ (57.8) $ (56.9) |
Statutory rate reconciliation | The provision for income taxes for each of the years ended December 31 differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes as a result of the following: 2020 2019 2018 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Amount Effective Tax Rate Statutory federal income tax $ 86.2 21.0 % $ 63.9 21.0 % $ 63.3 21.0 % State income taxes net of federal tax benefit 26.5 6.5 % 20.2 6.6 % 19.6 6.5 % Federal excess deferred tax amortization – Wisconsin unprotected (1) (42.7) (10.4) % — — % — — % Federal excess deferred tax amortization (2) (23.2) (5.7) % (16.1) (5.3) % (15.5) (5.1) % Wind PTCs (11.1) (2.7) % (9.3) (3.0) % (9.4) (3.1) % AFUDC – Equity (1.5) (0.4) % (0.8) (0.3) % (0.8) (0.3) % ITC restored (1.5) (0.4) % (2.3) (0.8) % (0.8) (0.3) % Domestic production activities deferral 6.3 1.5 % 6.1 2.0 % 6.1 2.0 % Tax repairs (3) 3.3 0.8 % (122.9) (40.1) % (120.7) (39.9) % Other, net 2.4 0.7 % 3.4 1.0 % 1.3 0.4 % Total income tax expense (benefit) $ 44.7 10.9 % $ (57.8) (18.9) % $ (56.9) (18.8) % (1) In accordance with the rate order received from the PSCW in December 2019, we are amortizing these unprotected deferred tax benefits over periods ranging from two years to four years, to reduce near-term rate impacts to our customers. The decrease in income tax expense related to the amortization of the deferred tax benefits is offset by a decrease in revenue as the benefits are returned to customers, resulting in no impact on net income. (2) The Tax Legislation required us to remeasure our deferred income taxes and we began to amortize the resulting excess protected deferred income taxes beginning in 2018 in accordance with normalization requirements. The decrease in income tax expense related to the amortization of the deferred tax benefits is offset by a decrease in revenue as the benefits are returned to customers, resulting in no impact on net income. |
Components of deferred income taxes | The components of deferred income taxes as of December 31 were as follows: (in millions) 2020 2019 Deferred tax assets Tax gross up – regulatory items $ 132.6 $ 152.7 Deferred revenues 124.6 126.8 Future tax benefits 14.8 41.0 Other 82.3 64.5 Total deferred tax assets $ 354.3 $ 385.0 Deferred tax liabilities Property-related $ 1,334.4 $ 1,368.9 Deferred costs – Plant retirements 237.4 215.5 Employee benefits and compensation 49.3 55.8 Deferred costs – SSR 47.7 51.1 Other 42.7 41.1 Total deferred tax liabilities 1,711.5 1,732.4 Deferred tax liability, net $ 1,357.2 $ 1,347.4 |
Summary of Operating Loss Carryforwards | The components of net deferred tax assets associated with federal and state tax benefit carryforwards as of December 31, 2020 and 2019 are summarized in the tables below: 2020 (in millions) Gross Value Deferred Tax Effect Earliest Year of Expiration Future tax benefits as of December 31, 2020 Federal tax credit $ — $ 14.8 2040 Balance as of December 31, 2020 $ — $ 14.8 2019 (in millions) Gross Value Deferred Tax Effect Earliest Year of Expiration Future tax benefits as of December 31, 2019 Federal tax credit $ — $ 37.1 2037 State net operating loss 52.4 3.3 2035 Other state benefits — 0.6 2019 Balance as of December 31, 2019 $ 52.4 $ 41.0 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Fair Value Disclosures [Abstract] | |
Schedule of fair value of assets and liabilities measured on a recurring basis categorized by level within the fair value hierarchy | The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy: December 31, 2020 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 3.0 $ 0.8 $ — $ 3.8 FTRs — — 1.1 1.1 Coal contracts — 1.4 — 1.4 Total derivative assets $ 3.0 $ 2.2 $ 1.1 $ 6.3 Derivative liabilities Natural gas contracts $ 2.9 $ 0.6 $ — $ 3.5 Coal contracts — 0.6 — 0.6 Total derivative liabilities $ 2.9 $ 1.2 $ — $ 4.1 December 31, 2019 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 0.4 $ — $ — $ 0.4 FTRs — — 1.5 1.5 Coal contracts — 0.1 — 0.1 Total derivative assets $ 0.4 $ 0.1 $ 1.5 $ 2.0 Derivative liabilities Natural gas contracts $ 5.2 $ — $ — $ 5.2 Coal contracts — 0.2 — 0.2 Total derivative liabilities $ 5.2 $ 0.2 $ — $ 5.4 |
Reconcilation of changes in fair value of items categorized as level 3 measurements | The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy at December 31: (in millions) 2020 2019 2018 Balance at the beginning of the period $ 1.5 $ 4.4 $ 2.4 Purchases 3.1 6.8 9.4 Settlements (3.5) (9.7) (7.4) Balance at the end of the period $ 1.1 $ 1.5 $ 4.4 |
Schedule of carrying value and estimated fair value of financial instruments not recorded at fair value | The following table shows the financial instruments included on our balance sheets that are not recorded at fair value: December 31, 2020 December 31, 2019 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock $ 30.4 $ 32.3 $ 30.4 $ 29.5 Long-term debt, including current portion 2,761.2 3,451.8 2,759.2 3,209.5 |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of derivative assets and liabilities | The following table shows our derivative assets and derivative liabilities, along with their classification on our balance sheets. None of our derivatives are designated as hedging instruments. December 31, 2020 December 31, 2019 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Other current Natural gas contracts $ 3.7 $ 3.2 $ 0.4 $ 5.1 FTRs 1.1 — 1.5 — Coal contracts 1.4 0.5 — 0.2 Total other current 6.2 3.7 1.9 5.3 Other long-term Natural gas contracts 0.1 0.3 — 0.1 Coal contracts — 0.1 0.1 — Total other long-term 0.1 0.4 0.1 0.1 Total $ 6.3 $ 4.1 $ 2.0 $ 5.4 |
Schedule of estimated notional sales volumes and realized gains (losses) | Our estimated notional sales volumes and realized gains (losses) were as follows for the years ended: December 31, 2020 December 31, 2019 December 31, 2018 (in millions) Volumes Gains (Losses) Volumes Gains (Losses) Volumes Gains Natural gas contracts 62.1 Dth $ (15.1) 61.6 Dth $ (11.3) 53.4 Dth $ 9.7 Petroleum products contracts — gallons — — gallons — 4.2 gallons 1.2 FTRs 20.9 MWh 2.5 21.7 MWh 8.7 21.2 MWh 3.4 Total $ (12.6) $ (2.6) $ 14.3 |
Schedule of net derivative instruments | The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets: December 31, 2020 December 31, 2019 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 6.3 $ 4.1 $ 2.0 $ 5.4 Gross amount not offset on the balance sheet (2.9) (2.9) (0.4) (5.2) (1) Net amount $ 3.4 $ 1.2 $ 1.6 $ 0.2 |
Employee Benefits (Tables)
Employee Benefits (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Retirement Benefits [Abstract] | |
Reconciliation of the changes in the plans' benefit obligations and fair value of assets | The following tables provide a reconciliation of the changes in our share of the plans' benefit obligations and fair value of assets: Pension Benefits OPEB Benefits (in millions) 2020 2019 2020 2019 Change in benefit obligation Obligation at January 1 $ 1,148.3 $ 1,099.4 $ 207.3 $ 227.7 Service cost 12.5 12.6 4.2 4.5 Interest cost 37.7 45.2 6.8 9.5 Participant contributions — — 6.9 6.1 Plan amendments — — (2.5) 2.7 Net transfer from/to affiliates 0.5 (1) (5.3) (1) 0.2 (1) — Actuarial loss (gain) 94.1 81.5 (1.9) (29.8) Benefit payments (80.0) (85.1) (17.5) (16.2) Federal subsidy on benefits paid N/A N/A 1.2 1.1 Transfer — — 1.4 (2) 1.7 (2) Obligation at December 31 $ 1,213.1 $ 1,148.3 $ 206.1 $ 207.3 Change in fair value of plan assets Fair value at January 1 $ 1,094.6 $ 1,019.8 $ 228.5 $ 201.5 Actual return on plan assets 108.3 156.7 27.0 35.4 Employer contributions 3.9 3.8 — 1.7 Participant contributions — — 6.9 6.1 Net transfer from/to affiliates 0.4 (1) (0.6) (1) — — Benefit payments (80.0) (85.1) (17.5) (16.2) Fair value at December 31 $ 1,127.2 $ 1,094.6 $ 244.9 $ 228.5 Funded status at December 31 $ (85.9) $ (53.7) $ 38.8 $ 21.2 (1) Benefit obligations and plan assets were moved along with our employees who were transferred from/to affiliated entities. (2) Represents a premium medical account that was transferred into the OPEB benefit obligation. |
Amounts recognized on the balance sheets at December 31 related to the funded status of the benefit plans | The amounts recognized on our balance sheets at December 31 related to the funded status of the benefit plans were as follows: Pension Benefits OPEB Benefits (in millions) 2020 2019 2020 2019 Other long-term assets $ — $ 6.1 $ 38.8 $ 21.2 Pension and OPEB obligations 85.9 59.8 — — Total net (liabilities) assets $ (85.9) $ (53.7) $ 38.8 $ 21.2 |
Information for pension plans with an accumulated benefit obligation in excess of plan assets | The following table shows information for the pension plans with an accumulated benefit obligation in excess of plan assets. Amounts presented are as of December 31: (in millions) 2020 2019 Accumulated benefit obligation $ 1,212.0 $ 1,039.5 Fair value of plan assets 1,127.2 980.9 |
Information for pension plans with a projected benefit obligation in excess of plan assets | The following table shows information for pension plans with a projected benefit obligation in excess of plan assets. Amounts presented are as of December 31: (in millions) 2020 2019 Projected benefit obligation $ 1,213.1 $ 1,040.7 Fair value of plan assets 1,127.2 980.9 |
Amounts that had not yet been recognized in the entity's net periodic benefit cost | The following table shows the amounts that have not yet been recognized in our net periodic benefit cost as of December 31: Pension Benefits OPEB Benefits (in millions) 2020 2019 2020 2019 Net regulatory assets (liabilities) Net actuarial loss (gain) $ 475.1 $ 460.1 $ (117.9) $ (115.3) Prior service credits (2.2) (2.3) (3.4) (1.5) Total $ 472.9 $ 457.8 $ (121.3) $ (116.8) |
Schedule of the components of net periodic benefit cost | The components of net periodic benefit cost (credit) (including amounts capitalized to our balance sheets) for the years ended December 31 were as follows: Pension Benefits OPEB Benefits (in millions) 2020 2019 2018 2020 2019 2018 Service cost $ 12.5 $ 12.6 $ 13.2 $ 4.2 $ 4.5 $ 6.9 Interest cost 37.7 45.2 42.3 6.8 9.5 11.1 Expected return on plan assets (69.4) (72.4) (75.2) (15.7) (14.3) (15.5) Plan settlement 2.4 — — — — — Amortization of prior service cost (credit) (0.1) 0.5 0.8 (0.6) (1.9) (2.2) Amortization of net actuarial loss (gain) 37.8 28.0 38.0 (10.6) (2.1) — Net periodic benefit cost (credit) $ 20.9 $ 13.9 $ 19.1 $ (15.9) $ (4.3) $ 0.3 |
Weighted-average assumptions used to determine benefit obligations and net periodic benefit cost for the plans | The weighted-average assumptions used to determine the benefit obligations for the plans were as follows for the years ended December 31: Pension Benefits OPEB Benefits 2020 2019 2020 2019 Discount rate 2.63% 3.39% 2.65% 3.40% Rate of compensation increase 4.00% 4.00% N/A N/A Interest credit rate 5.16% 5.16% N/A N/A Assumed medical cost trend rate (Pre 65) N/A N/A 5.85% 6.00% Ultimate trend rate (Pre 65) N/A N/A 5.00% 5.00% Year ultimate trend rate is reached (Pre 65) N/A N/A 2028 2028 Assumed medical cost trend rate (Post 65) N/A N/A 5.86% 6.04% Ultimate trend rate (Post 65) N/A N/A 5.00% 5.00% Year ultimate trend rate is reached (Post 65) N/A N/A 2028 2028 The weighted-average assumptions used to determine the net periodic benefit cost for the plans were as follows for the years ended December 31: Pension Benefits 2020 2019 2018 Discount rate 3.37% 4.30% 3.65% Expected return on plan assets 6.75% 7.00% 7.00% Rate of compensation increase 4.00% 3.40% 3.40% Interest credit rate 5.16% 5.18% 5.18% OPEB Benefits 2020 2019 2018 Discount rate 3.40% 4.30% 3.65% Expected return on plan assets 7.00% 7.25% 7.25% Assumed medical cost trend rate (Pre 65) 6.00% 6.25% 6.50% Ultimate trend rate (Pre 65) 5.00% 5.00% 5.00% Year ultimate trend rate is reached (Pre 65) 2028 2024 2024 Assumed medical cost trend rate (Post 65) 6.04% 6.12% 6.18% Ultimate trend rate (Post 65) 5.00% 5.00% 5.00% Year ultimate trend rate is reached (Post 65) 2028 2028 2028 |
Investments recorded at fair value, by asset class | The following tables summarize the fair values of our investments by asset class: December 31, 2020 Pension Plan Assets OPEB Assets (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Asset Class Equity securities: United States equity $ 134.5 $ — $ — $ 134.5 $ 36.5 $ — $ — $ 36.5 International equity 106.0 — — 106.0 31.4 — — 31.4 Fixed income securities: (1) United States bonds — 516.5 — 516.5 26.3 58.8 — 85.1 International bonds — 43.6 — 43.6 — 4.3 — 4.3 $ 240.5 $ 560.1 $ — $ 800.6 $ 94.2 $ 63.1 $ — $ 157.3 Investments measured at net asset value $ 326.6 $ 87.6 Total $ 240.5 $ 560.1 $ — $ 1,127.2 $ 94.2 $ 63.1 $ — $ 244.9 (1) This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries. December 31, 2019 Pension Plan Assets OPEB Assets (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Asset Class Equity securities: United States equity $ 103.3 $ — $ — $ 103.3 $ 27.9 $ — $ — $ 27.9 International equity 98.4 — — 98.4 28.5 — — 28.5 Fixed income securities: (1) United States bonds 49.1 438.9 — 488.0 23.1 52.6 — 75.7 International bonds 27.7 29.2 — 56.9 5.8 2.9 — 8.7 $ 278.5 $ 468.1 $ — $ 746.6 $ 85.3 $ 55.5 $ — $ 140.8 Investments measured at net asset value $ 348.0 $ 87.7 Total $ 278.5 $ 468.1 $ — $ 1,094.6 $ 85.3 $ 55.5 $ — $ 228.5 (1) This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries. |
Schedule of expected future benefit payments | The following table shows the payments, reflecting expected future service, that we expect to make for pension and OPEB over the next 10 years: (in millions) Pension Benefits OPEB Benefits 2021 $ 87.8 $ 11.4 2022 84.5 11.3 2023 83.5 11.4 2024 80.0 11.1 2025 77.9 11.0 2026-2030 342.9 54.4 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of minimum future commitments related to purchase obligations | The following table shows our minimum future commitments related to these purchase obligations as of December 31, 2020. Payments Due By Period (in millions) Date Contracts Extend Through Total Amounts Committed 2021 2022 2023 2024 2025 Later Years Electric utility: Nuclear 2033 $ 7,843.9 $ 501.1 $ 531.2 $ 563.1 $ 596.8 $ 632.6 $ 5,019.1 Coal supply and transportation 2023 548.9 226.8 176.4 145.7 — — — Purchased power 2051 59.6 12.3 10.5 7.6 3.6 2.3 23.3 Natural gas utility supply and transportation 2048 582.9 64.9 66.0 57.4 47.3 25.2 322.1 Total $ 9,035.3 $ 805.1 $ 784.1 $ 773.8 $ 647.7 $ 660.1 $ 5,364.5 |
Schedule of regulatory assets and reserves related to manufactured gas plant sites | We have established the following regulatory assets and reserves for manufactured gas plant sites as of December 31: (in millions) 2020 2019 Regulatory assets $ 18.5 $ 22.1 Reserves for future environmental remediation (1) 10.3 12.1 (1) Recorded within other long-term liabilities on our balance sheets. |
Supplemental Cash Flow Inform_2
Supplemental Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Supplemental Cash Flow Information [Abstract] | |
Schedule of supplemental cash flow information | Year Ended December 31 (in millions) 2020 2019 2018 Cash paid for interest, net of amount capitalized (1) $ 464.7 $ 475.2 $ 115.0 Cash paid for income taxes, net 101.2 45.8 17.7 Significant non-cash investing and financing transactions: Accounts payable related to construction costs 43.0 36.1 14.0 Receivable related to insurance proceeds for property damage (2) 2.7 — — (1) On January 1, 2019, we adopted ASU 2016-02, Leases (Topic 842). This ASU required us to prospectively change the classification of our finance lease payments on the income statement. As a result, during 2020 and 2019, we classified the interest component of our finance lease payments as cash paid for interest since it was included in interest expense on the income statement. However, prior to our adoption of Topic 842, the interest component was not considered cash paid for interest since it was not included in interest expense on the income statement. See Note 12, Leases, for more information on Topic 842 and our finance leases. (2) See Note 6, Property, Plant, and Equipment, for more information. |
Regulatory Environment (Tables)
Regulatory Environment (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Regulated Operations [Abstract] | |
Schedule of decisions in regulatory order | The final order reflects the following: 2020 Effective rate increase Electric (1) $ 15.3 million / 0.5% Gas (2) $ 10.4 million / 2.8% Steam $ 1.9 million / 8.6% ROE 10.0% Common equity component average on a financial basis 52.5% (1) Amount is net of certain deferred tax benefits from the Tax Legislation that were utilized to reduce near-term rate impact. The rate order reflects the majority of the unprotected deferred tax benefits from the Tax Legislation being amortized evenly over two years, which results in approximately $65 million of tax benefits being amortized in each of 2020 and 2021. The unprotected deferred tax benefits related to the unrecovered balances of our recently retired plants and our SSR regulatory asset were used to reduce the related regulatory asset. Unprotected deferred tax benefits by their nature are eligible to be returned to customers in a manner and timeline determined to be appropriate by the PSCW. (2) Amount includes certain deferred tax expense from the Tax Legislation. The rate order reflects all of the unprotected deferred tax expense from the Tax Legislation being amortized evenly over four years, which results in approximately $5 million of previously deferred tax expense being amortized each year. Unprotected deferred tax expense by its nature is eligible to be recovered from customers in a manner and timeline determined to be appropriate by the PSCW. |
Other Income, Net (Tables)
Other Income, Net (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Other Income and Expenses [Abstract] | |
Schedule of other income, net | Total other income, net was as follows for the years ended December 31: (in millions) 2020 2019 2018 Non-service components of net periodic benefit costs $ 11.8 $ 9.2 $ 5.7 AFUDC – Equity 7.0 3.7 3.9 Other, net (0.3) 9.8 10.6 Other income, net $ 18.5 $ 22.7 $ 20.2 |
Quarterly Financial Informati_2
Quarterly Financial Information (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule of Quarterly Financial Information (unaudited) | (in millions) First Quarter Second Quarter Third Quarter Fourth Quarter Total 2020 Operating revenues $ 871.0 $ 769.5 $ 900.2 $ 826.3 $ 3,367.0 Operating income 247.0 188.6 244.6 180.3 860.5 Net income attributed to common shareholder 118.7 70.6 114.6 61.7 365.6 2019 Operating revenues $ 960.8 $ 791.7 $ 884.1 $ 860.1 $ 3,496.7 Operating income 222.9 182.6 201.1 153.6 760.2 Net income attributed to common shareholder 114.7 84.9 100.6 61.9 362.1 |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies General Information (Details) | Oct. 31, 2018wholly_owned_subsidiaries |
Bostco LLC | |
Condensed Financial Statements, Captions | |
Number of wholly owned subsidiaries dissolved | 1 |
Summary of Significant Accoun_5
Summary of Significant Accounting Policies Cash and Cash Equivalents (Details) | 12 Months Ended |
Dec. 31, 2020 | |
Accounting Policies [Abstract] | |
Maximum term of original maturity to classify instrument as cash equivalent | 3 months |
Summary of Significant Accoun_6
Summary of Significant Accounting Policies Operating Revenues (Details) | 12 Months Ended |
Dec. 31, 2020performance_obligationscontract | |
Electric | |
Disaggregation of Operating Revenues | |
Number of days payment is due | 30 days |
Electric | Retail | |
Disaggregation of Operating Revenues | |
Number of performance obligations | 1 |
Percent fuel and purchased power costs can vary from the rate case approved costs before deferral is required | 2.00% |
Electric | Wholesale | |
Disaggregation of Operating Revenues | |
Number of performance obligations | 2 |
Number of contracts | contract | 1 |
Natural gas | |
Disaggregation of Operating Revenues | |
Number of days payment is due | 30 days |
Summary of Significant Accoun_7
Summary of Significant Accounting Policies Credit Losses (Details) $ in Millions | Dec. 31, 2020USD ($) |
Other | |
Accounts, Notes, Loans and Financing Receivable [Line Items] | |
Accounts receivable and unbilled revenues | $ 0 |
Summary of Significant Accoun_8
Summary of Significant Accounting Policies Materials, Supplies, and Inventories (Details) - USD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Accounting Policies [Abstract] | ||
Materials and supplies | $ 136.5 | $ 148.3 |
Fossil fuel | 57.1 | 51.1 |
Natural gas in storage | 25.9 | 30.4 |
Total | $ 219.5 | $ 229.8 |
Summary of Significant Accoun_9
Summary of Significant Accounting Policies Property, Plant, and Equipment (Details) | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Property, plant, and equipment | |||
Annual utility composite depreciation rate (as a percent) | 3.19% | 3.11% | 3.18% |
Software | Minimum | |||
Property, plant, and equipment | |||
Estimated useful life | 5 years | ||
Software | Maximum | |||
Property, plant, and equipment | |||
Estimated useful life | 15 years |
Summary of Significant Accou_10
Summary of Significant Accounting Policies Allowance for Funds Used During Construction (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Allowance for funds used during construction | |||
Percentage of retail jurisdictional construction work in progress expenditure subject to public utilities allowance for funds used during construction calculation | 50.00% | ||
AFUDC - Debt | $ 2.6 | $ 1.5 | $ 1.5 |
AFUDC - Equity | $ 7 | $ 3.7 | $ 3.9 |
Retail operations | |||
Allowance for funds used during construction | |||
Average AFUDC rate (as a percent) | 8.68% | 8.45% | 8.45% |
Wholesale operations | |||
Allowance for funds used during construction | |||
Average AFUDC rate (as a percent) | 5.39% | 5.11% | 3.63% |
Summary of Significant Accou_11
Summary of Significant Accounting Policies Stock-Based Compensation (Details) - $ / shares | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Number of shares of WEC Energy Group common stock authorized for issuance | 34,300,000 | ||
Stock options | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period (in years) | 3 years | ||
Minimum exercise price of stock option as a percent of WEC Energy Group common stock fair value on the grant date | 100.00% | ||
Period after the grant date during which stock options can't be exercised (in months) | 6 months | ||
Maximum term of awards (in years) | 10 years | ||
Stock options granted (in shares) | 59,511 | 59,404 | 81,730 |
Estimated weighted-average fair value per stock option (in dollars per share) | $ 10.82 | $ 8.60 | $ 7.26 |
Risk-free interest rate, minimum (as a percent) | 1.60% | 2.50% | 1.60% |
Risk-free interest rate, maximum (as a percent) | 1.90% | 2.70% | 2.50% |
Dividend yield (as a percent) | 3.00% | 3.60% | 3.50% |
Expected volatility (as a percent) | 16.00% | 17.00% | 18.00% |
Expected life (years) | 8 years 7 months 6 days | 8 years 6 months | 5 years 1 month 6 days |
Restricted stock | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period (in years) | 3 years | ||
Percentage to vest each year after the grant date | 33.00% | ||
Performance units | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period (in years) | 3 years | ||
Performance units | Minimum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Payout ratio (as a percent) | 0.00% | ||
Performance units | Maximum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Payout ratio (as a percent) | 175.00% |
Summary of Significant Accou_12
Summary of Significant Accounting Policies Leases (Details) $ in Millions | 1 Months Ended | |||
Jan. 31, 2019USD ($) | Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($) | Jan. 01, 2019USD ($)land_easement | |
Leases | ||||
Operating lease right of use assets | $ 8.4 | $ 10.6 | ||
Total Liabilities | ||||
Leases | ||||
Operating lease liability | $ 8.4 | |||
Accounting Standards Update 2016-02 | ||||
Leases | ||||
Impairment losses recorded upon adoption of ASU 2016-02 | $ 0 | |||
Finance capital lease expense impact of ASU 2016-02 | $ 0 | |||
Accounting Standards Update 2016-02 | Total Assets | ||||
Leases | ||||
Operating lease right of use assets | $ 13 | |||
Accounting Standards Update 2016-02 | Total Liabilities | ||||
Leases | ||||
Operating lease liability | $ 13 | |||
Accounting Standards Update 2018-01 | ||||
Leases | ||||
Number of land easements considered leases upon adoption of ASU 2016-02 | land_easement | 0 |
Summary of Significant Accou_13
Summary of Significant Accounting Policies Guarantees (Details) $ in Millions | Dec. 31, 2020USD ($) |
Standby letters of credit | |
Guarantor Obligations [Line Items] | |
Guarantee | $ 26 |
Summary of Significant Accou_14
Summary of Significant Accounting Policies Customer Concentrations of Credit Risk (Details) - Customer concentration risk | 12 Months Ended |
Dec. 31, 2020customer | |
Customer concentration risk | |
Number of customers that account for more than 10% of revenues | 0 |
Threshold percentage of revenues from major customers | 10.00% |
Related Parties (Details)
Related Parties (Details) - ATC - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Related parties | ||
Accounts receivable, related parties, current | $ 1.2 | $ 1.7 |
Amounts due from related party for transmission infrastructure upgrades | 1.6 | 0 |
Accounts payable, related parties, current | $ 19.2 | $ 19.9 |
Related Parties - Other Transac
Related Parties - Other Transactions (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
WPS | |||
Related parties | |||
Charges to related party for services and billings | $ 12.5 | $ 13.2 | $ 17.8 |
Charges from related party for services and billings | 8.3 | 9.3 | 10.9 |
Natural gas purchases | 1.5 | 2 | 1.9 |
WG | |||
Related parties | |||
Charges to related party for services and billings | 42.3 | 41.1 | 59 |
Charges from related party for services and billings | 31.7 | 30.1 | 32.6 |
Natural gas purchases | 5.7 | 5.4 | 5.3 |
Proceeds from assets transferred to affiliates | 5.3 | ||
UMERC | |||
Related parties | |||
Charges to related party for services and billings | 9.8 | 10.5 | 15.8 |
Electric sales to UMERC | 0 | 7.9 | 29.6 |
Bluewater | |||
Related parties | |||
Charges to related party for services and billings | 3 | 0.2 | 0 |
Charges from related party for services and billings | 12.9 | 14.2 | 15 |
Natural gas purchases | 2.6 | 2.3 | 0 |
We Power LLC | |||
Related parties | |||
Lease payments paid to related party | 404.3 | 401.1 | 396.5 |
Charges to related party for services and billings | 4.5 | 7.1 | 10.6 |
WBS | |||
Related parties | |||
Charges to related party for services and billings | 67.8 | 102.6 | 61.5 |
Charges from related party for services and billings | 152.9 | 205.3 | 243.4 |
Proceeds from liabilities transferred from WBS | 10 | ||
Payments for assets transferred from WBS | 59.8 | ||
ATC | |||
Related parties | |||
Charges to related party for services and billings | 15.6 | 14.9 | 13.9 |
Charges from related party for services and billings | 229.3 | 230.6 | 232 |
Refund from ATC per FERC ROE order | 7.3 | 0 | 0 |
Refund from ATC related to a FERC audit | $ 0 | $ 0 | $ 15.4 |
Related Parties - UMERC (Detail
Related Parties - UMERC (Details) - USD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 | Jun. 30, 2019 |
Related parties | |||
Regulatory assets | $ 2,803.3 | $ 2,755.2 | |
UMERC transfer | UMERC | |||
Related parties | |||
Regulatory assets | $ 12.5 |
Operating Revenues - Disaggrega
Operating Revenues - Disaggregation of Operating Revenues (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2020 | Sep. 30, 2020 | Jun. 30, 2020 | Mar. 31, 2020 | Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Disaggregation of Operating Revenues | |||||||||||
Operating revenues | $ 826.3 | $ 900.2 | $ 769.5 | $ 871 | $ 860.1 | $ 884.1 | $ 791.7 | $ 960.8 | $ 3,367 | $ 3,496.7 | $ 3,625 |
Utility | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Operating revenues | 3,367 | 3,496.7 | 3,625 | ||||||||
Utility | Other operating revenues | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Other operating revenues | 8.2 | 9.4 | 7.2 | ||||||||
Utility | Transferred over time | Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | 3,358.8 | 3,487.3 | 3,617.8 | ||||||||
Utility | Electric | Transferred over time | Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | 3,000.2 | 3,088.3 | 3,212.7 | ||||||||
Utility | Natural gas | Transferred over time | Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | $ 358.6 | $ 399 | $ 405.1 |
Operating Revenues Electric Uti
Operating Revenues Electric Utility Operating Revenues (Details) - Utility - Revenues from contracts with customers - Transferred over time - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | $ 3,358.8 | $ 3,487.3 | $ 3,617.8 |
Electric | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 3,000.2 | 3,088.3 | 3,212.7 |
Electric | Total retail | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 2,791.8 | 2,822.1 | 2,918.1 |
Electric | Residential | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 1,289.2 | 1,206.7 | 1,220.8 |
Electric | Small commercial and industrial | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 955.4 | 1,010.9 | 1,020 |
Electric | Large commercial and industrial | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 527.3 | 583.9 | 656.6 |
Electric | Other | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 19.9 | 20.6 | 20.7 |
Electric | Wholesale | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 78.8 | 93.8 | 108.5 |
Electric | Resale | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 108.4 | 132.7 | 153.7 |
Electric | Steam | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 21.3 | 23.3 | 24.1 |
Electric | Other utility | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | $ (0.1) | $ 16.4 | $ 8.3 |
Operating Revenues Natural Gas
Operating Revenues Natural Gas Utility Operating Revenues (Details) - Revenues from contracts with customers - Utility - Transferred over time - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | $ 3,358.8 | $ 3,487.3 | $ 3,617.8 |
Natural gas | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 358.6 | 399 | 405.1 |
Natural gas | Total retail | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 335.5 | 382.9 | 390.6 |
Natural gas | Residential | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 238.4 | 261.7 | 264.3 |
Natural gas | Commercial and industrial | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 97.1 | 121.2 | 126.3 |
Natural gas | Transport | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 16.3 | 13.6 | 13.4 |
Natural gas | Other utility | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | $ 6.8 | $ 2.5 | $ 1.1 |
Operating Revenues - Other Oper
Operating Revenues - Other Operating Revenues (Details) - Utility - Other operating revenues - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Disaggregation of Operating Revenues | |||
Other operating revenues | $ 8.2 | $ 9.4 | $ 7.2 |
Late payment charges | |||
Disaggregation of Operating Revenues | |||
Other operating revenues | 5.6 | 8.2 | 8.2 |
Rental revenues | |||
Disaggregation of Operating Revenues | |||
Other operating revenues | 2.9 | 2.9 | 2.9 |
Alternative revenues | |||
Disaggregation of Operating Revenues | |||
Other operating revenues | $ (0.3) | $ (1.7) | $ (3.9) |
Credit Losses - Gross Receivabl
Credit Losses - Gross Receivables and Related Allowances (Details) - Utility - USD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts receivable and unbilled revenues | $ 525.4 | |
Allowance for credit losses | 59.3 | $ 38.1 |
Accounts receivable and unbilled revenues, net | 466.1 | |
Total accounts receivable, net - past due greater than 90 days | $ 56.3 | |
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms | 98.20% | |
Amount of net accounts receivable with regulatory protections | $ 239.8 | |
Percent of net accounts receivable with regulatory protections | 51.40% |
Credit Losses - Rollforward of
Credit Losses - Rollforward of Allowances (Details) - Utility $ in Millions | 12 Months Ended |
Dec. 31, 2020USD ($) | |
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | |
Balance at December 31, 2019 | $ 38.1 |
Provision for credit losses | 24.6 |
Provision for credit losses deferred for future recovery or refund | 14.8 |
Write-offs charged against the allowance | (38.8) |
Recovery of amounts previously written off | 20.6 |
Balance at December 31, 2020 | $ 59.3 |
Regulatory Assets and Liabili_3
Regulatory Assets and Liabilities - Regulatory Assets (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Regulatory assets | ||
Regulatory assets | $ 2,803.3 | $ 2,755.2 |
Allowance for return on equity capitalized for regulatory purposes | 14.5 | 9.9 |
Regulatory assets not earning a return | 8.1 | |
Regulatory assets earning a return based on short-term interest rates | 8.9 | |
Regulatory assets earning a return based on long-term interest rates | 135.6 | |
Finance leases | ||
Regulatory assets | ||
Regulatory assets | 985.5 | 930.5 |
Plant retirements | ||
Regulatory assets | ||
Regulatory assets | 669.8 | 688.8 |
Pension and OPEB costs | ||
Regulatory assets | ||
Regulatory assets | 477 | 459.4 |
Income tax related items | ||
Regulatory assets | ||
Regulatory assets | 392.6 | 403.2 |
System support resource (SSR) | ||
Regulatory assets | ||
Regulatory assets | $ 135.6 | 151.5 |
Recovery period of regulatory asset | 15 years | |
Securitization | ||
Regulatory assets | ||
Regulatory assets | $ 105.2 | 100 |
Other, net | ||
Regulatory assets | ||
Regulatory assets | $ 37.6 | $ 21.8 |
Regulatory Assets and Liabili_4
Regulatory Assets and Liabilities - Regulatory Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Regulatory liabilities | ||
Other current liabilities | $ 4.2 | $ 12 |
Regulatory liabilities | 1,703.7 | 1,744.2 |
Total regulatory liabilities | 1,707.9 | 1,756.2 |
Income tax related items | ||
Regulatory liabilities | ||
Total regulatory liabilities | 806.7 | 888.1 |
Removal costs | ||
Regulatory liabilities | ||
Total regulatory liabilities | 677.2 | 654.7 |
Pension and OPEB benefits | ||
Regulatory liabilities | ||
Total regulatory liabilities | 132.1 | 120.4 |
Electric transmission costs | ||
Regulatory liabilities | ||
Total regulatory liabilities | 61.7 | 38.6 |
Earnings sharing refunds offsetting electric transmission escrow | 38.6 | |
Uncollectible expense | ||
Regulatory liabilities | ||
Total regulatory liabilities | 15.5 | 28.8 |
Energy efficiency programs | ||
Regulatory liabilities | ||
Total regulatory liabilities | 2.9 | 15.8 |
Earnings sharing mechanism | ||
Regulatory liabilities | ||
Total regulatory liabilities | 0 | |
Other, net | ||
Regulatory liabilities | ||
Total regulatory liabilities | $ 11.8 | $ 9.8 |
Regulatory Assets and Liabili_5
Regulatory Assets and Liabilities - Plant Retirements (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Regulatory assets | |||
Regulatory assets | $ 2,803.3 | $ 2,755.2 | |
Deferred tax liabilities | 1,334.4 | 1,368.9 | |
Severance liability for plant retirements | |||
Severance liability at January 1 | 2.1 | 12.9 | $ 25.8 |
Severance payments | (0.1) | (5.7) | (9.9) |
Other | (1.3) | (5.1) | (3) |
Severance liability at December 31 | 0.7 | 2.1 | $ 12.9 |
Securitization | |||
Regulatory assets | |||
Regulatory assets | 105.2 | $ 100 | |
Pleasant Prairie power plant | |||
Regulatory assets | |||
Net book value of retired plant | 602.7 | ||
Deferred unprotected tax benefits | 19.6 | ||
Regulatory assets | 583.1 | ||
Deferred tax liabilities | 168.7 | ||
Pleasant Prairie power plant | Securitization | |||
Regulatory assets | |||
Regulatory assets | 100 | ||
Presque Isle power plant | |||
Regulatory assets | |||
Net book value of retired plant | 149.1 | ||
Deferred unprotected tax benefits | 6 | ||
Regulatory assets | 143.1 | ||
Deferred tax liabilities | $ 42.8 |
Property, Plant, and Equipmen_2
Property, Plant, and Equipment - Balances (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Property, Plant and Equipment [Line Items] | ||
Accumulated depreciation | $ 4,849.2 | $ 4,564 |
Property, plant, and equipment | 9,789.9 | 9,586.7 |
Net leased facilities | 1,855.2 | 1,910.4 |
Costs incurred for repairs and restorations | 35.2 | |
Insurance proceeds received to cover damage to the PSB Building | 20 | |
Accounts receivable recorded for future insurance recoveries for the PSB building | 2.7 | |
PSB building repair and restoration costs in other operation and maintenance expense | 12.5 | |
Regulated operations | ||
Property, Plant and Equipment [Line Items] | ||
Accumulated depreciation | 3,568.5 | 3,397 |
Net | 7,681.5 | 7,485.5 |
CWIP | 253.2 | 190.8 |
Property, plant, and equipment | 7,934.7 | 7,676.3 |
Regulated operations | Electric - generation | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant, and equipment, gross, excluding construction work in progress and finance/capital leases | 3,612.8 | 3,623.4 |
Regulated operations | Electric - distribution | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant, and equipment, gross, excluding construction work in progress and finance/capital leases | 5,328.4 | 5,086.4 |
Regulated operations | Natural gas - distribution, storage, and transmission | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant, and equipment, gross, excluding construction work in progress and finance/capital leases | 1,444.2 | 1,358 |
Regulated operations | Other | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant, and equipment, gross, excluding construction work in progress and finance/capital leases | 864.6 | 814.7 |
Regulated operations | Finance leases | ||
Property, Plant and Equipment [Line Items] | ||
Property under finance leases | 3,135.9 | 3,077.4 |
Accumulated amortization | 1,280.7 | 1,167 |
Net leased facilities | $ 1,855.2 | $ 1,910.4 |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Changes to asset retirement obligations | |||
Balance as of January 1 | $ 65 | $ 70.7 | $ 68.3 |
Accretion | 2.3 | 3.6 | 3.3 |
Additions and revisions to estimated cash flows | (11.1) | (8.4) | 1 |
Liabilities settled | (1.7) | (0.9) | (1.9) |
Balance as of December 31 | $ 54.5 | $ 65 | $ 70.7 |
Common Equity - Stock-Based Com
Common Equity - Stock-Based Compensation Expense (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Stock-based compensation expense | $ 14.5 | $ 22.3 | $ 14.6 |
Related Tax Benefit | 4 | 6.1 | 4 |
Stock options | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Stock-based compensation expense | 2.1 | 1.7 | 2 |
Restricted stock | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Stock-based compensation expense | 2.7 | 2.7 | 3 |
Performance units | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Stock-based compensation expense | $ 9.7 | $ 17.9 | $ 9.6 |
Common Equity - Stock Options (
Common Equity - Stock Options (Details) - Stock options - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Options Activity | ||||
Outstanding, shares, beginning balance | 485,113 | 626,261 | ||
Granted, shares | 59,511 | 59,404 | 81,730 | |
Exercised, shares | (121,624) | |||
Transferred, shares | (75,668) | |||
Forfeited, shares | (3,367) | |||
Outstanding, shares, ending balance | 485,113 | 626,261 | ||
Options - Weighted Average Exercise Price | ||||
Outstanding, Weighted-Average Exercise Price, Beginning | $ 55.93 | $ 48.98 | ||
Granted, Weighted-Average Exercise Price | 91.49 | |||
Exercised, Weighted-Average Exercise Price | 42.60 | |||
Transferred, Weighted-Average Exercise Price | 47.30 | |||
Forfeited, Weighted Average Exercise Price | 67.33 | |||
Outstanding, Weighted-Average Exercise Price, Ending | $ 55.93 | $ 48.98 | ||
Options - Additional Disclosures | ||||
Outstanding, Weighted-Average Remaining Contractual Life (Years) | 5 years 1 month 6 days | |||
Outstanding, Aggregate Intrinsic Value | $ 17.5 | |||
Exercisable, shares | 330,010 | |||
Exercisable, Weighted-Average Exercise Price | $ 46.45 | |||
Exercisable, Weighted-Average Remaining Contractual Life (Years) | 3 years 8 months 12 days | |||
Exercisable, Aggregate Intrinsic Value | $ 15 | |||
Intrinsic value of options exercised | 7.1 | $ 8 | $ 12.9 | |
Tax benefit from option exercises | 1.9 | $ 2.2 | $ 2.7 | |
Compensation cost not yet recognized | $ 0.8 | |||
Weighted-average period over which unrecognized compensation cost is expected to be recognized | 1 year 9 months 18 days | |||
Estimated weighted-average fair value per stock option (in dollars per share) | $ 10.82 | $ 8.60 | $ 7.26 | |
Subsequent event | ||||
Options Activity | ||||
Granted, shares | 60,108 | |||
Options - Weighted Average Exercise Price | ||||
Granted, Weighted-Average Exercise Price | $ 91.06 | |||
Options - Additional Disclosures | ||||
Estimated weighted-average fair value per stock option (in dollars per share) | $ 13.20 | |||
WEC Energy Group | ||||
Options - Additional Disclosures | ||||
Cash received by WEC Energy Group from options exercised by WE employees | $ 5.2 | $ 6.3 | $ 10 |
Common Equity - Restricted Shar
Common Equity - Restricted Shares (Details) - Restricted stock - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Restricted Stock Activity | ||||
Outstanding, shares, beginning of period | 8,632 | 9,736 | ||
Granted, shares | 4,371 | |||
Released, shares | (4,791) | |||
Transferred, shares | 64 | |||
Forfeited, shares | (748) | |||
Outstanding, shares, end of period | 8,632 | 9,736 | ||
Restricted Stock Weighted-Average Grant Date Fair Value | ||||
Outstanding, weighted-average grant date fair value, beginning of period | $ 78.97 | $ 65.58 | ||
Granted, weighted-average grant date fair value | 91.49 | |||
Released, weighted-average grant date fair value | 63.95 | |||
Transferred, weighted-average grant date fair value | 66.78 | |||
Forfeited, weighted-average grant date fair value | 73.02 | |||
Outstanding, weighted-average grant date fair value, end of period | $ 78.97 | $ 65.58 | ||
Restricted Stock - Additional Disclosures | ||||
Intrinsic value of released restricted shares | $ 0.4 | $ 0.4 | $ 0.4 | |
Tax benefit from released restricted shares | 0.1 | $ 0.1 | $ 0.1 | |
Compensation cost not yet recognized | $ 1.1 | |||
Weighted-average period over which unrecognized compensation cost is expected to be recognized | 1 year 9 months 18 days | |||
Subsequent event | ||||
Restricted Stock Activity | ||||
Granted, shares | 4,183 | |||
Restricted Stock Weighted-Average Grant Date Fair Value | ||||
Granted, weighted-average grant date fair value | $ 91.06 |
Common Equity - Performance Uni
Common Equity - Performance Units (Details) - Performance units - USD ($) $ in Millions | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||
Jan. 31, 2021 | Mar. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Performance units granted | 18,952 | 22,452 | 32,650 | ||
Intrinsic value of settled performance units | $ 3.9 | $ 2.3 | $ 2 | ||
Tax benefit from distribution of performance units | $ 0.9 | $ 0.5 | $ 0.4 | ||
Performance units outstanding | 59,530 | ||||
Liability recorded on balance sheet | $ 5.5 | ||||
Compensation cost not yet recognized | $ 7.3 | ||||
Weighted-average period over which unrecognized compensation cost is expected to be recognized | 1 year 7 months 6 days | ||||
Subsequent event | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Performance units granted | 18,138 | ||||
Intrinsic value of settled performance units | $ 3 | ||||
Tax benefit from distribution of performance units | $ 0.7 |
Common Equity - Dividend Restri
Common Equity - Dividend Restrictions (Details) | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
$100 par value, Serial Preferred Stock, 3.60% Series | ||
Dividend Payment Restrictions [Line Items] | ||
Preferred Stock, dividend rate (as a percent) | 3.60% | 3.60% |
Minimum | $100 par value, Serial Preferred Stock, 3.60% Series | Common stock equity to total capitalization is between 25% and 20% | ||
Dividend Payment Restrictions [Line Items] | ||
Percentage of common equity to total capitalization required to be maintained | 20.00% | |
Maximum | $100 par value, Serial Preferred Stock, 3.60% Series | Common stock equity to total capitalization is between 25% and 20% | ||
Dividend Payment Restrictions [Line Items] | ||
Percentage of net income for which dividends can be declared | 75.00% | |
Percentage of common equity to total capitalization required to be maintained | 25.00% | |
Maximum | $100 par value, Serial Preferred Stock, 3.60% Series | Common stock equity to total capitalization is less than 20% | ||
Dividend Payment Restrictions [Line Items] | ||
Percentage of net income for which dividends can be declared | 50.00% | |
Percentage of common equity to total capitalization required to be maintained | 20.00% | |
Public Service Commission of Wisconsin | Minimum | ||
Dividend Payment Restrictions [Line Items] | ||
Common equity ratio required to be maintained (as a percent) | 52.50% |
Preferred Stock (Details)
Preferred Stock (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Class of Stock | ||
Total preferred stock value issued | $ 30.4 | $ 30.4 |
$100 par value, Six Per Cent. Preferred Stock | ||
Class of Stock | ||
Par or stated value per share | $ 100 | $ 100 |
Dividend rate (as a percentage) | 6.00% | 6.00% |
Shares authorized | 45,000 | 45,000 |
Shares outstanding | 44,498 | 44,498 |
Redemption price per share | $ 0 | $ 0 |
Total preferred stock value issued | $ 4.4 | $ 4.4 |
$100 par value, Serial Preferred Stock, 3.60% Series | ||
Class of Stock | ||
Par or stated value per share | $ 100 | $ 100 |
Dividend rate (as a percentage) | 3.60% | 3.60% |
Shares authorized | 2,286,500 | 2,286,500 |
Shares outstanding | 260,000 | 260,000 |
Redemption price per share | $ 101 | $ 101 |
Total preferred stock value issued | $ 26 | $ 26 |
$25 par value, Serial Preferred Stock | ||
Class of Stock | ||
Par or stated value per share | $ 25 | $ 25 |
Shares authorized | 5,000,000 | 5,000,000 |
Shares outstanding | 0 | 0 |
Redemption price per share | $ 0 | $ 0 |
Total preferred stock value issued | $ 0 | $ 0 |
Short-Term Debt and Lines of _3
Short-Term Debt and Lines of Credit Outstanding (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Short-term Debt [Line Items] | ||
Maximum debt to capitalization ratio required to be maintained (as a percent) | 65.00% | |
Commercial Paper | ||
Short-term Debt [Line Items] | ||
Commercial paper outstanding | $ 292 | $ 115.5 |
Average interest rate on amounts outstanding | 0.21% | 2.03% |
Average amounts outstanding during year | $ 72.7 | |
Weighted average interest rate during the year | 1.16% |
Short-Term Debt and Lines of _4
Short-Term Debt and Lines of Credit - Credit Facilities (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2020USD ($)extension | Dec. 31, 2019USD ($) | |
Line of Credit Facility [Line Items] | ||
Available capacity under existing agreements | $ 207 | |
Number of extensions available on a credit facility | extension | 2 | |
Length of credit facility extension | 1 year | |
Credit facility maturing October 2022 [Member] | ||
Line of Credit Facility [Line Items] | ||
Short-term credit capacity | $ 500 | |
Letters of Credit | ||
Line of Credit Facility [Line Items] | ||
Letters of credit issued inside credit facilities | 1 | |
Commercial Paper | ||
Line of Credit Facility [Line Items] | ||
Commercial paper outstanding | $ 292 | $ 115.5 |
Long-Term Debt (Details)
Long-Term Debt (Details) - USD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Long-term debt | ||
Total | $ 2,785 | $ 2,785 |
Unamortized debt issuance costs | (7.4) | (8) |
Unamortized discount, net | (16.4) | (17.8) |
Long-term debt including current portion | 2,761.2 | 2,759.2 |
Current portion of long-term debt | (300) | 0 |
Total long-term debt | 2,461.2 | 2,759.2 |
Future maturities of long-term debt outstanding | ||
2021 | 300 | |
2022 | 0 | |
2023 | 0 | |
2024 | 300 | |
2025 | 250 | |
Thereafter | 1,935 | |
Total | $ 2,785 | 2,785 |
Debentures (unsecured), 2.95% due 2021 | ||
Long-term debt | ||
Interest rate | 2.95% | |
Unsecured debt | $ 300 | 300 |
Debentures (unsecured), 2.05% due 2024 | ||
Long-term debt | ||
Interest rate | 2.05% | |
Unsecured debt | $ 300 | 300 |
Debentures (unsecured), 3.10% due 2025 | ||
Long-term debt | ||
Interest rate | 3.10% | |
Unsecured debt | $ 250 | 250 |
Debentures (unsecured), 6.50% due 2028 | ||
Long-term debt | ||
Interest rate | 6.50% | |
Unsecured debt | $ 150 | 150 |
Debentures (unsecured), 5.625% due 2033 | ||
Long-term debt | ||
Interest rate | 5.625% | |
Unsecured debt | $ 335 | 335 |
Debentures (unsecured), 5.70% due 2036 | ||
Long-term debt | ||
Interest rate | 5.70% | |
Unsecured debt | $ 300 | 300 |
Debentures (unsecured), 3.65% due 2042 | ||
Long-term debt | ||
Interest rate | 3.65% | |
Unsecured debt | $ 250 | 250 |
Debentures (unsecured), 4.25% due 2044 | ||
Long-term debt | ||
Interest rate | 4.25% | |
Unsecured debt | $ 250 | 250 |
Debentures (unsecured), 4.30% due 2045 | ||
Long-term debt | ||
Interest rate | 4.30% | |
Unsecured debt | $ 250 | 250 |
Debentures (unsecured), 4.30% due 2048 | ||
Long-term debt | ||
Interest rate | 4.30% | |
Unsecured debt | $ 300 | 300 |
Debentures (unsecured), 6.875% due 2095 | ||
Long-term debt | ||
Interest rate | 6.875% | |
Unsecured debt | $ 100 | $ 100 |
Leases - Power Purchase Commitm
Leases - Power Purchase Commitment (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2020USD ($)MW | Dec. 31, 2009USD ($) | |
Leases | ||
Finance lease obligation | $ 2,841.2 | |
Power purchase commitment | ||
Leases | ||
Power purchase contract period | 25 years | |
Firm capacity from power purchase contract (in megawatts) | MW | 236 | |
Minimum energy requirements over remaining term of power purchase contract (in megawatts) | MW | 0 | |
Power purchase contract renewal period | 10 years | |
Maximum regulatory asset for power purchase contract | $ 78.5 | |
Regulatory asset at end of life of power purchase contract | $ 0 | |
Finance lease obligation | 12.1 | |
Finance lease obligation at end of life of power purchase contract | $ 0 |
Leases - Port Washington Genera
Leases - Port Washington Generating Station (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2020USD ($)contractrenewal_termsgenerating_unitsMW | |
Leases | |
Finance lease obligation | $ 2,841.2 |
Port Washington Generating Station | |
Leases | |
Number of generation units at the Port Washington Generating Station | generating_units | 2 |
Capacity of generation unit (in megawatts) | MW | 545 |
Power purchase contract period | 25 years |
Regulatory asset at end of life of power purchase contract | $ 0 |
Finance lease obligation | 598.9 |
Finance lease obligation at end of life of power purchase contract | $ 0 |
Minimum number of power purchase contracts that can be renewed | contract | 1 |
Maximum number of consecutive renewal terms | renewal_terms | 3 |
Increase to contract term if renewal selected (as percent of remaining economic life of generation unit) | 80.00% |
Minimum number of generation units that can be purchased | generating_units | 1 |
Port Washington Generating Station unit 1 (PWGS 1) | |
Leases | |
Maximum regulatory asset for power purchase contract | $ 129.5 |
Port Washington Generating Station unit 2 (PWGS 2) | |
Leases | |
Maximum regulatory asset for power purchase contract | $ 126.8 |
Leases - Elm Road Generating St
Leases - Elm Road Generating Station (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2020USD ($)contractrenewal_termsgenerating_units | |
Leases | |
Finance lease obligation | $ 2,841.2 |
Elm Road Generating Station | |
Leases | |
Power purchase contract period | 30 years |
Regulatory asset at end of life of power purchase contract | $ 0 |
Finance lease obligation | 2,207.1 |
Finance lease obligation at end of life of power purchase contract | $ 0 |
Minimum number of power purchase contracts that can be renewed | contract | 1 |
Maximum number of consecutive renewal terms | renewal_terms | 3 |
Increase to contract term if renewal selected (as percent of remaining economic life of generation unit) | 80.00% |
Minimum number of generation units that can be purchased | generating_units | 1 |
Elm Road Generating Station unit 1 (ER 1) | |
Leases | |
Maximum regulatory asset for power purchase contract | $ 528.2 |
Elm Road Generating Station unit 2 (ER 2) | |
Leases | |
Maximum regulatory asset for power purchase contract | $ 436.1 |
Leases - Badger Hollow Solar Pa
Leases - Badger Hollow Solar Park II (Details) $ in Millions | Dec. 31, 2020USD ($)a |
Leases | |
Finance lease obligation | $ 2,841.2 |
Badger Hollow II | |
Leases | |
Solar land lease acreage | a | 1,500 |
Lease initial term | 25 years |
Renewal term | 25 years |
Finance lease obligation | $ 23.1 |
Finance lease obligation at end of life of solar land contract | $ 0 |
Leases - Lease Expense and Supp
Leases - Lease Expense and Supplemental Cash Flow Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Lease expense | |||
Amortization of finance lease right of use assets | $ 59.2 | $ 20.6 | |
Interest on finance lease liabilities | 347.1 | 350.9 | |
Capital lease expense | $ 371 | ||
Operating lease expense | 2.6 | 2.6 | 2.7 |
Total lease expense | 408.9 | 374.1 | 373.7 |
Other information | |||
Operating cash flows from finance / capital leases | 347.1 | 350.9 | 381.4 |
Operating cash flows from operating leases | 2.6 | 2.6 | 2.7 |
Financing cash flows from finance leases | 58.3 | 50.5 | $ 0 |
Right-of-use asset obtained in exchange for finance lease liability | 22.8 | 0 | |
Noncash activity - right of use assets obtained in exchange for operating lease liabilities | $ 0 | $ 13 | |
Weighted average remaining lease term - finance leases | 18 years | 18 years 7 months 6 days | |
Weighted average remaining lease term - operating leases | 29 years 10 months 24 days | 25 years | |
Weighted average discount rate - finance leases | 13.80% | 13.90% | |
Weighted average discount rate - operating leases | 4.60% | 4.50% |
Leases - Right of Use Assets (D
Leases - Right of Use Assets (Details) - USD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Leases | ||
Total finance lease right of use assets | $ 1,855.2 | $ 1,910.4 |
Operating lease right of use assets | 8.4 | 10.6 |
Power purchase commitment | ||
Leases | ||
Under finance leases | 140.3 | 140.3 |
Accumulated amortization | (132.3) | (126.6) |
Total finance lease right of use assets | 8 | 13.7 |
Port Washington Generating Station | ||
Leases | ||
Under finance leases | 749.4 | 742.7 |
Accumulated amortization | (399.6) | (367.6) |
Total finance lease right of use assets | 349.8 | 375.1 |
Elm Road Generating Station | ||
Leases | ||
Under finance leases | 2,223.4 | 2,194.4 |
Accumulated amortization | (748.6) | (672.8) |
Total finance lease right of use assets | 1,474.8 | 1,521.6 |
Badger Hollow II | ||
Leases | ||
Under finance leases | 22.8 | 0 |
Accumulated amortization | (0.2) | 0 |
Total finance lease right of use assets | $ 22.6 | $ 0 |
Leases - Future Minimum Lease P
Leases - Future Minimum Lease Payments (Details) - USD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Total operating leases | ||
2021 | $ 0.7 | |
2022 | 0.5 | |
2023 | 0.5 | |
2024 | 0.5 | |
2025 | 0.5 | |
Thereafter | 12.7 | |
Total minimum lease payments | 15.4 | |
Less: interest | (7) | |
Total finance leases | ||
2021 | 407 | |
2022 | 401.7 | |
2023 | 397.7 | |
2024 | 397.6 | |
2025 | 397.3 | |
Thereafter | 4,960.9 | |
Total minimum lease payments | 6,962.2 | |
Less: interest | (4,121) | |
Present value of minimum lease payments | 2,841.2 | |
Less: short-term lease liabilities | (66.8) | $ (57.8) |
Finance lease obligations | 2,774.4 | $ 2,783.1 |
Total Liabilities | ||
Total operating leases | ||
Present value of minimum lease payments | 8.4 | |
Other Current Liabilities | ||
Total operating leases | ||
Less: short-term lease liabilities | (0.3) | |
Other Noncurrent Liabilities | ||
Total operating leases | ||
Long-term lease liabilities | 8.1 | |
Power purchase commitment | ||
Total finance leases | ||
2021 | 9.4 | |
2022 | 4.2 | |
2023 | 0 | |
2024 | 0 | |
2025 | 0 | |
Thereafter | 0 | |
Total minimum lease payments | 13.6 | |
Less: interest | (1.5) | |
Present value of minimum lease payments | 12.1 | |
Less: short-term lease liabilities | (8.1) | |
Finance lease obligations | 4 | |
Port Washington Generating Station | ||
Total finance leases | ||
2021 | 99.4 | |
2022 | 99.4 | |
2023 | 99.4 | |
2024 | 99.3 | |
2025 | 99.1 | |
Thereafter | 589.4 | |
Total minimum lease payments | 1,086 | |
Less: interest | (487.1) | |
Present value of minimum lease payments | 598.9 | |
Less: short-term lease liabilities | (28.9) | |
Finance lease obligations | 570 | |
Elm Road Generating Station | ||
Total finance leases | ||
2021 | 297.9 | |
2022 | 297.8 | |
2023 | 297.6 | |
2024 | 297.6 | |
2025 | 297.5 | |
Thereafter | 4,316.5 | |
Total minimum lease payments | 5,804.9 | |
Less: interest | (3,597.8) | |
Present value of minimum lease payments | 2,207.1 | |
Less: short-term lease liabilities | (29.8) | |
Finance lease obligations | 2,177.3 | |
Badger Hollow II | ||
Total finance leases | ||
2021 | 0.3 | |
2022 | 0.3 | |
2023 | 0.7 | |
2024 | 0.7 | |
2025 | 0.7 | |
Thereafter | 55 | |
Total minimum lease payments | 57.7 | |
Less: interest | (34.6) | |
Present value of minimum lease payments | 23.1 | |
Less: short-term lease liabilities | 0 | |
Finance lease obligations | $ 23.1 |
Income Taxes - Summary of incom
Income Taxes - Summary of income tax expense (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | |||
Current tax expense (benefit) | $ 112.2 | $ 73.4 | $ (56.2) |
Deferred income tax expense (benefit), net | (66) | (128.9) | 0.1 |
Investment tax credit, net | (1.5) | (2.3) | (0.8) |
Total income tax expense (benefit) | $ 44.7 | $ (57.8) | $ (56.9) |
Income Taxes - Statutory rate r
Income Taxes - Statutory rate reconciliation (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Effective Income Tax Rate Reconciliation, Amount [Abstract] | ||||
Statutory federal income tax | $ 86.2 | $ 63.9 | $ 63.3 | |
State income taxes net of federal tax benefit | 26.5 | 20.2 | 19.6 | |
Federal excess deferred tax amortization - Wisconsin unprotected | (42.7) | 0 | 0 | |
Federal excess deferred tax amortization | (23.2) | (16.1) | (15.5) | |
Wind production tax credits | (11.1) | (9.3) | (9.4) | |
AFUDC - Equity | (1.5) | (0.8) | (0.8) | |
Investment tax credit restored | (1.5) | (2.3) | (0.8) | |
Domestic production activities deferral | 6.3 | 6.1 | 6.1 | |
Tax repairs | 3.3 | (122.9) | (120.7) | |
Other, net | 2.4 | 3.4 | 1.3 | |
Total income tax expense (benefit) | $ 44.7 | $ (57.8) | $ (56.9) | |
Effective Income Tax Rate Reconciliation, Percentage [Abstract] | ||||
Statutory federal income tax | 21.00% | 21.00% | 21.00% | |
State income taxes net of federal tax benefit | 6.50% | 6.60% | 6.50% | |
Federal excess deferred tax amortization - Wisconsin unprotected | (10.40%) | 0.00% | 0.00% | |
Federal excess deferred tax amortization | (5.70%) | (5.30%) | (5.10%) | |
Wind production tax credits | (2.70%) | (3.00%) | (3.10%) | |
AFUDC - Equity | (0.40%) | (0.30%) | (0.30%) | |
Investment tax credit restored | (0.40%) | (0.80%) | (0.30%) | |
Domestic production activities deferral | 1.50% | 2.00% | 2.00% | |
Tax repairs | 0.80% | (40.10%) | (39.90%) | |
Other, net | 0.70% | 1.00% | 0.40% | |
Total income tax expense (benefit) | 10.90% | (18.90%) | (18.80%) | |
2018 and 2019 rates | Public Service Commission of Wisconsin (PSCW) | Tax Repairs Regulatory Asset | ||||
Income Taxes | ||||
Income statement impact of flow through of repair related deferred tax liabilities | 0 | |||
2018 and 2019 rates | Public Service Commission of Wisconsin (PSCW) | Tax Cuts and Jobs Act of 2017 | ||||
Income Taxes | ||||
Income Statement Impact of amortizing protected tax benefits | $ 0 | |||
2020 and 2021 rates | Public Service Commission of Wisconsin (PSCW) | Tax Repairs Regulatory Asset | ||||
Income Taxes | ||||
Amortization period | 50 years | |||
2020 and 2021 rates | Public Service Commission of Wisconsin (PSCW) | Tax Cuts and Jobs Act of 2017 | ||||
Income Taxes | ||||
Income Statement Impact of amortizing unprotected tax benefits | $ 0 | |||
2020 and 2021 rates | Public Service Commission of Wisconsin (PSCW) | Electric rates | Tax Cuts and Jobs Act of 2017 | ||||
Income Taxes | ||||
Amortization period | 2 years | 2 years | ||
2020 and 2021 rates | Public Service Commission of Wisconsin (PSCW) | Natural gas rates | Tax Cuts and Jobs Act of 2017 | ||||
Income Taxes | ||||
Amortization period | 4 years | 4 years |
Income Taxes - Components of de
Income Taxes - Components of deferred tax assets and liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Non-current | ||
Tax gross up - regulatory items | $ 132.6 | $ 152.7 |
Deferred revenues | 124.6 | 126.8 |
Future tax benefits | 14.8 | 41 |
Other | 82.3 | 64.5 |
Total deferred tax assets | 354.3 | 385 |
Non-current | ||
Property-related | 1,334.4 | 1,368.9 |
Deferred costs - Plant retirements | 237.4 | 215.5 |
Employee benefits and compensation | 49.3 | 55.8 |
Deferred costs - SSR | 47.7 | 51.1 |
Other | 42.7 | 41.1 |
Total deferred tax liabilities | 1,711.5 | 1,732.4 |
Deferred tax liability, net | $ 1,357.2 | $ 1,347.4 |
Income Taxes - Components of ne
Income Taxes - Components of net deferred tax assets (Details) - USD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Income Taxes | ||
Balance of tax benefit carryforwards, gross | $ 0 | $ 52.4 |
Balance of tax benefit carryforwards, deferred tax effect | 14.8 | 41 |
Domestic tax authority | ||
Income Taxes | ||
Tax credit carryforwards, gross | 0 | 0 |
Tax credit carryforwards, deferred tax effect | $ 14.8 | 37.1 |
State and local jurisdiction | ||
Income Taxes | ||
Tax credit carryforwards, gross | 0 | |
Tax credit carryforwards, deferred tax effect | 0.6 | |
Net operating loss carryforwards, gross | 52.4 | |
Net operating loss carryforwards, deferred tax effect | $ 3.3 |
Income Taxes - Unrecognized Tax
Income Taxes - Unrecognized Tax Benefits (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | |||
Unrecognized tax benefits | $ 0 | $ 0 | |
Interest expense in the consolidated income statements | 0 | 0 | $ 0 |
Penalties in the consolidated income statements | 0 | 0 | $ 0 |
Accrued interest on the consolidated balance sheets | 0 | 0 | |
Accrued penalties on the consolidated balance sheets | $ 0 | $ 0 |
Fair Value Measurements - Asset
Fair Value Measurements - Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Assets | ||
Derivative assets | $ 6.3 | $ 2 |
Liabilities | ||
Derivative liabilities | 4.1 | 5.4 |
Fair value measurements on a recurring basis | ||
Assets | ||
Derivative assets | 6.3 | 2 |
Liabilities | ||
Derivative liabilities | 4.1 | 5.4 |
Fair value measurements on a recurring basis | Level 1 | ||
Assets | ||
Derivative assets | 3 | 0.4 |
Liabilities | ||
Derivative liabilities | 2.9 | 5.2 |
Fair value measurements on a recurring basis | Level 2 | ||
Assets | ||
Derivative assets | 2.2 | 0.1 |
Liabilities | ||
Derivative liabilities | 1.2 | 0.2 |
Fair value measurements on a recurring basis | Level 3 | ||
Assets | ||
Derivative assets | 1.1 | 1.5 |
Liabilities | ||
Derivative liabilities | 0 | 0 |
Fair value measurements on a recurring basis | Natural gas contracts | ||
Assets | ||
Derivative assets | 3.8 | 0.4 |
Liabilities | ||
Derivative liabilities | 3.5 | 5.2 |
Fair value measurements on a recurring basis | Natural gas contracts | Level 1 | ||
Assets | ||
Derivative assets | 3 | 0.4 |
Liabilities | ||
Derivative liabilities | 2.9 | 5.2 |
Fair value measurements on a recurring basis | Natural gas contracts | Level 2 | ||
Assets | ||
Derivative assets | 0.8 | 0 |
Liabilities | ||
Derivative liabilities | 0.6 | 0 |
Fair value measurements on a recurring basis | Natural gas contracts | Level 3 | ||
Assets | ||
Derivative assets | 0 | 0 |
Liabilities | ||
Derivative liabilities | 0 | 0 |
Fair value measurements on a recurring basis | FTRs | ||
Assets | ||
Derivative assets | 1.1 | 1.5 |
Fair value measurements on a recurring basis | FTRs | Level 1 | ||
Assets | ||
Derivative assets | 0 | 0 |
Fair value measurements on a recurring basis | FTRs | Level 2 | ||
Assets | ||
Derivative assets | 0 | 0 |
Fair value measurements on a recurring basis | FTRs | Level 3 | ||
Assets | ||
Derivative assets | 1.1 | 1.5 |
Fair value measurements on a recurring basis | Coal contracts | ||
Assets | ||
Derivative assets | 1.4 | 0.1 |
Liabilities | ||
Derivative liabilities | 0.6 | 0.2 |
Fair value measurements on a recurring basis | Coal contracts | Level 1 | ||
Assets | ||
Derivative assets | 0 | 0 |
Liabilities | ||
Derivative liabilities | 0 | 0 |
Fair value measurements on a recurring basis | Coal contracts | Level 2 | ||
Assets | ||
Derivative assets | 1.4 | 0.1 |
Liabilities | ||
Derivative liabilities | 0.6 | 0.2 |
Fair value measurements on a recurring basis | Coal contracts | Level 3 | ||
Assets | ||
Derivative assets | 0 | 0 |
Liabilities | ||
Derivative liabilities | $ 0 | $ 0 |
Fair Value Measurements - Level
Fair Value Measurements - Level 3 Reconciliation (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Level 3 rollforward | |||
Balance at the beginning of the period | $ 1.5 | $ 4.4 | $ 2.4 |
Purchases | 3.1 | 6.8 | 9.4 |
Settlements | (3.5) | (9.7) | (7.4) |
Balance at the end of the period | $ 1.1 | $ 1.5 | $ 4.4 |
Fair Value Measurements - Finan
Fair Value Measurements - Financial Instruments (Details) - USD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Fair value of financial instruments | ||
Preferred stock | $ 30.4 | $ 30.4 |
Long-term debt, including current portion | 2,761.2 | 2,759.2 |
Carrying amount | ||
Fair value of financial instruments | ||
Preferred stock | 30.4 | 30.4 |
Long-term debt, including current portion | 2,761.2 | 2,759.2 |
Fair value | ||
Fair value of financial instruments | ||
Preferred stock | 32.3 | 29.5 |
Long-term debt, including current portion | $ 3,451.8 | $ 3,209.5 |
Derivative Instruments - Deriva
Derivative Instruments - Derivative Assets and Derivative Liabilities (Details) $ in Millions | Dec. 31, 2020USD ($)Instruments | Dec. 31, 2019USD ($) |
Derivative assets | ||
Other current derivative assets | $ 6.2 | $ 1.9 |
Other long-term derivative assets | 0.1 | 0.1 |
Derivative assets | 6.3 | 2 |
Derivative liabilities | ||
Other current derivative liabilities | 3.7 | 5.3 |
Other long-term derivative liabilities | 0.4 | 0.1 |
Derivative liabilities | 4.1 | 5.4 |
Natural gas contracts | ||
Derivative assets | ||
Other current derivative assets | 3.7 | 0.4 |
Other long-term derivative assets | 0.1 | 0 |
Derivative liabilities | ||
Other current derivative liabilities | 3.2 | 5.1 |
Other long-term derivative liabilities | 0.3 | 0.1 |
FTRs | ||
Derivative assets | ||
Other current derivative assets | 1.1 | 1.5 |
Derivative liabilities | ||
Other current derivative liabilities | 0 | 0 |
Coal contracts | ||
Derivative assets | ||
Other current derivative assets | 1.4 | 0 |
Other long-term derivative assets | 0 | 0.1 |
Derivative liabilities | ||
Other current derivative liabilities | 0.5 | 0.2 |
Other long-term derivative liabilities | $ 0.1 | $ 0 |
Derivatives designated as hedging instruments | ||
Derivative instruments | ||
Number of derivative instruments | Instruments | 0 |
Derivative Instruments - Gains
Derivative Instruments - Gains (Losses) and Notional Volumes (Details) gal in Millions, MWh in Millions, MMBTU in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2020USD ($)MWhMMBTUgal | Dec. 31, 2019USD ($)MMBTUMWhgal | Dec. 31, 2018USD ($)MWhMMBTUgal | |
Realized gains (losses) on derivatives | |||
Gains (losses) | $ (12.6) | $ (2.6) | $ 14.3 |
Natural gas contracts | |||
Realized gains (losses) on derivatives | |||
Gains (losses) | $ (15.1) | $ (11.3) | $ 9.7 |
Notional sales volumes | |||
Notional sales volumes | MMBTU | 62.1 | 61.6 | 53.4 |
Petroleum products contracts | |||
Realized gains (losses) on derivatives | |||
Gains (losses) | $ 0 | $ 0 | $ 1.2 |
Notional sales volumes | |||
Notional sales volumes (gallons) | gal | 0 | 0 | 4.2 |
FTRs | |||
Realized gains (losses) on derivatives | |||
Gains (losses) | $ 2.5 | $ 8.7 | $ 3.4 |
Notional sales volumes | |||
Notional sales volumes | MWh | 20.9 | 21.7 | 21.2 |
Derivative Instruments - Balanc
Derivative Instruments - Balance Sheet Offsetting (Details) - USD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Cash collateral | ||
Cash collateral posted in margin accounts | $ 6.7 | $ 8.5 |
Offsetting derivative assets | ||
Gross amount recognized on the balance sheet | 6.3 | 2 |
Gross amount not offset on the balance sheet | (2.9) | (0.4) |
Net amount | 3.4 | 1.6 |
Offsetting derivative liabilities | ||
Gross amount recognized on the balance sheet | 4.1 | 5.4 |
Gross amount not offset on the balance sheet | (2.9) | (5.2) |
Net amount | $ 1.2 | 0.2 |
Cash collateral posted | $ 4.8 |
Employee Benefits - Change in B
Employee Benefits - Change in Benefit Obligations and Plan Assets (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Pension Benefits | |||
Change in benefit obligation | |||
Obligation at January 1 | $ 1,148.3 | $ 1,099.4 | |
Service cost | 12.5 | 12.6 | $ 13.2 |
Interest cost | 37.7 | 45.2 | 42.3 |
Participant contributions | 0 | 0 | |
Plan amendments | 0 | 0 | |
Net transfer from/to affiliates | 0.5 | (5.3) | |
Actuarial loss (gain) | 94.1 | 81.5 | |
Benefit payments | (80) | (85.1) | |
Transfer | 0 | 0 | |
Obligation at December 31 | 1,213.1 | 1,148.3 | 1,099.4 |
Change in fair value of plan assets | |||
Beginning balance at January 1 | 1,094.6 | 1,019.8 | |
Actual return on plan assets | 108.3 | 156.7 | |
Employer contributions | 3.9 | 3.8 | |
Participant contributions | 0 | 0 | |
Net transfer from/to affiliates | 0.4 | (0.6) | |
Benefit payments | (80) | (85.1) | |
Ending balance at December 31 | 1,127.2 | 1,094.6 | 1,019.8 |
Funded status at December 31 | (85.9) | (53.7) | |
OPEB Benefits | |||
Change in benefit obligation | |||
Obligation at January 1 | 207.3 | 227.7 | |
Service cost | 4.2 | 4.5 | 6.9 |
Interest cost | 6.8 | 9.5 | 11.1 |
Participant contributions | 6.9 | 6.1 | |
Plan amendments | (2.5) | 2.7 | |
Net transfer from/to affiliates | 0.2 | 0 | |
Actuarial loss (gain) | (1.9) | (29.8) | |
Benefit payments | (17.5) | (16.2) | |
Federal subsidy on benefits paid | 1.2 | 1.1 | |
Transfer | 1.4 | 1.7 | |
Obligation at December 31 | 206.1 | 207.3 | 227.7 |
Change in fair value of plan assets | |||
Beginning balance at January 1 | 228.5 | 201.5 | |
Actual return on plan assets | 27 | 35.4 | |
Employer contributions | 0 | 1.7 | |
Participant contributions | 6.9 | 6.1 | |
Net transfer from/to affiliates | 0 | 0 | |
Benefit payments | (17.5) | (16.2) | |
Ending balance at December 31 | 244.9 | 228.5 | $ 201.5 |
Funded status at December 31 | $ 38.8 | $ 21.2 |
Employee Benefits - Amounts Rec
Employee Benefits - Amounts Recognized on the Balance Sheets (Details) - USD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Defined Benefit Plan Disclosure [Line Items] | ||
Pension and OPEB obligations | $ 85.9 | $ 59.8 |
Pension Benefits | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Other long-term assets | 0 | 6.1 |
Pension and OPEB obligations | 85.9 | 59.8 |
Total net (liabilities) assets | (85.9) | (53.7) |
OPEB Benefits | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Other long-term assets | 38.8 | 21.2 |
Pension and OPEB obligations | 0 | 0 |
Total net (liabilities) assets | $ 38.8 | $ 21.2 |
Employee Benefits - Accumulated
Employee Benefits - Accumulated Benefit Obligations (Details) - Pension Plan - USD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Defined Benefit Plan Disclosure [Line Items] | ||
Accumulated benefit obligation | $ 1,212 | $ 1,147 |
Information for pension plans with an accumulated benefit obligation in excess of plan assets | ||
Accumulated benefit obligation | 1,212 | 1,039.5 |
Fair value of plan assets | 1,127.2 | 980.9 |
Information for pension plans with a projected benefit obligation in excess of plan assets | ||
Projected benefit obligation | 1,213.1 | 1,040.7 |
Fair value of plan assets | $ 1,127.2 | $ 980.9 |
Employee Benefits - Amounts Not
Employee Benefits - Amounts Not Yet Recognized in Net Periodic Benefit Cost (Details) - USD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 |
Pension Benefits | ||
Net regulatory assets (liabilities) | ||
Net actuarial loss (gain) | $ 475.1 | $ 460.1 |
Prior service credits | (2.2) | (2.3) |
Total | 472.9 | 457.8 |
OPEB Benefits | ||
Net regulatory assets (liabilities) | ||
Net actuarial loss (gain) | (117.9) | (115.3) |
Prior service credits | (3.4) | (1.5) |
Total | $ (121.3) | $ (116.8) |
Employee Benefits - Net Periodi
Employee Benefits - Net Periodic Benefit Cost (Credit) (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Pension Benefits | |||
Components of net periodic benefit cost (credit) (including amounts capitalized to the balance sheets) | |||
Service cost | $ 12.5 | $ 12.6 | $ 13.2 |
Interest cost | 37.7 | 45.2 | 42.3 |
Expected return on plan assets | (69.4) | (72.4) | (75.2) |
Plan settlement | 2.4 | 0 | 0 |
Amortization of prior service cost (credit) | (0.1) | 0.5 | 0.8 |
Amortization of net actuarial loss (gain) | 37.8 | 28 | 38 |
Net periodic benefit cost (credit) | 20.9 | 13.9 | 19.1 |
OPEB Benefits | |||
Components of net periodic benefit cost (credit) (including amounts capitalized to the balance sheets) | |||
Service cost | 4.2 | 4.5 | 6.9 |
Interest cost | 6.8 | 9.5 | 11.1 |
Expected return on plan assets | (15.7) | (14.3) | (15.5) |
Plan settlement | 0 | 0 | 0 |
Amortization of prior service cost (credit) | (0.6) | (1.9) | (2.2) |
Amortization of net actuarial loss (gain) | (10.6) | (2.1) | 0 |
Net periodic benefit cost (credit) | $ (15.9) | $ (4.3) | $ 0.3 |
Employee Benefits - Assumptions
Employee Benefits - Assumptions (Details) | 12 Months Ended | |||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Pension Benefits | Benefit obligation assumptions | ||||
Weighted average assumptions - benefit obligations | ||||
Discount rate | 2.63% | 3.39% | 4.30% | |
Rate of compensation increase | 4.00% | 4.00% | ||
Interest credit rate | 5.16% | 5.16% | ||
Pension Benefits | Net periodic benefit cost assumptions | ||||
Weighted average assumptions - net periodic benefit cost | ||||
Discount rate | 3.37% | 4.30% | 3.65% | |
Expected return on plan assets | 6.75% | 7.00% | 7.00% | |
Rate of compensation increase | 4.00% | 3.40% | 3.40% | |
Interest credit rate | 5.16% | 5.18% | 5.18% | |
Pension Benefits | Net periodic benefit cost assumptions | Subsequent event | ||||
Weighted average assumptions - net periodic benefit cost | ||||
Expected return on plan assets | 6.75% | |||
OPEB Benefits | Benefit obligation assumptions | ||||
Weighted average assumptions - benefit obligations | ||||
Discount rate | 2.65% | 3.40% | 4.30% | |
OPEB Benefits | Benefit obligation assumptions | Pre 65 | ||||
Medical cost trend rates | ||||
Assumed medical cost trend rate | 5.85% | 6.00% | ||
Ultimate trend rate | 5.00% | 5.00% | ||
Year ultimate trend rate is reached | 2028 | 2028 | ||
OPEB Benefits | Benefit obligation assumptions | Post 65 | ||||
Medical cost trend rates | ||||
Assumed medical cost trend rate | 5.86% | 6.04% | ||
Ultimate trend rate | 5.00% | 5.00% | ||
Year ultimate trend rate is reached | 2028 | 2028 | ||
OPEB Benefits | Net periodic benefit cost assumptions | ||||
Weighted average assumptions - net periodic benefit cost | ||||
Discount rate | 3.40% | 4.30% | 3.65% | |
Expected return on plan assets | 7.00% | 7.25% | 7.25% | |
OPEB Benefits | Net periodic benefit cost assumptions | Subsequent event | ||||
Weighted average assumptions - net periodic benefit cost | ||||
Expected return on plan assets | 7.00% | |||
OPEB Benefits | Net periodic benefit cost assumptions | Pre 65 | ||||
Medical cost trend rates | ||||
Assumed medical cost trend rate | 6.00% | 6.25% | 6.50% | |
Ultimate trend rate | 5.00% | 5.00% | 5.00% | |
Year ultimate trend rate is reached | 2028 | 2024 | 2024 | |
OPEB Benefits | Net periodic benefit cost assumptions | Post 65 | ||||
Medical cost trend rates | ||||
Assumed medical cost trend rate | 6.04% | 6.12% | 6.18% | |
Ultimate trend rate | 5.00% | 5.00% | 5.00% | |
Year ultimate trend rate is reached | 2028 | 2028 | 2028 |
Employee Benefits - Target Asse
Employee Benefits - Target Asset Allocations (Details) | Dec. 31, 2020 |
Pension Plan | Equity securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 35.00% |
Pension Plan | Fixed income securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 55.00% |
Pension Plan | Private Equity and Real Estate | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 10.00% |
OPEB Plan | Largest trust 1 | Equity securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 50.00% |
OPEB Plan | Largest trust 1 | Fixed income securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 50.00% |
OPEB Plan | Largest trust 2 | Equity securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 70.00% |
OPEB Plan | Largest trust 2 | Fixed income securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 30.00% |
Employee Benefits - Plan Assets
Employee Benefits - Plan Assets (Details) - USD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Pension Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | $ 1,127.2 | $ 1,094.6 | $ 1,019.8 |
Pension Plan | Level 1, 2, and 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 800.6 | 746.6 | |
Pension Plan | Level 1, 2, and 3 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 134.5 | 103.3 | |
Pension Plan | Level 1, 2, and 3 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 106 | 98.4 | |
Pension Plan | Level 1, 2, and 3 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 516.5 | 488 | |
Pension Plan | Level 1, 2, and 3 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 43.6 | 56.9 | |
Pension Plan | Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 240.5 | 278.5 | |
Pension Plan | Level 1 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 134.5 | 103.3 | |
Pension Plan | Level 1 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 106 | 98.4 | |
Pension Plan | Level 1 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 49.1 | |
Pension Plan | Level 1 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 27.7 | |
Pension Plan | Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 560.1 | 468.1 | |
Pension Plan | Level 2 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Plan | Level 2 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Plan | Level 2 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 516.5 | 438.9 | |
Pension Plan | Level 2 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 43.6 | 29.2 | |
Pension Plan | Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Plan | Level 3 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Plan | Level 3 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Plan | Level 3 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Plan | Level 3 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Plan | Investments measured at net asset value per share | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 326.6 | 348 | |
OPEB Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 244.9 | 228.5 | $ 201.5 |
OPEB Plan | Level 1, 2, and 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 157.3 | 140.8 | |
OPEB Plan | Level 1, 2, and 3 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 36.5 | 27.9 | |
OPEB Plan | Level 1, 2, and 3 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 31.4 | 28.5 | |
OPEB Plan | Level 1, 2, and 3 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 85.1 | 75.7 | |
OPEB Plan | Level 1, 2, and 3 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 4.3 | 8.7 | |
OPEB Plan | Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 94.2 | 85.3 | |
OPEB Plan | Level 1 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 36.5 | 27.9 | |
OPEB Plan | Level 1 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 31.4 | 28.5 | |
OPEB Plan | Level 1 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 26.3 | 23.1 | |
OPEB Plan | Level 1 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 5.8 | |
OPEB Plan | Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 63.1 | 55.5 | |
OPEB Plan | Level 2 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
OPEB Plan | Level 2 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
OPEB Plan | Level 2 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 58.8 | 52.6 | |
OPEB Plan | Level 2 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 4.3 | 2.9 | |
OPEB Plan | Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
OPEB Plan | Level 3 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
OPEB Plan | Level 3 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
OPEB Plan | Level 3 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
OPEB Plan | Level 3 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
OPEB Plan | Investments measured at net asset value per share | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | $ 87.6 | $ 87.7 |
Employee Benefits - Cash Flows
Employee Benefits - Cash Flows (Details) $ in Millions | Dec. 31, 2020USD ($) |
Pension Benefits | |
Defined Benefit Plan Disclosure [Line Items] | |
Expected contributions to the plans during the next year | $ 3.5 |
2021 | 87.8 |
2022 | 84.5 |
2023 | 83.5 |
2024 | 80 |
2025 | 77.9 |
2026 through 2030 | 342.9 |
OPEB Benefits | |
Defined Benefit Plan Disclosure [Line Items] | |
Expected contributions to the plans during the next year | 0.1 |
2021 | 11.4 |
2022 | 11.3 |
2023 | 11.4 |
2024 | 11.1 |
2025 | 11 |
2026 through 2030 | $ 54.4 |
Employee Benefits - Defined Con
Employee Benefits - Defined Contribution Benefit Plans (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Retirement Benefits [Abstract] | |||
Total costs incurred for defined contribution benefit plans | $ 11.4 | $ 11.9 | $ 11.9 |
Segment Information (Details)
Segment Information (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2020USD ($)segment | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | |
Segment Reporting [Abstract] | |||
Number of reportable segments | segment | 2 | ||
Significant items reported in the other segment | $ | $ 0 | $ 0 | $ 0 |
Variable Interest Entities (Det
Variable Interest Entities (Details) - Power purchase agreement $ in Millions | 12 Months Ended |
Dec. 31, 2020USD ($)MW | |
Variable interest entities | |
Firm capacity from power purchase agreement (in megawatts) | MW | 236 |
Minimum energy requirements over remaining term of power purchase agreement (in megawatts) | MW | 0 |
Remaining term of power purchase agreement (in years) | 1 year |
Residual guarantee associated with power purchase agreement | $ | $ 0 |
Required capacity payments over remaining term of power purchase agreement | $ | $ 13.6 |
Commitments and Contingencies -
Commitments and Contingencies - Unconditional Purchase Obligations (Details) $ in Millions | Dec. 31, 2020USD ($) |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | $ 9,035.3 |
2021 | 805.1 |
2022 | 784.1 |
2023 | 773.8 |
2024 | 647.7 |
2025 | 660.1 |
Later Years | 5,364.5 |
Nuclear | Electric | |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | 7,843.9 |
2021 | 501.1 |
2022 | 531.2 |
2023 | 563.1 |
2024 | 596.8 |
2025 | 632.6 |
Later Years | 5,019.1 |
Coal supply and transportation | Electric | |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | 548.9 |
2021 | 226.8 |
2022 | 176.4 |
2023 | 145.7 |
2024 | 0 |
2025 | 0 |
Later Years | 0 |
Purchased power | Electric | |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | 59.6 |
2021 | 12.3 |
2022 | 10.5 |
2023 | 7.6 |
2024 | 3.6 |
2025 | 2.3 |
Later Years | 23.3 |
Natural gas utility supply and transportation | Natural gas | |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | 582.9 |
2021 | 64.9 |
2022 | 66 |
2023 | 57.4 |
2024 | 47.3 |
2025 | 25.2 |
Later Years | $ 322.1 |
Commitments and Contingencies_2
Commitments and Contingencies - Environmental Matters (Details) T in Millions, $ in Millions | 1 Months Ended | 12 Months Ended | 15 Months Ended | |
Oct. 31, 2020States | Dec. 31, 2020USD ($)performance_obligationsTMW | Dec. 31, 2019USD ($) | Mar. 31, 2019MW | |
Climate Change | Electric | ||||
Air Quality | ||||
No other source category, except for EGUs, should contribute to GHG emissions above this percentage threshold | 3.00% | |||
Company goal met in 2019 for percentage of carbon dioxide emissions reductions by 2030 | 40.00% | |||
Company goal for percentage of carbon dioxide emissions reduction below 2005 levels by 2030 | 70.00% | |||
Company near-term goal for percentage of carbon dioxide emission reduction by 2025 | 55.00% | |||
Capacity of coal generation retired since the beginning of 2018 | MW | 1,500 | |||
Capacity of fossil-fueled generation to be retired by 2025, in megawatts | MW | 1,800 | |||
Per mile rate of methane emission reduction | 30.00% | |||
Carbon dioxide emissions | T | 14.7 | |||
Climate Change | Natural gas | ||||
Air Quality | ||||
Carbon dioxide emissions | T | 3.9 | |||
Cross State Air Pollution Rule Update Rule Revision | Electric | ||||
Air Quality | ||||
Number of states in group 2 for CSAPR update rule revision | States | 9 | |||
Number of states affected by CSAPR update rule revision | States | 21 | |||
Steam Electric Effluent Guidelines | Electric | ||||
Water Quality | ||||
Number of new ELG rule requirements that affect us | performance_obligations | 2 | |||
Expected capital investment to achieve required discharge limits | $ 100 | |||
Manufactured Gas Plant Remediation | Natural gas | ||||
Manufactured Gas Plant Remediation | ||||
Regulatory assets recorded for remediation of manufactured gas plant sites | 18.5 | $ 22.1 | ||
Reserves recorded for future environmental remediation of manufactured gas plant sites | $ 10.3 | $ 12.1 | ||
Renewables, Efficiency, and Conservation | Electric | Wisconsin | ||||
Renewables, Efficiency, and Conservation | ||||
Annual state renewable portfolio requirement, as a percent | 10.00% | |||
Required renewable energy percent achieved | 8.27% | |||
Percent of annual operating revenues used to fund renewable program | 1.20% |
Supplemental Cash Flow Inform_3
Supplemental Cash Flow Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Supplemental Cash Flow Information [Abstract] | |||
Cash paid for interest, net of amount capitalized | $ 464.7 | $ 475.2 | $ 115 |
Cash paid for income taxes, net | 101.2 | 45.8 | 17.7 |
Accounts payable related to construction costs | 43 | 36.1 | 14 |
Receivable related to insurance proceeds for property damage | $ 2.7 | $ 0 | $ 0 |
Regulatory Environment - COVID-
Regulatory Environment - COVID-19 (Details) | Mar. 24, 2020order |
Public Service Commission of Wisconsin | |
Public Utilities, General Disclosures [Line Items] | |
Number of orders issued in response to COVID-19 | 2 |
Regulatory Environment - Tax Cu
Regulatory Environment - Tax Cuts and Jobs Act of 2017 (Details) $ in Millions | 1 Months Ended | |
May 31, 2018customer | Dec. 31, 2017USD ($) | |
MPSC | ||
Public Utilities, General Disclosures [Line Items] | ||
Number of electric customers served in Michigan | customer | 1 | |
Electric rates | 2018 and 2019 rates | Public Service Commission of Wisconsin (PSCW) | ||
Public Utilities, General Disclosures [Line Items] | ||
Percentage of current tax benefit from Tax Cuts and Jobs Act of 2017 to be used to reduce regulatory assets | 80.00% | |
Percent of current tax benefit from Tax Cuts and Jobs Act of 2017 to be returned to customers via bill credits | 20.00% | |
Natural gas rates | 2018 and 2019 rates | Public Service Commission of Wisconsin (PSCW) | ||
Public Utilities, General Disclosures [Line Items] | ||
Percent of current tax benefit from Tax Cuts and Jobs Act of 2017 to be returned to customers via bill credits | 100.00% | |
Tax Cuts and Jobs Act of 2017 | ||
Public Utilities, General Disclosures [Line Items] | ||
Estimated tax benefit related to the remeasurement of deferred income taxes from tax legislation | $ | $ 1,102 |
Regulatory Environment - 2020 a
Regulatory Environment - 2020 and 2021 Rates (Details) - Public Service Commission of Wisconsin (PSCW) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended |
Dec. 31, 2019 | Dec. 31, 2020 | |
2020 and 2021 rates | ||
Public Utilities, General Disclosures [Line Items] | ||
Approved return on equity (as a percent) | 10.00% | |
Approved common equity component average (as a percent) | 52.50% | |
Percentage of first 25 basis points of additional earnings retained by the utility | 100.00% | |
Return on equity in excess of authorized amount (as a percent) | 0.25% | |
Percentage of additional earnings between 25 and 75 basis points refunded to customers | 50.00% | |
Return on equity in excess of first 25 basis points above authorized amount (as a percent) | 0.50% | |
Percentage of earnings in excess of 75 basis points refunded to customers | 100.00% | |
Electric rates | 2020 rates | ||
Public Utilities, General Disclosures [Line Items] | ||
Approved rate increase | $ 15.3 | |
Approved rate increase (as a percent) | 0.50% | |
Electric rates | 2020 and 2021 rates | ||
Public Utilities, General Disclosures [Line Items] | ||
Pleasant Prairie power plant's book value to be securitized | $ 100 | |
Electric rates | Tax Cuts and Jobs Act of 2017 | 2020 rates | ||
Public Utilities, General Disclosures [Line Items] | ||
Amortization of regulatory liabilities | 65 | |
Electric rates | Tax Cuts and Jobs Act of 2017 | 2021 rates | ||
Public Utilities, General Disclosures [Line Items] | ||
Amortization of regulatory liabilities | $ 65 | |
Electric rates | Tax Cuts and Jobs Act of 2017 | 2020 and 2021 rates | ||
Public Utilities, General Disclosures [Line Items] | ||
Amortization period | 2 years | 2 years |
Natural gas rates | 2020 rates | ||
Public Utilities, General Disclosures [Line Items] | ||
Approved rate increase | $ 10.4 | |
Approved rate increase (as a percent) | 2.80% | |
Natural gas rates | Tax Cuts and Jobs Act of 2017 | 2020 rates | ||
Public Utilities, General Disclosures [Line Items] | ||
Amortization of regulatory liabilities | $ (5) | |
Natural gas rates | Tax Cuts and Jobs Act of 2017 | 2021 rates | ||
Public Utilities, General Disclosures [Line Items] | ||
Amortization of regulatory liabilities | $ (5) | |
Natural gas rates | Tax Cuts and Jobs Act of 2017 | 2020 and 2021 rates | ||
Public Utilities, General Disclosures [Line Items] | ||
Amortization period | 4 years | 4 years |
Steam rates | 2020 rates | ||
Public Utilities, General Disclosures [Line Items] | ||
Approved rate increase | $ 1.9 | |
Approved rate increase (as a percent) | 8.60% |
Regulatory Environment - 2018 a
Regulatory Environment - 2018 and 2019 Rates (Details) - Public Service Commission of Wisconsin (PSCW) - 2018 and 2019 rates - USD ($) $ in Millions | 1 Months Ended | 24 Months Ended |
Sep. 30, 2017 | Dec. 31, 2019 | |
Public Utilities, General Disclosures [Line Items] | ||
Approved return on equity (as a percent) | 10.20% | |
Income statement impact of flow through of repair-related deferred tax liabilities | $ 0 | |
Percentage of first 50 basis points of additional utility earnings shared with customers | 50.00% | |
Return on equity in excess of authorized amount (as a percent) | 0.50% |
Regulatory Environment - Liquef
Regulatory Environment - Liquefied Natural Gas Facilities (Details) - Public Service Commission of Wisconsin (PSCW) - Liquefied Natural Gas Facilities $ in Millions | Nov. 01, 2019USD ($)Bcf |
Public Utilities, General Disclosures [Line Items] | |
Natural gas supply | Bcf | 1 |
Entity's estimated project costs | $ | $ 185 |
Regulatory Environment - Solar
Regulatory Environment - Solar Generation Project (Details) - Public Service Commission of Wisconsin (PSCW) - Badger Hollow II $ in Millions | Mar. 31, 2020USD ($)MW |
Public Utilities, General Disclosures [Line Items] | |
Solar project megawatts that approval was requested for from the PSCW | MW | 100 |
Estimated share of cost for solar project(s) | $ | $ 130 |
Other Income, Net (Details)
Other Income, Net (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Other Income and Expenses [Abstract] | |||
Non-service components of net periodic benefit costs | $ 11.8 | $ 9.2 | $ 5.7 |
AFUDC - Equity | 7 | 3.7 | 3.9 |
Other, net | (0.3) | 9.8 | 10.6 |
Other income, net | $ 18.5 | $ 22.7 | $ 20.2 |
Quarterly Financial Informati_3
Quarterly Financial Information (Unaudited) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2020 | Sep. 30, 2020 | Jun. 30, 2020 | Mar. 31, 2020 | Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Operating revenues | $ 826.3 | $ 900.2 | $ 769.5 | $ 871 | $ 860.1 | $ 884.1 | $ 791.7 | $ 960.8 | $ 3,367 | $ 3,496.7 | $ 3,625 |
Operating income | 180.3 | 244.6 | 188.6 | 247 | 153.6 | 201.1 | 182.6 | 222.9 | 860.5 | 760.2 | 402.5 |
Net income attributed to common shareholder | $ 61.7 | $ 114.6 | $ 70.6 | $ 118.7 | $ 61.9 | $ 100.6 | $ 84.9 | $ 114.7 | $ 365.6 | $ 362.1 | $ 358.3 |
Schedule II - Valuation and Q_2
Schedule II - Valuation and Qualifying Accounts (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Valuation and qualifying accounts | |||
Balance at beginning of period | $ 38.1 | $ 40.9 | $ 39.5 |
Expense | 24.6 | 32.7 | 32.3 |
Deferral | 14.8 | (12.6) | (9.1) |
Net write-offs | (18.2) | (22.9) | (21.8) |
Balance at end of period | $ 59.3 | $ 38.1 | $ 40.9 |