COVER PAGE
COVER PAGE - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Jan. 31, 2024 | Jun. 30, 2023 | |
Cover [Abstract] | |||
Document Type | 10-K | ||
Document Annual Report | true | ||
Document Period End Date | Dec. 31, 2023 | ||
Document Transition Report | false | ||
Entity File Number | 001-03016 | ||
Entity Registrant Name | WISCONSIN PUBLIC SERVICE CORPORATION | ||
Entity Tax Identification Number | 39-0715160 | ||
Entity Incorporation, State or Country Code | WI | ||
Entity Address, Address Line One | 2830 South Ashland Avenue | ||
Entity Address, Address Line Two | P.O. Box 19001 | ||
Entity Address, City or Town | Green Bay | ||
Entity Address, State or Province | WI | ||
Entity Address, Postal Zip Code | 54307-9001 | ||
City Area Code | 800 | ||
Local Phone Number | 450-7260 | ||
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 | ||
Document Financial Statement Error Correction | false | ||
Entity Shell Company | false | ||
Entity Public Float | $ 0 | ||
Entity Common Stock, Shares Outstanding | 23,896,962 | ||
Entity Central Index Key | 0000107833 | ||
Current Fiscal Year End Date | --12-31 | ||
Document Fiscal Year Focus | 2023 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false |
AUDIT INFORMATION
AUDIT INFORMATION | 12 Months Ended |
Dec. 31, 2023 | |
Audit Information [Abstract] | |
Auditor Name | DELOITTE & TOUCHE LLP |
Auditor Location | Milwaukee, Wisconsin |
Auditor Firm ID | 34 |
INCOME STATEMENTS
INCOME STATEMENTS - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Income Statement [Abstract] | |||
Operating revenues | $ 1,681.4 | $ 1,785.2 | $ 1,520.9 |
Operating expenses | |||
Cost of sales | 606.8 | 845.1 | 597.2 |
Other operation and maintenance | 434.3 | 362.5 | 406.4 |
Depreciation and amortization | 226.9 | 199.8 | 188.6 |
Property and revenue taxes | 47.4 | 42.4 | 39.9 |
Total operating expenses | 1,315.4 | 1,449.8 | 1,232.1 |
Operating income | 366 | 335.4 | 288.8 |
Other income, net | 45.9 | 42.3 | 38.2 |
Interest expense | 89 | 70.5 | 64.7 |
Other expense | (43.1) | (28.2) | (26.5) |
Income before income taxes | 322.9 | 307.2 | 262.3 |
Income tax expense | 62.7 | 72.2 | 31.2 |
Net income | $ 260.2 | $ 235 | $ 231.1 |
BALANCE SHEETS
BALANCE SHEETS - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Current assets | ||
Cash and cash equivalents | $ 1.4 | $ 0.5 |
Materials, supplies, and inventories | 171.1 | 164.5 |
Prepaid taxes | 48.9 | 58.4 |
Other prepayments | 6.5 | 6 |
Other | 20.5 | 36.1 |
Current assets | 503.3 | 565.1 |
Long-term assets | ||
Property, plant, and equipment, net of accumulated depreciation and amortization of $2,033.4 and $1,820.6, respectively | 5,801.4 | 5,376.7 |
Regulatory assets | 360.6 | 365.5 |
Goodwill | 36.4 | 36.4 |
Pension and OPEB assets | 284.5 | 282.1 |
Other | 44.9 | 83 |
Long-term assets | 6,527.8 | 6,143.7 |
Total assets | 7,031.1 | 6,708.8 |
Current liabilities | ||
Short-term debt | 310.3 | 194.9 |
Other | 93.6 | 98.2 |
Current liabilities | 580 | 519.8 |
Long-term liabilities | ||
Long-term debt | 2,008.1 | 1,999.9 |
Deferred income taxes | 924.4 | 860.7 |
Deferred ITCs | 71.9 | 78.5 |
Regulatory liabilities | 672 | 650.3 |
Environmental remediation liabilities | 85.3 | 88.6 |
Other | 135.7 | 127.7 |
Long-term liabilities | 3,897.4 | 3,805.7 |
Commitments and contingencies (Note 21) | ||
Common shareholder's equity | ||
Common stock – $4 par value; 32,000,000 shares authorized; 23,896,962 shares issued and outstanding | 95.6 | 95.6 |
Additional paid in capital | 1,782 | 1,616.8 |
Retained earnings | 676.1 | 670.9 |
Common shareholder's equity | 2,553.7 | 2,383.3 |
Total liabilities and equity | 7,031.1 | 6,708.8 |
Nonrelated Party | ||
Current assets | ||
Accounts receivable | 219.2 | 267.8 |
Current liabilities | ||
Accounts payable | 118.5 | 176.9 |
Related Party | ||
Current assets | ||
Accounts receivable | 35.7 | 31.8 |
Current liabilities | ||
Accounts payable | $ 57.6 | $ 49.8 |
BALANCE SHEETS (PARENTHETICAL)
BALANCE SHEETS (PARENTHETICAL) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Statement of Financial Position [Abstract] | ||
Accounts receivable and unbilled revenues, reserves | $ 10.9 | $ 11.7 |
Property, plant, and equipment, accumulated depreciation and amortization | $ 2,033.4 | $ 1,820.6 |
Common stock, par value | $ 4 | $ 4 |
Common stock, shares authorized | 32,000,000 | 32,000,000 |
Common stock, shares issued | 23,896,962 | 23,896,962 |
Common stock, shares outstanding | 23,896,962 | 23,896,962 |
STATEMENTS OF CASH FLOWS
STATEMENTS OF CASH FLOWS - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Operating Activities | |||
Net income | $ 260.2 | $ 235 | $ 231.1 |
Reconciliation to cash provided by operating activities | |||
Depreciation and amortization | 226.9 | 199.8 | 188.6 |
Deferred income taxes and ITCs, net | 44.9 | 70 | 84.6 |
Pension and OPEB income | (7.6) | (25.3) | (12.8) |
Net change in transmission regulatory asset and liability | 1.5 | (21.6) | 3 |
Change in – | |||
Accounts receivable and unbilled revenues, net | 47.8 | (56.6) | (24.5) |
Materials, supplies, and inventories | (1.8) | (51.6) | (20.2) |
Prepaid taxes | 9.5 | (18.4) | (1) |
Collateral on deposit | 10.7 | (20.3) | (2.6) |
Other current assets | 2 | (2.3) | (0.7) |
Accounts payable | (45.4) | 38.4 | 3.2 |
Other current liabilities | 3.6 | 1.2 | 0.9 |
Other, net | 23.4 | (60.1) | (11.3) |
Net cash provided by operating activities | 575.7 | 288.2 | 438.3 |
Investing activities | |||
Capital expenditures | (453.8) | (433.8) | (389.7) |
Acquisition of Whitewater | (38) | 0 | 0 |
Acquisition of Red Barn | (143.8) | 0 | 0 |
Proceeds from cash surrender value of life insurance | 0 | 4.4 | 0 |
Reimbursement for ATC's construction costs | 0.1 | 10 | 0 |
Other, net | (2.5) | 0.4 | (8) |
Net cash used in investing activities | (638) | (419) | (397.7) |
Financing activities | |||
Retirement of long-term debt | 0 | 0 | (400) |
Issuance of long-term debt | 0 | 300 | 450 |
Change in short-term debt | 115.4 | (136.1) | 120.5 |
Payment of dividends to parent | (255) | (120) | (260) |
Equity contribution from parent | 165 | 125 | 55 |
Other, net | (0.2) | (2) | (6.4) |
Net cash provided by (used in) financing activities | 25.2 | 166.9 | (40.9) |
Net change in cash, cash equivalents, and restricted cash | (37.1) | 36.1 | (0.3) |
Cash, cash equivalents, and restricted cash at beginning of year | 38.5 | 2.4 | 2.7 |
Cash, cash equivalents, and restricted cash at end of year | $ 1.4 | $ 38.5 | $ 2.4 |
STATEMENTS OF EQUITY
STATEMENTS OF EQUITY - USD ($) $ in Millions | Total | Total common shareholder's equity | Common stock | Additional paid-in capital | Retained earnings |
Balance at Dec. 31, 2020 | $ 2,116.7 | $ 95.6 | $ 1,436.4 | $ 584.7 | |
Equity | |||||
Net income | $ 231.1 | 231.1 | 0 | 0 | 231.1 |
Equity contribution from parent | 55 | 55 | 0 | 55 | 0 |
Payment of dividends to parent | (260) | (260) | 0 | 0 | (260) |
Stock-based compensation and other | 0.2 | 0 | 0.1 | 0.1 | |
Balance at Dec. 31, 2021 | 2,143 | 95.6 | 1,491.5 | 555.9 | |
Equity | |||||
Net income | 235 | 235 | 0 | 0 | 235 |
Equity contribution from parent | 125 | 125 | 0 | 125 | 0 |
Payment of dividends to parent | (120) | (120) | 0 | 0 | (120) |
Stock-based compensation and other | 0.3 | 0 | 0.3 | 0 | |
Balance at Dec. 31, 2022 | 2,383.3 | 95.6 | 1,616.8 | 670.9 | |
Equity | |||||
Net income | 260.2 | 260.2 | 0 | 0 | 260.2 |
Equity contribution from parent | 165 | 165 | 0 | 165 | 0 |
Payment of dividends to parent | $ (255) | (255) | 0 | 0 | (255) |
Stock-based compensation and other | 0.2 | 0 | 0.2 | 0 | |
Balance at Dec. 31, 2023 | $ 2,553.7 | $ 95.6 | $ 1,782 | $ 676.1 |
SUMMARY OF SIGNIFICANT ACCOUNTI
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2023 | |
Accounting Policies [Abstract] | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (a) Nature of Operations —We are an electric and natural gas utility company that serves electric and natural gas customers in northeastern Wisconsin. We are subject to the jurisdiction of, and regulation by, the PSCW, which has general supervisory and regulatory powers over virtually all phases of the public utility industry in Wisconsin. In addition, we are subject to the jurisdiction of the FERC, which regulates our natural gas pipelines and wholesale electric rates. We are an indirect, wholly owned subsidiary of WEC Energy Group. As used in these notes, the term "financial statements" includes the income statements, balance sheets, statements of cash flows, and statements of equity, unless otherwise noted. These financial statements reflect our proportionate interests in certain jointly owned utility facilities. See Note 8, Jointly Owned Utility Facilities, for more information. 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. (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 4, 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. 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 Wisconsin, our 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 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 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. Under normal circumstances, 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. However, as a result of the extreme weather in the Midwest in February 2021, the cost of gas purchased for our natural gas customers was temporarily driven significantly higher than our normal winter weather expectations. See Note 23, Regulatory Environment, for more information on the recovery of these high natural gas costs. 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. 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 5, Credit Losses. 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, 2023 and 2022. 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. (f) Materials, Supplies, and Inventories —Our inventories as of December 31 consisted of: (in millions) 2023 2022 Materials and supplies 79.9 59.3 Fossil fuel 52.1 40.2 Natural gas in storage 39.1 65.0 Total $ 171.1 $ 164.5 (g) Regulatory Assets and Liabilities —The economic effects of regulation can result in regulated companies recording costs and revenues that are allowed in the ratemaking 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 6, 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 2.93%, 2.67%, and 2.66% in 2023, 2022, and 2021, 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 3 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. See Note 7, Property, Plant, and Equipment, for more information. (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 7.46%, 7.55%, and 7.55% for 2023, 2022, and 2021, respectively. Our average AFUDC wholesale rates were 4.60%, 5.49%, and 1.04% for 2023, 2022, and 2021, respectively. We recorded the following AFUDC for the years ended December 31: (in millions) 2023 2022 2021 AFUDC-Debt $ 2.9 $ 2.3 $ 3.5 AFUDC-Equity 7.6 5.8 9.0 (j) Asset Impairment —Goodwill and other intangible assets with indefinite lives are subject to an annual impairment test. Interim impairment tests are performed when impairment indicators are present. During the third quarter of each year, we perform an annual goodwill impairment test. The carrying amount of our goodwill is considered not recoverable if the carrying amount of our net assets exceeds our fair value. An impairment loss is recorded as the excess of the carrying amount of the goodwill over its fair value. For our indefinite-lived intangible assets, an impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds its fair value. An impairment loss is measured as the excess of the carrying amount of the intangible asset over its fair value. No impairment losses were recorded for our indefinite-lived intangible assets during the years ended December 31, 2023, 2022, and 2021. See Note 10, Goodwill and Intangible Assets, for more information. 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. 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 its fair value. 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 over its fair value. We assess the likelihood of a disallowance of part of the cost of recently completed plant by considering factors such as applicable regulatory environment changes, our own recent rate orders, as well as recent rate orders of other regulated entities in similar jurisdictions. When it becomes probable that part of the cost of recently completed plant will be disallowed for rate-making purposes, we assess whether a reasonable estimate of the amount of the disallowance can be made. The estimated amount of the probable disallowance will then be deducted from the reported cost of the plant and recognized as an impairment loss. 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. See Note 6, Regulatory Assets and Liabilities, and Note 7, Property, Plant, and Equipment, for more information. We periodically assess the recoverability of equity method investments when factors indicate the carrying amount of such assets may be impaired. Equity method investments are assessed for impairment by comparing the fair values of these investments to their carrying amounts if a fair value assessment was completed or by reviewing for the presence of impairment indicators. If an impairment exists, and it is determined to be other-than-temporary, an impairment loss is recognized equal to the amount by which the carrying amount exceeds the investment's fair value. (k) Asset Retirement Obligations (l) Stock-Based Compensation —Our employees participate in the WEC Energy Group stock-based compensation plans. In accordance with the 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. In addition to those shares of WEC Energy Group common stock that were subject to awards outstanding as of May 6, 2021, when the plan was last approved by shareholders, 9.0 million shares of WEC Energy Group common stock were reserved for issuance under the plan. 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 connection with certain termination of employment events following 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: 2023 2022 2021 Stock options granted 10,655 16,079 18,021 Estimated weighted-average fair value per stock option $ 19.58 $ 14.71 $ 13.20 Assumptions used to value the options: Risk-free interest rate 3.8% – 4.8% 0.2% – 1.6% 0.1% – 0.9% Dividend yield 3.2 % 3.2 % 2.9 % Expected volatility 22.0 % 21.0 % 21.0 % Expected life (years) 8.3 8.7 8.7 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. All grants of performance units are settled in cash and are accounted for as liability awards accordingly. Performance units accrue forfeitable dividend equivalents in the form of additional performance units. 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. 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. Under the terms of awards granted prior to 2023, participants may earn between 0% and 175% of the performance unit award based on WEC Energy Group's total shareholder return. Pursuant to the plan terms governing these awards, these percentages can be adjusted upwards or downwards by up to 10% based on WEC Energy Group's performance against additional performance measures, if any, adopted by the Compensation Committee. The WEC Energy Group Performance Unit Plan was amended and restated, effective January 1, 2023. In accordance with the amended plan, the Compensation Committee selected multiple performance measures that will be weighted to determine the ultimate payout for the awards granted in 2023 and 2024. The ultimate number of units awarded will be based on WEC Energy Group's total shareholder return compared to the total shareholder return of a peer group of companies over three years (55%), and WEC Energy Group's performance against the weighted average authorized ROE of all of its utility subsidiaries (45%). In addition, the Compensation Committee selected the level of WEC Energy Group's stock price to earnings ratio compared to its peer companies as a performance measure that can increase the payout by up to 25%. In no event can the performance unit payout be greater than 200% of the target award. See Note 11, Common Equity, for more information on WEC Energy Group's stock-based compensation plans. (m) Leases —We recognize a right of use asset and lease liability for operating and finance leases with a term of greater than one year. As a policy election, we account for each lease component separately from the nonlease components of a contract. 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 renewable generating facilities. 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. (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. PTCs are recognized in the period in which such credits are generated. The amount of the credit is based upon power production from our qualifying generation facilities. 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 the benefit for loss method, where attributes are realized when WEC Energy Group is able to realize them. We recognize interest and penalties accrued related to unrecognized tax benefits in income tax expense in our income statements. The IRA contains a tax credit transferability provision that allows us to sell PTCs produced after December 31, 2022, to third parties. In September 2023, under this transferability provision, WEC Energy Group entered into an agreement to sell substantially all of our 2023 PTCs to a third party. We elect to account for tax credits transferred under the scope of ASC 740. We include the discount from the sale of tax credits as a component of income tax expense. We will also include any expected proceeds from the sale of tax credits in the evaluation of the realizability of deferred tax assets related to PTCs. The sale of tax credits is presented in the operating activities section of the statements of cash flows consistent with the presentation of cash taxes paid. In April 2023, the IRS issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting that taxpayers may use to determine whether expenses to repair, maintain, replace, or improve natural gas transmission and distribution property must be capitalized for tax purposes. We are currently evaluating the impact this guidance may have on our financial statements and related disclosures. See Note 16, Income Taxes, for more information. (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 r |
ACQUISITIONS
ACQUISITIONS | 12 Months Ended |
Dec. 31, 2023 | |
Asset Acquisition [Abstract] | |
Asset Acquisition | ACQUISITIONS In accordance with Topic 805: Clarifying the Definition of a Business (ASU 2017-01), transactions are evaluated and are accounted for as acquisitions of assets or businesses, and transaction costs are capitalized in asset acquisitions. It was determined that all of the below acquisitions met the criteria of asset acquisitions. Acquisitions of Electric Generation Facilities in Wisconsin In April 2023, we, along with an unaffiliated utility, completed the acquisition of Red Barn, a commercially operational utility-scale wind-powered electric generating facility. The project is located in Grant County, Wisconsin and we own 82 MWs of this project. Our share of the cost of this project was $143.8 million. Red Barn qualifies for PTCs. In January 2023, we, along with WE, completed the acquisition of Whitewater, a commercially operational 236.5 MW dual fueled (natural gas and low sulfur fuel oil) combined cycle electrical generation facility in Whitewater, Wisconsin. Our share of the cost of this facility was $38.0 million for 50% of the capacity. |
RELATED PARTIES
RELATED PARTIES | 12 Months Ended |
Dec. 31, 2023 | |
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 ultimate 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). As required by FERC regulations for centralized service companies, WBS renders services at cost. Services provided by any regulated subsidiary of WEC Energy Group to another regulated subsidiary or WBS are provided at cost, and any services provided by a regulated subsidiary to a nonregulated subsidiary of WEC Energy Group are provided at the greater of cost or fair market value. We provide services to WRPC under an operating agreement approved by the PSCW. We are also under a service agreement with WRPC where we are billed for services provided by WRPC. Services are billed to and from WRPC under these agreements at a fully allocated cost. 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) December 31, 2023 December 31, 2022 Accounts receivable Services provided to ATC $ 0.7 $ 0.5 Amounts due from ATC for transmission infrastructure upgrades (1) 6.6 3.3 Accounts payable Services received from ATC 12.0 9.1 (1) The transmission infrastructure upgrades were primarily related to the construction of our renewable energy projects. The following table shows activity associated with our related party transactions for the years ended December 31: (in millions) 2023 2022 2021 Transactions with WE Natural gas related sales to WE (1) $ 1.3 $ 3.3 $ 2.9 Charges to WE for services and other items (2) 11.3 10.7 9.4 Charges from WE for services and other items (2) 16.2 13.3 11.8 Transactions with WG Natural gas related sales to WG (1) 1.4 0.4 0.1 Transactions with UMERC Natural gas related sales to UMERC (1) 3.1 4.0 2.6 Charges to UMERC for services and other items (2) 2.2 3.7 3.1 Transactions with Bluewater Charges from Bluewater for storage service fees (3) 12.1 10.7 10.3 Charges from Bluewater for other operating fees (3) 2.7 2.3 1.0 Natural gas related sales to Bluewater (1) 1.9 1.9 1.9 Transactions with WBS Charges to WBS for services and other items (2) 13.1 16.1 15.4 Charges from WBS for services and other items (2) 55.6 62.4 67.4 (5) Transactions with ATC Charges to ATC for services and construction 9.3 9.6 8.0 Charges from ATC for network transmission services 114.2 109.5 107.0 Net refund from ATC related to FERC ROE orders — — 2.3 Transactions with WRPC Rental payments to WRPC (4) 2.5 1.9 1.9 Charges to WRPC for operations 0.4 0.4 0.6 Charges from WRPC for services 2.8 2.6 2.4 (1) Includes amounts related to the 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 AIA. (3) We have a long-term service agreement with a wholly owned subsidiary of Bluewater that was previously approved by the PSCW. Bluewater owns natural gas storage facilities in Michigan and provides a portion of our current storage needs. (4) We have an agreement with WRPC whereby we receive 50% of the energy generated from its hydroelectric power generation facilities. (5) Includes $5.4 million for the transfer of certain software assets from WBS. |
OPERATING REVENUES
OPERATING REVENUES | 12 Months Ended |
Dec. 31, 2023 | |
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. 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 has different expectations of service, energy and demand requirements, and can be impacted differently by regulatory activities within their jurisdictions. Year Ended December 31 (in millions) 2023 2022 2021 Wisconsin Public Service Corporation Electric utility $ 1,309.9 $ 1,316.5 $ 1,176.7 Natural gas utility 368.0 465.5 338.8 Total revenues from contracts with customers 1,677.9 1,782.0 1,515.5 Other operating revenues 3.5 3.2 5.4 Total operating revenues $ 1,681.4 $ 1,785.2 $ 1,520.9 Revenues from Contracts with Customers Electric Utility Operating Revenues The following table disaggregates electric utility operating revenues into customer class: Year Ended December 31 (in millions) 2023 2022 2021 Residential $ 479.9 $ 460.4 $ 423.5 Small commercial and industrial 445.9 413.8 376.2 Large commercial and industrial 273.1 293.3 256.6 Other 8.7 8.8 8.4 Total retail revenues 1,207.6 1,176.3 1,064.7 Wholesale 79.2 95.4 86.7 Resale 17.8 27.3 11.4 Other utility revenues 5.3 17.5 13.9 Total electric utility operating revenues $ 1,309.9 $ 1,316.5 $ 1,176.7 Natural Gas Utility Operating Revenues The following table disaggregates natural gas utility operating revenues into customer class: Year Ended December 31 (in millions) 2023 2022 2021 Residential $ 219.8 $ 271.8 $ 202.0 Commercial and industrial 124.2 175.1 122.0 Total retail revenues 344.0 446.9 324.0 Transportation 22.3 20.1 19.4 Other utility revenues (1) 1.7 (1.5) (4.6) Total natural gas utility operating revenues $ 368.0 $ 465.5 $ 338.8 (1) Includes the revenues subject to our purchased gas recovery mechanism, which fluctuate based on actual natural gas costs incurred, compared with the recovery of natural gas costs that were anticipated in rates. Other Operating Revenues Other operating revenues consist of the following: Year Ended December 31 (in millions) 2023 2022 2021 Late payment charges $ 3.9 $ 3.8 $ 3.9 Rental revenues 0.3 0.3 0.1 Alternative revenues (1) (0.7) (0.9) 1.4 Total other operating revenues $ 3.5 $ 3.2 $ 5.4 (1) 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 wholesale customers subject to true-ups. |
CREDIT LOSSES
CREDIT LOSSES | 12 Months Ended |
Dec. 31, 2023 | |
Credit Loss [Abstract] | |
CREDIT LOSSES | CREDIT LOSSES The table below shows our gross third-party receivable balances and related allowance for credit losses. (in millions) December 31, 2023 December 31, 2022 Accounts receivable and unbilled revenues $ 230.1 $ 279.5 Allowance for credit losses 10.9 11.7 Accounts receivable and unbilled revenues, net (1) $ 219.2 $ 267.8 Total accounts receivable, net – past due greater than 90 days (1) $ 8.3 $ 8.4 Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1) 93.4 % 95.5 % (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, 2023, $124.0 million, or 56.6%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses. A rollforward of the allowance for credit losses is included below: Year Ended December 31 (in millions) 2023 2022 2021 Balance at January 1 $ 11.7 $ 11.1 $ 18.3 Provision for credit losses 5.6 8.4 6.2 Provision for credit losses deferred for future recovery or refund 3.3 0.1 (7.0) Write-offs charged against the allowance (14.9) (12.8) (10.0) Recoveries of amounts previously written off 5.2 4.9 3.6 Balance at December 31 $ 10.9 $ 11.7 $ 11.1 The allowance for credit losses decreased during the year ended December 31, 2023, primarily related to lower customer energy costs (driven by the warmer weather during the fourth quarter of 2023 when compared to the same quarter in 2022 and lower natural gas prices), which contributed to a reduction in past due accounts receivable balances and a related decrease in the allowance for credit losses. Customer write-offs also contributed to the decrease in the allowance for credit losses. After a customer is disconnected for a period of time without payment on their account, we will write off that customer balance. The allowance for credit losses increased during the year ended December 31, 2022. We believe that the high energy costs that customers were seeing, which were driven by high natural gas prices, contributed to higher past due accounts receivable balances and a related increase in the allowance for credit losses. The increase was substantially offset by customer write-offs related to collection practices returning to pre-pandemic levels, including the restoration of our ability to disconnect customers. |
REGULATORY ASSETS AND LIABILITI
REGULATORY ASSETS AND LIABILITIES | 12 Months Ended |
Dec. 31, 2023 | |
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) 2023 2022 See Note Regulatory assets (1) (2) Environmental remediation costs (3) $ 121.5 $ 118.5 21 Pension and OPEB costs (4) 62.0 48.6 19, 23 Income tax related items 57.2 61.5 16 Plant retirement related items 38.4 43.1 AROs 18.8 15.6 1(k), 9 Derivatives 12.5 22.5 1(p) Bluewater (5) 11.9 6.8 ReACT™ 10.4 13.0 23 Uncollectible expense 8.9 5.6 5 Energy efficiency programs (6) 5.5 13.4 Other, net 13.5 16.9 Total regulatory assets $ 360.6 $ 365.5 (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 $7.7 million and $9.6 million at December 31, 2023 and 2022, respectively. (2) As of December 31, 2023, we had $36.2 million of regulatory assets not earning a return. 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) As of December 31, 2023, we had made cash expenditures of $36.2 million related to these environmental remediation costs. The remaining $85.3 million represents our estimated future cash expenditures. (4) 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. (5) Primarily relates to costs associated with our long-term service agreement with Bluewater for natural gas storage services. The PSCW has approved escrow accounting for these costs. As a result, we defer as a regulatory asset or liability the difference between actual storage costs and those included in rates until recovery or refund is authorized in a future rate proceeding. (6) Represents amounts recoverable from customers related to programs designed to meet energy efficiency standards. The following regulatory liabilities were reflected on our balance sheets as of December 31: (in millions) 2023 2022 See Note Regulatory liabilities Income tax related items $ 331.4 $ 343.7 16 Removal costs (1) 191.2 186.5 Pension and OPEB benefits (2) 85.3 90.1 19, 23 Energy costs refundable through rate adjustments 36.3 9.9 1(d) Derivatives 4.1 7.9 1(p) Other, net 32.2 22.1 Total regulatory liabilities $ 680.5 $ 660.2 Balance sheet presentation Other current liabilities $ 8.5 $ 9.9 Regulatory liabilities 672.0 650.3 Total regulatory liabilities $ 680.5 $ 660.2 (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 9, 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. Pulliam Power Plant In connection with a MISO ruling, we retired Pulliam Units 7 and 8 on October 21, 2018. The net book value of the Pulliam units was $33.0 million at December 31, 2023, representing book value less cost of removal and accumulated depreciation. This amount was classified as a regulatory asset on our balance sheet at December 31, 2023 as a result of the retirement of the plant. Effective with our rate order issued by the PSCW in December 2019, we received approval to collect a return of and on the entire net book value of the Pulliam units, and as a result, will continue to amortize this regulatory asset on a straight-line basis through 2031, using the composite depreciation rates approved by the PSCW before these generating units were retired. The amortization is included in depreciation and amortization in the income statement. We also have FERC approval to continue to collect the net book value of the Pulliam power plant using the approved composite depreciation rates, in addition to a return on the remaining net book value. Edgewater Unit 4 |
PROPERTY, PLANT, AND EQUIPMENT
PROPERTY, PLANT, AND EQUIPMENT | 12 Months Ended |
Dec. 31, 2023 | |
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) 2023 2022 Electric – generation $ 3,108.8 $ 2,736.5 Electric – distribution 2,338.5 2,184.9 Natural gas – distribution, storage, and transmission 1,266.3 1,184.5 Property, plant, and equipment to be retired, net 259.8 273.1 Other 513.3 493.1 Less: Accumulated depreciation 1,857.8 1,662.6 Net 5,628.9 5,209.5 CWIP 172.5 167.2 Total property, plant, and equipment $ 5,801.4 $ 5,376.7 Severance Liability for Plant Retirements We have severance liabilities related to past and future plant retirements recorded in other current and other long-term liabilities on our balance sheets. Activity related to these severance liabilities for the years ended December 31 was as follows: (in millions) 2023 2022 2021 Severance liability at January 1 $ 2.7 $ 1.6 $ — Severance expense — 1.1 1.6 Total severance liability at December 31 $ 2.7 $ 2.7 $ 1.6 Plant to be Retired Columbia Units 1 and 2 As a result of a MISO ruling received in June 2021, retirement of the jointly-owned Columbia Units 1 and 2 became probable. Columbia Units 1 and 2 are expected to be retired by June 2026. The total net book value of our ownership share of Columbia Units 1 and 2 was $259.8 million at December 31, 2023, which does not include deferred taxes. This amount was classified as plant to be retired within property, plant, and equipment on our balance sheet. These units are included in rate base, and we continue to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW. |
JOINTLY OWNED UTILITY FACILITIE
JOINTLY OWNED UTILITY FACILITIES | 12 Months Ended |
Dec. 31, 2023 | |
Jointly Owned Utility Plant, Net Ownership Amount [Abstract] | |
JOINTLY OWNED UTILITY FACILITIES | JOINTLY OWNED UTILITY FACILITIES We hold joint ownership interests in certain electric generating facilities. We are entitled to our share of generating capability and output of each facility equal to our respective ownership interest. We have supplied our own financing for all jointly owned projects. We pay our ownership share of additional construction costs, fuel inventory purchases, and operating expenses, unless specific agreements have been executed to limit our maximum exposure to additional costs. We record our proportionate share of significant jointly owned electric generating facilities as property, plant, and equipment on the balance sheets. In addition, our proportionate share of direct expenses for the joint operation of these plants is recorded within operating expenses in the income statements. Information related to jointly owned utility facilities at December 31, 2023 was as follows: Jointly-Owned Utility Facilities Ownership Share of Capacity (MW) In-Service /Acquisition Date Operating Owner Property, Plant, and Equipment Accumulated Depreciation CWIP (in millions, except for percentages and MW) Weston Unit 4 (1) 70.0 % 384.8 2008 WPS $ 613.3 $ (227.3) $ 0.5 Columbia Energy Center Units 1 and 2 (1 ) (5) 27.5 % 312.3 1975 & 1978 WPL 433.1 (173.8) 3.5 Forward Wind (2) 44.6 % 61.5 2008 WPS 119.3 (56.8) — Two Creeks (3) 66.7 % 100.0 2020 WPS 136.9 (14.1) — Badger Hollow I (3) 66.7 % 100.0 2021 WPS 146.2 (9.7) 0.1 Red Barn (2) 90.0 % 82.4 2023 WPS 150.0 (3.2) — Weston RICE units (1) 50.0 % 65.0 2023 WPS 91.7 (1.2) — Whitewater (1) (4) 50.0 % 121.4 2023 WE 125.7 (93.6) 0.4 (1) Capacity is based on rated capacity, which is the net power output under average operating conditions with equipment in an average state of repair as of a given month in a given year. Values are primarily based on the net dependable expected capacity ratings for summer 2024 established by tests and may change slightly from year to year. The summer period is the most relevant for capacity planning purposes. This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand. (2) Capacity for wind generating facilities is based on nameplate capacity, which is the amount of energy a turbine should produce at optimal wind speeds. (3) Capacity for solar generating facilities is based on nameplate capacity, which is the maximum output that a generator should produce at continuous full power. (4) Effective January 1, 2023, we, along with WE, completed the acquisition of Whitewater. See Note 2, Acquisitions, for more information. (5) These units are expected to be retired by June 2026. See Note 7, Property, Plant, and Equipment, for more information. We, along with WE and an unaffiliated utility, received PSCW approval to construct Koshkonong, a utility-scale solar-powered electric generating facility. The project will be located in Dane County, Wisconsin and once fully constructed, we will own 15%, or 45 MWs of solar generation of this project. Commercial operation of the solar facility is targeted for 2026. Our CWIP balance for Koshkonong was not significant as of December 31, 2023. We, along with WE and an unaffiliated utility, received PSCW approval to construct Paris, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Kenosha County, Wisconsin and once fully constructed, we will own 15%, or 30 MWs of solar generation and 17 MWs of battery storage of this project. Commercial operation of the solar facility is targeted for 2024 and construction of the battery storage is expected to be completed in 2025. Our CWIP balance for Paris was $55.2 million as of December 31, 2023. We, along with WE and an unaffiliated utility, received PSCW approval to construct Darien, a utility-scale solar-powered electric generating facility. The project will be located in Rock and Walworth counties, Wisconsin and once fully constructed, we will own 15%, or 37 MWs of solar generation of this project. Commercial operation of the solar facility is targeted for 2024. Our CWIP balance for Darien was $36.6 million as of December 31, 2023. |
ASSET RETIREMENT OBLIGATIONS
ASSET RETIREMENT OBLIGATIONS | 12 Months Ended |
Dec. 31, 2023 | |
Asset Retirement Obligation Disclosure [Abstract] | |
ASSET RETIREMENT OBLIGATIONS | ASSET RETIREMENT OBLIGATIONS We have recorded AROs primarily for asbestos abatement at certain generation facilities, office buildings, and service centers; the dismantling of solar and wind generation projects; the disposal of polychlorinated biphenyls-contaminated transformers; and the closure of CCR landfills at certain generation facilities. We establish regulatory assets and liabilities to record the differences between ongoing expense recognition under the ARO accounting rules and the ratemaking 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) 2023 2022 2021 Balance as of January 1 $ 55.1 $ 55.8 $ 45.5 Accretion 2.1 2.0 1.8 Additions 2.2 (1) 0.7 10.7 (4) Revisions to estimated cash flows 1.6 1.4 (2.1) (5) Liabilities settled (4.3) (2) (4.8) (3) (0.1) Balance as of December 31 $ 56.7 $ 55.1 $ 55.8 (1) AROs increased primarily as a result of AROs being recorded for the legal requirement to dismantle, at retirement, the Red Barn wind-powered generation project. See Note 2, Acquisitions, for more information. (2) AROs decreased primarily due to the partial settlement of AROs for landfill and ash pond closure activities. (3) AROs decreased primarily due to the partial settlement of AROs for landfill and ash pond closure activities. (4) AROs increased primarily due to the legal requirement to dismantle, at retirement, the Badger Hollow I solar generation project. (5) AROs decreased primarily due to revisions made to removal estimates for wind generation projects, offset by revisions made to the removal estimates for fly ash landfills and ash ponds. |
GOODWILL AND INTANGIBLES
GOODWILL AND INTANGIBLES | 12 Months Ended |
Dec. 31, 2023 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
GOODWILL AND INTANGIBLE ASSETS | GOODWILL AND INTANGIBLE ASSETS Goodwill Goodwill represents the excess of the cost of an acquisition over the fair value of the identifiable net assets acquired. We had no changes to the carrying amount of goodwill during the years ended December 31, 2023 and 2022. We had no accumulated impairment losses related to our goodwill as of December 31, 2023. During the third quarter of 2023, we completed our annual goodwill impairment test for goodwill we carried as of July 1, 2023. No impairment resulted from this test. Intangible Assets |
COMMON EQUITY
COMMON EQUITY | 12 Months Ended |
Dec. 31, 2023 | |
Stockholders' Equity Note [Abstract] | |
COMMON EQUITY | COMMON EQUITY Stock-Based Compensation 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) 2023 2022 2021 Stock options $ 1.0 $ 1.1 $ 1.1 Restricted stock 1.1 1.2 1.0 Performance units (0.4) (1) 3.9 0.4 Stock-based compensation expense $ 1.7 $ 6.2 $ 2.5 Related tax benefit $ 0.5 $ 1.7 $ 0.7 1) The reduction in expense was due to a decrease in the fair value of the outstanding performance units. Stock-based compensation costs capitalized during 2023, 2022, and 2021 were not significant. Stock Options The following is a summary of our employees' WEC Energy Group stock option activity during 2023: 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, 2023 62,168 $ 87.00 Granted 10,655 93.69 Transferred 2,454 75.82 Outstanding as of December 31, 2023 75,277 87.58 6.8 $ 0.3 Exercisable as of December 31, 2023 31,857 79.59 5.3 $ 0.3 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, 2023. This is calculated as the difference between WEC Energy Group's closing stock price on December 31, 2023, and the option exercise price, multiplied by the number of in-the-money stock options. No stock options were exercised by our employees during the year ended December 31, 2023. The intrinsic value of options exercised during the years ended December 31, 2022 and 2021 was $0.9 million and $0.3 million, respectively. Cash received by WEC Energy Group from exercises of its options by our employees was $2.4 million and $0.6 million during the years ended December 31, 2022 and 2021, respectively. The actual tax benefit from option exercises for the same years was approximately $0.2 million and $0.1 million, respectively. As of December 31, 2023, we expected to recognize approximately $0.3 million of unrecognized compensation cost related to unvested and outstanding WEC Energy Group stock options over the next 1.6 years on a weighted-average basis. During the first quarter of 2024, the Compensation Committee awarded 11,878 non-qualified WEC Energy Group stock options with an exercise price of $85.05 and a weighted-average grant date fair value of $16.20 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 2023: Restricted Shares Number of Shares Weighted-Average Grant Date Fair Value Outstanding and unvested as of January 1, 2023 2,557 $ 93.84 Granted 1,587 93.69 Released (1,233) 93.07 Transferred 74 93.68 Outstanding and unvested as of December 31, 2023 2,985 94.07 The intrinsic value of WEC Energy Group restricted stock held by our employees that was released was $0.1 million for each of the years ended December 31, 2023, 2022, and 2021. The actual tax benefit from released restricted shares for the same years was not significant. As of December 31, 2023, we expected to recognize approximately $0.5 million of unrecognized compensation cost related to unvested and outstanding WEC Energy Group restricted stock over the next 1.7 years on a weighted-average basis. During the first quarter of 2024, the Compensation Committee awarded 2,783 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 $85.05 per share. Performance Units During 2023, 2022, and 2021, the Compensation Committee awarded 6,905; 6,608; and 5,437 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 $0.4 million, $0.7 million, and $1.2 million were settled during 2023, 2022, and 2021, respectively. The actual tax benefit from the distribution of performance units for the same years was $0.1 million, $0.2 million, and $0.2 million, respectively. At December 31, 2023, our employees held 19,718 WEC Energy Group performance units, including dividend equivalents. A liability of $0.5 million was recorded on our balance sheet at December 31, 2023 related to these outstanding units. As of December 31, 2023, we expected to recognize approximately $2.3 million of unrecognized compensation cost related to unvested and outstanding WEC Energy Group performance units over the next 1.9 years on a weighted-average basis. During the first quarter of 2024, performance units held by our employees with an intrinsic value of $0.1 million were settled. The actual tax benefit from the distribution of these awards was not significant. In January 2024, the Compensation Committee also awarded 9,061 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 the sole holder of our common stock, Integrys, 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, Integrys, or their 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 53.0%. 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. See Note 13, 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, 2023, our restricted retained earnings totaled approximately $647 million. 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, 2023 | |
Class of Stock Disclosures [Abstract] | |
PREFERRED STOCK | PREFERRED STOCK We have 1,000,000 shares of preferred stock with a $100 par value authorized for issuance, of which none were issued and outstanding at December 31, 2023 and 2022. |
SHORT-TERM DEBT AND LINES OF CR
SHORT-TERM DEBT AND LINES OF CREDIT | 12 Months Ended |
Dec. 31, 2023 | |
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) 2023 2022 Commercial paper Amount outstanding at December 31 $ 310.3 $ 194.9 Average interest rate on amounts outstanding at December 31 5.41 % 4.60 % Our average amount of commercial paper borrowings based on daily outstanding balances during 2023 was $151.4 million, with a weighted-average interest rate during the period of 5.17%. 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, 2023, 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 2023 Revolving credit facility September 2026 $ 400.0 Less: Letters of credit issued inside credit facility 1.3 Commercial paper outstanding 310.3 Available capacity under existing agreement $ 88.4 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, 2023 | |
Debt Disclosure [Abstract] | |
LONG-TERM DEBT | LONG-TERM DEBT The following table is a summary of our long-term debt outstanding (excluding finance leases) as of December 31: (in millions) Interest Rate Year Due 2023 2022 Senior Notes (unsecured) 5.35% 2025 $ 300.0 $ 300.0 6.08% 2028 50.0 50.0 5.55% 2036 125.0 125.0 3.671% 2042 300.0 300.0 4.752% 2044 450.0 450.0 3.30% 2049 300.0 300.0 2.85% 2051 450.0 450.0 Total 1,975.0 1,975.0 Unamortized debt issuance costs (14.5) (15.5) Unamortized discount, net (1.4) (1.5) Total long-term debt (1) $ 1,959.1 $ 1,958.0 (1) The amount of long-term debt on our balance sheet includes finance lease obligations of $49.0 million at December 31, 2023 and $41.9 million at December 31, 2022. 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 (excluding obligations under finance leases) as of December 31, 2023: (in millions) Payments 2024 $ — 2025 300.0 2026 — 2027 — 2028 50.0 Thereafter 1,625.0 Total $ 1,975.0 Our long-term debt obligations contain covenants related to payment of principal and interest when due and various other obligations. Failure to comply with these covenants could result in an event of default, which could result in the acceleration of outstanding debt obligations. |
LEASES
LEASES | 12 Months Ended |
Dec. 31, 2023 | |
Leases [Abstract] | |
LEASES | LEASES Obligations Under Finance Leases In accordance with ASC Subtopic 980-842, Regulated Operations – Leases (Subtopic 980-842), the timing of expense recognition associated with our finance leases is modified to conform to the rate treatment. Amortization of the right-of-use asset is modified so that the total of the imputed interest and amortization costs equals the lease expense that is allowed for rate-making purposes. The difference between this lease expense and the sum of imputed interest and unadjusted amortization costs calculated under Topic 842 is deferred as a regulatory asset on our balance sheets in accordance with Subtopic 980-842. Land Leases – Utility Solar Generation We have entered into various land leases related to our investments in utility solar generation. Each lease has an initial term and one or more optional extensions. We expect the optional extensions to be exercised, and, as a result, all of the land leases are being amortized over an extended term of approximately 50 years. Once a solar project achieves commercial operation, the lease liability is remeasured to reflect the final total acres being leased. Our payments related to these leases are being recovered through rates. Amounts Recognized in the Financial Statements and Other Information Lease expense and cash payments related to our finance leases were not significant in 2023, 2022, or 2021. Other information related to these leases for the years ended December 31 are as follows: Other information (dollar amounts in millions) 2023 2022 2021 Non-cash activities: Right of use assets obtained in exchange for finance lease liabilities $ 6.6 $ 10.2 $ 2.6 Reduction of right of use asset and finance lease liability due to a remeasurement — — (2.9) Weighted average remaining lease term 48.4 years 49.0 years 49.6 years Weighted average discount rate (1) 4.3 % 3.9 % 3.3 % (1) Because these 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. The following table summarizes our finance lease right of use assets and obligations at December 31: (in millions) 2023 2022 Balance Sheet Location Right of use assets Finance lease right of use assets, net (1) $ 43.8 $ 38.0 Property, plant, and equipment, net Lease obligations Long-term finance lease liabilities $ 49.0 $ 41.9 Long-term debt (1) Amounts are net of accumulated amortization of $3.1 million and $2.2 million at December 31, 2023 and 2022, respectively. Future minimum lease payments under our finance leases and the present value of our net minimum lease payments as of December 31, 2023, were as follows: (in millions) Total Finance Leases 2024 $ 1.4 2025 1.6 2026 1.6 2027 1.7 2028 1.7 Thereafter 126.6 Total minimum lease payments 134.6 Less: Interest (85.6) Present value of minimum lease payments 49.0 Less: Short-term lease liabilities — Long-term lease liabilities $ 49.0 As of February 22, 2024, we have not entered into any material leases that have not yet commenced. |
INCOME TAXES
INCOME TAXES | 12 Months Ended |
Dec. 31, 2023 | |
Income Tax Disclosure [Abstract] | |
INCOME TAXES | INCOME TAXES Income Tax Expense The following table is a summary of income tax expense for each of the years ended December 31: (in millions) 2023 2022 2021 Current tax expense (benefit) $ 17.8 $ 8.7 $ (18.3) Deferred income taxes, net 48.7 66.3 51.1 ITCs (3.8) (2.8) (1.6) Total income tax expense $ 62.7 $ 72.2 $ 31.2 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: 2023 2022 2021 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Amount Effective Tax Rate Statutory federal income tax $ 67.8 21.0 % $ 64.5 21.0 % $ 55.1 21.0 % State income taxes net of federal tax benefit 20.2 6.3 % 19.5 6.3 % 16.3 6.2 % PTCs, net (14.4) (4.5) % (0.6) (0.2) % — — % Federal excess deferred tax amortization (1) (5.7) (1.8) % (5.2) (1.7) % (5.2) (2.0) % Federal excess deferred tax amortization – Wisconsin unprotected (2) (3.8) (1.2) % (3.8) (1.2) % (33.0) (12.6) % ITCs (3.8) (1.2) % (2.8) (0.9) % (1.6) (0.6) % Other, net 2.4 0.8 % 0.6 0.2 % (0.4) (0.1) % Total income tax expense $ 62.7 19.4 % $ 72.2 23.5 % $ 31.2 11.9 % (1) 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. (2) In accordance with the rate order received from the PSCW in December 2019, we amortized 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. See Note 23, 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) 2023 2022 Deferred tax assets Tax gross up – regulatory items $ 94.8 $ 99.9 Future tax benefits 8.8 3.5 Other 21.3 23.3 Total deferred tax assets $ 124.9 $ 126.7 Deferred tax liabilities Property-related 935.7 878.3 Employee benefits and compensation 66.7 62.2 Other 46.9 46.9 Total deferred tax liabilities 1,049.3 987.4 Deferred tax liability, net $ 924.4 $ 860.7 Consistent with ratemaking 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 tax benefit carryforwards as of December 31, 2023 and 2022 are summarized in the tables below: 2023 (in millions) Gross Value Deferred Tax Effect Earliest Year of Expiration Future tax benefits as of December 31, 2023 Federal tax credit $ — $ 8.8 2042 Balance as of December 31, 2023 $ — $ 8.8 2022 (in millions) Gross Value Deferred Tax Effect Earliest Year of Expiration Future tax benefits as of December 31, 2022 Federal tax credit $ — $ 3.5 2041 Balance as of December 31, 2022 $ — $ 3.5 Unrecognized Tax Benefits We had no unrecognized tax benefits at December 31, 2023 and 2022. We do not expect any unrecognized tax benefits to affect our effective tax rate in periods after December 31, 2023. For the years ended December 31, 2023, 2022, and 2021, we recognized no interest expense and no penalties related to unrecognized tax benefits in our income statements. At December 31, 2023 and 2022, 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. Our primary tax jurisdictions include federal and the state of Wisconsin. With a few exceptions, we are no longer subject to federal income tax examinations by the IRS for years prior to 2020. As of December 31, 2023, we were subject to examination by the Wisconsin taxing authority for tax years 2019 through 2023. |
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS | 12 Months Ended |
Dec. 31, 2023 | |
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, 2023 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 0.6 $ 1.3 $ — $ 1.9 FTRs — — 2.0 2.0 Coal contracts — 0.3 — 0.3 Total derivative assets $ 0.6 $ 1.6 $ 2.0 $ 4.2 Derivative liabilities Natural gas contracts $ 7.4 $ 0.5 $ — $ 7.9 Coal contracts — 1.0 — 1.0 Total derivative liabilities $ 7.4 $ 1.5 $ — $ 8.9 December 31, 2022 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 1.2 $ 0.5 $ — $ 1.7 FTRs — — 4.1 4.1 Coal contracts — 1.8 — 1.8 Total derivative assets $ 1.2 $ 2.3 $ 4.1 $ 7.6 Derivative liabilities Natural gas contracts $ 14.5 $ 2.4 $ — $ 16.9 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) 2023 2022 2021 Balance at the beginning of the period $ 4.1 $ 1.4 $ 1.2 Purchases 6.3 11.7 3.1 Settlements (8.4) (9.0) (2.9) Balance at the end of the period $ 2.0 $ 4.1 $ 1.4 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, 2023 December 31, 2022 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt (1) $ 1,959.1 $ 1,662.8 $ 1,958.0 $ 1,607.2 (1) The carrying amount of long-term debt excludes finance lease obligations of $49.0 million and $41.9 million at December 31, 2023 and 2022, respectively. The fair value of our long-term debt is categorized within Level 2 of the fair value hierarchy. |
DERIVATIVE INSTRUMENTS
DERIVATIVE INSTRUMENTS | 12 Months Ended |
Dec. 31, 2023 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
DERIVATIVE INSTRUMENTS | DERIVATIVE INSTRUMENTS Derivative assets and liabilities are included in the other current and other long-term line items on our balance sheets. The following table shows our derivative assets and derivative liabilities. None of the derivatives shown below were designated as hedging instruments. December 31, 2023 December 31, 2022 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Current Natural gas contracts $ 1.9 $ 7.4 $ 1.7 $ 16.3 FTRs 2.0 — 4.1 — Coal contracts 0.3 0.7 1.4 — Total current 4.2 8.1 7.2 16.3 Long-term Natural gas contracts — 0.5 — 0.6 Coal contracts — 0.3 0.4 — Total long-term — 0.8 0.4 0.6 Total $ 4.2 $ 8.9 $ 7.6 $ 16.9 Realized gains and losses on derivatives are primarily recorded in cost of sales December 31, 2023 December 31, 2022 December 31, 2021 (in millions) Volumes Gains (Losses) Volumes Gains Volumes Gains Natural gas contracts 40.6 Dth $ (52.0) 33.4 Dth $ 43.1 37.5 Dth $ 21.8 FTRs 8.3 MWh 10.2 7.8 MWh 2.5 7.0 MWh 8.7 Total $ (41.8) $ 45.6 $ 30.5 At December 31, 2023 and 2022, we had posted cash collateral of $15.9 million and $26.6 million, respectively. The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets: December 31, 2023 December 31, 2022 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 4.2 $ 8.9 $ 7.6 $ 16.9 Gross amount not offset on the balance sheet (0.6) (7.5) (1) (1.4) (14.8) (2) Net amount $ 3.6 $ 1.4 $ 6.2 $ 2.1 (1) Includes cash collateral posted of $6.9 million. (2) |
EMPLOYEE BENEFITS
EMPLOYEE BENEFITS | 12 Months Ended |
Dec. 31, 2023 | |
Retirement Benefits [Abstract] | |
EMPLOYEE BENEFITS | EMPLOYEE BENEFITS Pension and Other Postretirement Employee Benefits We have our own noncontributory, qualified pension plan. We serve as plan sponsor and administrator for certain OPEB plans. The benefits 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. WEC Energy Group also offers medical, dental, and life insurance benefits to our active employees and their dependents. We expense the allocated costs of these benefits as incurred. The defined benefit pension plans are closed to all new hires. In addition, the service accruals for the defined benefit pension plans were frozen for non-union employees as of January 1, 2013. These employees receive an annual company contribution to their 401(k) savings plan, which is calculated based on age, wages, and full years of vesting service as of December 31 each year. 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) 2023 2022 2023 2022 Change in benefit obligation Obligation at January 1 $ 560.7 $ 773.1 $ 112.2 $ 146.9 Service cost 4.8 9.0 2.8 4.0 Interest cost 30.1 22.7 6.1 4.4 Net transfer from affiliates — — — 0.3 Actuarial loss (gain) 25.3 (204.9) 16.7 (36.2) Participant contributions — — 0.8 0.6 Benefit payments (34.2) (39.2) (9.9) (7.8) Obligation at December 31 $ 586.7 $ 560.7 $ 128.7 $ 112.2 Change in fair value of plan assets Fair value at January 1 $ 685.1 $ 859.4 $ 255.6 $ 303.6 Actual return on plan assets 62.2 (135.7) 24.5 (41.7) Employer contributions 0.6 0.6 0.9 0.9 Participant contributions — — 0.8 0.6 Benefit payments (34.2) (39.2) (9.9) (7.8) Fair value at December 31 $ 713.7 $ 685.1 $ 271.9 $ 255.6 Funded status at December 31 $ 127.0 $ 124.4 $ 143.2 $ 143.4 In 2023, we had actuarial losses related to our pension benefit obligations of $25.3 million and actuarial gains in 2022 of $204.9 million. The primary driver for the actuarial loss was the change in discount rate. Partially offsetting the loss in 2023, was higher than expected asset returns. The discount rate for our pension benefits was 5.15%, 5.50%, and 3.00% in 2023, 2022, and 2021, respectively. In 2023, we had actuarial losses related to our OPEB benefit obligation of $16.7 million and actuarial gains in 2022 of $36.2 million. The primary driver for the actuarial loss was changes to medical trend assumptions and a lower discount rate in 2023. Partially offsetting the loss in 2023, was higher than expected asset returns. The discount rate for our OPEB benefits was 5.16%, 5.50%, and 2.98% in 2023, 2022, and 2021, 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) 2023 2022 2023 2022 Pension and OPEB assets $ 131.6 $ 129.5 $ 152.9 $ 152.6 Other long-term liabilities 4.6 5.1 9.7 9.2 Total net assets $ 127.0 $ 124.4 $ 143.2 $ 143.4 The accumulated benefit obligation for the defined benefit pension plans was $548.1 million and $525.9 million at December 31, 2023 and 2022, respectively. The following table shows information for pension plans with an accumulated benefit obligation in excess of plan assets. There were no plan assets related to these pension plans. Amounts presented are as of December 31: (in millions) 2023 2022 Accumulated benefit obligation $ 4.7 $ 5.1 The following table shows information for pension plans with a projected benefit obligation in excess of plan assets. There were no plan assets related to these pension plans. Amounts presented are as of December 31: (in millions) 2023 2022 Projected benefit obligation $ 4.7 $ 5.1 The following table shows information for OPEB plans with an accumulated benefit obligation in excess of plan assets. Amounts presented are as of December 31: (in millions) 2023 2022 Accumulated benefit obligation $ 14.5 $ 14.4 Fair value of plan assets 4.8 5.3 The following table shows the amounts that had not yet been recognized in our net periodic benefit cost as of December 31: Pension Benefits OPEB Benefits (in millions) 2023 2022 2023 2022 Net regulatory assets (liabilities) Net actuarial loss (gain) $ 53.2 $ 56.1 $ (28.1) $ (35.6) Prior service credits — — (21.0) (31.2) Total $ 53.2 $ 56.1 $ (49.1) $ (66.8) 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) 2023 2022 2021 2023 2022 2021 Service cost $ 4.8 $ 9.0 $ 10.6 $ 2.8 $ 4.0 $ 4.3 Interest cost 30.1 22.7 21.9 6.1 4.4 4.2 Expected return on plan assets (51.3) (55.2) (51.8) (16.3) (21.0) (20.4) Plan curtailment — — — — — (6.4) Amortization of prior service credit — — — (10.2) (10.2) (10.3) Amortization of net actuarial loss (gain) 17.3 17.3 26.6 1.0 (2.5) (3.7) Net periodic benefit cost (credit) $ 0.9 $ (6.2) $ 7.3 $ (16.6) $ (25.3) $ (32.3) Effective January 1, 2023, the PSCW approved escrow accounting for pension and OPEB costs. As a result, as of December 31, 2023, we recorded a $6.7 million regulatory asset for pension costs and a $6.8 million regulatory asset for OPEB costs. The above table does not reflect any adjustments for the creation of these regulatory assets. 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 2023 2022 2023 2022 Discount rate 5.15% 5.50% 5.16% 5.50% Rate of compensation increase 4.00% 4.00% N/A N/A Interest credit rate 4.50% 4.00% N/A N/A Assumed medical cost trend rate (Pre 65) N/A N/A 6.25% 6.50% 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 2031 2031 Assumed medical cost trend rate (Post 65) N/A N/A 6.25% 6.00% 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 2030 2031 The weighted-average assumptions used to determine net periodic benefit cost for the plans were as follows for the years ended December 31: Pension Benefits 2023 2022 2021 Discount rate 5.50% 3.00% 2.74% Expected return on plan assets 6.75% 7.00% 7.00% Rate of compensation increase 4.00% 4.00% 4.00% Interest credit rate 4.00% 2.25% 2.25% OPEB Benefits 2023 2022 2021 Discount rate 5.50% 2.98% 2.95% Expected return on plan assets 6.50% 7.00% 7.00% Assumed medical cost trend rate (Pre 65) 6.50% 5.70% 5.85% Ultimate trend rate (Pre 65) 5.00% 5.00% 5.00% Year ultimate trend rate is reached (Pre 65) 2031 2028 2028 Assumed medical cost trend rate (Post 65) 6.00% 5.60% 5.70% Ultimate trend rate (Post 65) 5.00% 5.00% 5.00% Year ultimate trend rate is reached (Post 65) 2031 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 trust. For 2024, the expected return on asset assumption is 6.75% for the pension plan and 6.50% 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 25% equity investments, 55% fixed income investments, and 20% private equity and real estate investments. The OPEB trust has a target asset allocation of 45% equity investments, 45% fixed income investments, and 10% real estate investments. 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 provide the fair values of our investments by asset class: December 31, 2023 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 $ 52.0 $ — $ — $ 52.0 $ 32.6 $ — $ — $ 32.6 International equity 53.7 — — 53.7 29.8 — — 29.8 Fixed income securities: (1) United States bonds — 176.7 — 176.7 33.9 61.3 — 95.2 International bonds — 22.8 — 22.8 — 2.9 — 2.9 $ 105.7 $ 199.5 $ — $ 305.2 $ 96.3 $ 64.2 $ — $ 160.5 Investments measured at net asset value: Equity securities 112.5 65.1 Fixed income securities 66.1 17.1 Other 229.9 29.2 Total $ 713.7 $ 271.9 (1) This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries. December 31, 2022 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 $ 70.2 $ — $ — $ 70.2 $ 28.4 $ — $ — $ 28.4 International equity 61.3 — — 61.3 27.3 — — 27.3 Fixed income securities: (1) United States bonds — 130.7 — 130.7 50.2 32.6 — 82.8 International bonds — 23.7 — 23.7 — 3.0 — 3.0 $ 131.5 $ 154.4 $ — $ 285.9 $ 105.9 $ 35.6 $ — $ 141.5 Investments measured at net asset value: Equity securities 141.6 58.6 Fixed income securities 53.0 24.7 Other 204.6 30.8 Total $ 685.1 $ 255.6 (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 $0.6 million to the pension plans and $0.9 million to the OPEB plans in 2024, 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 2024 $ 37.2 $ 8.8 2025 37.1 9.0 2026 37.3 9.4 2027 37.6 9.7 2028 38.0 9.9 2029-2033 190.8 50.1 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 based on the employee's wages, age, and years of service. Total costs incurred under all of these plans were $12.8 million, $11.7 million, and $11.0 million in 2023, 2022, and 2021, respectively. |
SEGMENTS INFORMATION
SEGMENTS INFORMATION | 12 Months Ended |
Dec. 31, 2023 | |
Segment Reporting [Abstract] | |
SEGMENT INFORMATION | SEGMENT INFORMATION We use net income to measure segment profitability and to allocate resources to our businesses. At December 31, 2023, we reported two segments, which are described below. Our utility segment includes our electric and natural gas utility operations, which serve customers in northeastern and central Wisconsin. Our electric utility operations are engaged in the generation, distribution, and sale of electricity. Our natural gas utility operations are engaged in the purchase, distribution, and sale of natural gas to retail customers as well as the transportation of customer-owned natural gas. Our other segment primarily consists of equity earnings from our investment in WRPC. All of our operations and assets are located within the United States. The following tables show summarized financial information related to our reportable segments for the years ended December 31, 2023, 2022, and 2021. 2023 (in millions) Utility Other Wisconsin Public Service Corporation External revenues $ 1,681.4 $ — $ 1,681.4 Other operation and maintenance 434.3 — 434.3 Depreciation and amortization 226.9 — 226.9 Other income, net 43.8 2.1 45.9 Interest expense 89.0 — 89.0 Income tax expense 62.3 0.4 62.7 Net income 258.5 1.7 260.2 Capital expenditures and asset acquisitions 635.6 — 635.6 Total assets 7,017.5 13.6 7,031.1 2022 (in millions) Utility Other Wisconsin Public Service Corporation External revenues $ 1,785.2 $ — $ 1,785.2 Other operation and maintenance 362.5 — 362.5 Depreciation and amortization 199.8 — 199.8 Other income, net 41.0 1.3 42.3 Interest expense 70.5 — 70.5 Income tax expense 71.9 0.3 72.2 Net income 234.0 1.0 235.0 Capital expenditures 433.8 — 433.8 Total assets 6,696.0 12.8 6,708.8 2021 (in millions) Utility Other Wisconsin Public Service Corporation External revenues $ 1,520.9 $ — $ 1,520.9 Other operation and maintenance 406.4 — 406.4 Depreciation and amortization 188.6 — 188.6 Other income, net 36.8 1.4 38.2 Interest expense 64.7 — 64.7 Income tax expense 30.9 0.3 31.2 Net income 230.0 1.1 231.1 Capital expenditures 389.7 — 389.7 Total assets 6,224.3 11.4 6,235.7 |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 12 Months Ended |
Dec. 31, 2023 | |
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, 2023: Payments Due By Period (in millions) Date Contracts Extend Through Total Amounts Committed 2024 2025 2026 2027 2028 Later Years Electric utility: Purchased power 2063 $ 310.6 $ 53.9 $ 54.9 $ 55.9 $ 50.5 $ 46.8 $ 48.6 Coal supply and transportation 2026 194.1 110.4 70.4 13.3 — — — Other 2043 100.6 13.9 13.3 12.9 11.6 10.2 38.7 Natural gas utility supply and transportation 2048 376.5 57.5 31.5 21.5 21.4 20.1 224.5 Total $ 981.8 $ 235.7 $ 170.1 $ 103.6 $ 83.5 $ 77.1 $ 311.8 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, battery storage, and natural gas storage facilities; • 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, biodiversity including 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, and/or replacement with renewable generation; • the beneficial use of ash and other products from coal-fired generating units; • the remediation of former manufactured gas plant sites; • the reduction of methane emissions across our natural gas distribution system by upgrading infrastructure; and • the reporting of GHG emissions to comply with federal clean air rules. Air Quality Cross State Air Pollution Rule – Good Neighbor Plan In March 2023, the EPA issued its final Good Neighbor Plan, which became effective in August 2023 and requires significant reductions in ozone-forming emissions of NOx from power plants and industrial facilities. After review of the final rule, we believe that we are well positioned to meet the requirements. Our RICE units in Wisconsin are not currently subject to the final rule as each unit is less than 25 MWs. To the extent we use RICE engines for natural gas distribution operations, those engines not part of an LDC are subject to the emission limits and operational requirements of the rule beginning in 2026. The EPA has exempted LDCs from the final rule. Mercury and Air Toxics Standards In 2012, the EPA issued the MATS to limit emissions of mercury, acid gases, and other hazardous air pollutants. In April 2023, the EPA issued the pre-publication version of a proposed rule to strengthen and update MATS to reflect recent developments in control technologies and performance of coal and oil-fired units. The EPA proposed three revisions including a proposal to lower the PM limit from 0.03 lb/MMBtu to 0.01 lb/MMBtu. The EPA also sought comments on an even lower limit of 0.006 lb/MMBtu. Adoption of either of these lower limits could have an adverse effect on our operations. National Ambient Air Quality Standards Ozone 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 November 2022, the EPA's 2022 CASAC Ozone Review Panel issued a draft report supporting the reconsideration of the 2015 standard. The EPA staff initially issued a draft Policy Assessment in March 2023 that supported the reconsideration, however, in August 2023 it announced that it is instead restarting its ozone standard evaluation. The EPA has indicated it plans to release its Integrated Review Plan in fall 2024. This new review is anticipated to take 3 to 5 years to complete. In February 2022, revisions to the Wisconsin Administrative Code to adopt the 2015 standard were finalized. The amended regulations incorporated by reference the federal air pollution monitoring requirements related to the standard. The WDNR submitted the rule updates as a SIP revision to the EPA, which the EPA approved in February 2023. We believe that we are well positioned to meet the requirements associated with the 2015 ozone standard and do not expect to incur significant costs to comply with the associated state and federal rules. Particulate Matter In December 2020, the EPA completed its 5-year review of the 2012 annual and 24-hour standards for fine PM and determined that no revisions were necessary to the current annual standard of 12 µg/m 3 or the 24-hour standard of 35 µg/m 3 . All counties within our service territory are in attainment with the current 2012 standards. Under the Biden Administration's policy review, the EPA concluded that the scientific evidence and information from the December 2020 determination supports revising the level of the annual standard for the PM NAAQS to below the current level of 12 µg/m 3 , while retaining the 24-hour standard. In January 2023, the EPA announced its proposed decision to revise the primary (health-based) annual PM2.5 standard from its current level of 12 µg/m 3 to within the range of 9 to 10 µg/m 3 . The EPA also proposed not to change the current secondary (welfare-based) annual PM2.5 standard, primary and secondary 24-hour PM2.5 standards, and primary and secondary PM10 standards. The EPA did, however, take comments on the full range (between 8 and 11 µg/m 3 ) included in the CASAC's latest report. The EPA finalized the rule on February 7, 2024 and lowered the primary annual PM2.5 level to 9 µg/m 3 . We expect our locations to be designated as attainment with the new standard. The secondary and 24-hour standards remain unchanged. The EPA will designate areas as attainment and nonattainment with the new standard by early 2026. The WDNR will need to draft and submit a SIP for the EPA's approval. Climate Change In May 2023, the EPA proposed GHG performance standards for existing fossil-fired steam generating and gas combustion units and also proposed to repeal the Affordable Clean Energy rule, which had replaced the Clean Power Plan. For coal plants, no standards would apply under the proposed version of the rule until 2032, and after 2032 the applicable standard would depend on the unit's retirement date. For combined cycle natural gas plants above a 50% capacity factor, the proposed rule is highly dependent on the use of hydrogen as an alternative fuel, and on carbon capture technology. For simple cycle natural gas-fired combustion turbines, the proposed version of the rule does not include applicable limits as long as the capacity factor is less than 20%. The new Weston RICE project is not affected under the rule because each RICE unit is less than 25 MWs. We continue to evaluate the proposed rule to understand the impacts to our operations. A final rule is expected in the second quarter of 2024. In May 2023, the EPA proposed to revise the NSPS for GHG emissions from new, modified, and reconstructed fossil-fueled power plants. The EPA is proposing two distinct 111(b) rules – one for natural gas-fired stationary combustion turbines and the other for coal-fired units. New stationary combustion turbine units would be divided into three subcategories based on their annual capacity factor – low load, intermediate load, and base load. Our RICE units are not affected by this rule since each unit is below 25 MWs. WEC Energy Group's ESG Progress Plan is heavily focused on reducing GHG emissions. The EPA has indicated that it anticipates a final rule in the second quarter of 2024. The EPA released proposed regulations for the Mandatory Greenhouse Gas Reporting Rule, 40 CFR Part 98, in June 2022. In May 2023, the EPA released a supplementary proposal, which includes updates of the global warming potentials to determine CO 2 equivalency for threshold reporting and the addition of a new section regarding energy consumption. The proposed revisions could impact the reporting required for our electric generation facilities and LDC. In August 2023, the EPA also issued its proposed updates to amend reporting requirements for petroleum and natural gas systems, with an anticipated final rule to be issued in early 2024. We are currently evaluating the potential impact of the proposed rule, if any, on our operations. WEC Energy Group's ESG Progress Plan includes the retirement of older, fossil-fueled generation, to be replaced with zero-carbon-emitting renewables and clean natural gas-fueled generation. We have already retired approximately 400 MWs of fossil-fueled generation since the beginning of 2018. WEC Energy Group expects to retire approximately 1,800 MWs of additional fossil-fueled generation by the end of 2031, which includes the planned retirement by June 2026 of jointly-owned Columbia Units 1 and 2 and the planned retirement in 2031 of Weston Unit 3. See Note 7, Property, Plant, and Equipment, for more information related to these power plant retirements. In May 2021, WEC Energy Group announced goals to achieve reductions in carbon emissions from its electric generation fleet by 60% by the end of 2025 and by 80% by the end of 2030, both from a 2005 baseline. WEC Energy Group expects to achieve these goals by continuing to make operating refinements, retiring less efficient generating units, and executing its capital plan. Over the longer term, the target for WEC Energy Group's generation fleet is to be net carbon neutral by 2050. WEC Energy Group also continues to reduce methane emissions by improving its natural gas distribution systems, and has set a target across its natural gas distribution operations to achieve net-zero methane emissions by the end of 2030. WEC Energy Group plans to achieve its net-zero goal through an effort that includes both continuous operational improvements and equipment upgrades, as well as the use of RNG throughout its utility systems. Water Quality Clean Water Act Cooling Water Intake Structure Rule The EPA issued a final regulation under Section 316(b) of the CWA that became effective in October 2014 and requires the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the BTA for minimizing adverse environmental impacts. The rule applies to all of our existing generating facilities with cooling water intake structures. Pursuant to a WDNR rule, which became effective in June 2020, the requirements of federal Section 316(b) of the CWA were incorporated into the Wisconsin Administrative Code. The WDNR applies this rule when establishing BTA requirements for cooling water intake structures at existing facilities. These BTA requirements are incorporated into WPDES permits for our facilities. We have received interim BTA determinations for Weston Units 3 and 4. We believe that existing technology installed at the Weston facility will result in a final BTA determination during the WPDES permit reissuance expected in the first quarter of 2024. Steam Electric Effluent Limitation Guidelines The EPA's ELG rule, effective January 2016 and modified in 2020, revised the treatment technology requirements related to BATW at existing coal-fueled facilities and created new requirements for several types of power plant wastewaters. The new requirement that affects our facilities relates to discharge limits for BATW. Although our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule, certain facility modifications are necessary to meet the ELG rule requirements. We completed $8 million of BATW modifications at Weston Unit 3 in June 2023, which are now in service and did not require PSCW approval prior to construction. In March 2023, the EPA issued the proposed "supplemental ELG rule." The rule would replace the existing 2020 ELG rule and, as proposed, would establish stricter limitations on: 1) BATW; 2) flue gas desulfurization wastewater; 3) CCR leachate; and 4) legacy wastewaters. If the supplemental ELG rule is finalized as proposed, we anticipate that our coal-fueled facilities, including Weston Unit 3, will meet the BATW rule provisions. The EPA also proposed requirements for legacy wastewaters and landfill leachate. We have reviewed the proposed requirements to determine potential costs and actions required for our facilities. We submitted comments to the EPA regarding these proposed requirements. Waters of the United States In January 2023, the EPA and the Army Corps (the agencies) together released a final rule effective in March 2023 that established standards for identifying which wetland or surface drainage features qualify as WOTUS based on its pre-2015 definition. The pre-2015 approach involved applying factors established through case law and agency precedents to determine whether a wetland or surface drainage feature is subject to federal jurisdiction. In May 2023, in Sackett v. EPA, the Supreme Court issued a decision significantly narrowing federal jurisdiction over wetlands to "traditional navigable waters" and wetlands or other waters that have a "continuous surface connection" with a traditional navigable water. In August 2023, the agencies revised the final rule to conform the definition of WOTUS to the Supreme Court's May 2023 Sackett decision. The conforming rule became effective upon publication in the Federal Register on September 8, 2023. We anticipate this final rule revision based on the Sackett decision may lead to a decreased number of projects that require Army Corps federal wetland permits. This decision also may affect the administration of some state programs. At this point, our projects requiring federal permits are moving ahead, but we are monitoring these recent developments to better understand potential future impacts. 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, some of which are in the EPA Superfund Alternative Approach Program. We are also working with the state of Wisconsin in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure. In addition, we are coordinating the investigation and cleanup of some of these sites subject to the jurisdiction of the EPA under what is called a "multisite" program. This program involves prioritizing the work to be done at the sites, preparation and approval of documents common to all of the sites, and use of a consistent approach in selecting remedies. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below. 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) 2023 2022 Regulatory assets $ 121.5 $ 118.5 Reserves for future environmental remediation 85.3 88.6 Coal Combustion Residuals Rule The EPA issued a pre-publication proposed rule for CCR in May 2023 that would apply to landfills, historic fill sites, and projects where CCR was placed at a power plant site. As proposed, the rule would regulate previously exempt closed landfills. We are actively engaged with our trade organizations and provided them information to include in their comments to the EPA. The EPA has indicated that it anticipates issuing a final rule in the second quarter of 2024. As proposed, the rule could have a material adverse impact on our coal ash landfills and require additional remediation that has not been required under the current state programs. 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 9.74% by constructing various wind parks, solar parks, 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. Consent Decrees Weston and Pulliam Power Plants In November 2009, the EPA issued an NOV to us, which alleged violations of the CAA's New Source Review requirements relating to certain projects completed at the Weston and Pulliam power plants from 1994 to 2009. We entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Eastern District of Wisconsin in March 2013. With the retirement of Pulliam Units 7 and 8 in October 2018, we completed the mitigation projects required by the Consent Decree and received a completeness letter from the EPA in October 2018. See Note 6, Regulatory Assets and Liabilities, for more information about the retirement. We are working with the EPA on a closeout process for the Consent Decree and expect that process to begin in 2024. Joint Ownership Power Plants – Columbia and Edgewater In December 2009, the EPA issued an NOV to WPL, the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including MG&E, WE (former co-owner of an Edgewater unit), and us. The NOV alleged violations of the CAA's New Source Review requirements related to certain projects completed at those plants. We, along with WPL, MG&E, and WE, entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Western District of Wisconsin in June 2013. As a result of the continued implementation of the Consent Decree related to the jointly owned Columbia and Edgewater plants, the Edgewater 4 generating unit was retired in September 2018. See Note 6, Regulatory Assets and Liabilities, for more information about the retirement. WPL started the process to close out this Consent Decree. |
SUPPLEMENTAL CASH FLOW INFORMAT
SUPPLEMENTAL CASH FLOW INFORMATION | 12 Months Ended |
Dec. 31, 2023 | |
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract] | |
SUPPLEMENTAL CASH FLOW INFORMATION | SUPPLEMENTAL CASH FLOW INFORMATION Non-Cash Transactions Year Ended December 31 (in millions) 2023 2022 2021 Cash paid for interest, net of amount capitalized $ 87.6 $ 67.8 $ 63.2 Cash paid (received) for income taxes, net (1) 2.9 25.9 (55.2) Significant non-cash investing and financing transactions: Accounts payable related to construction costs 24.8 30.3 15.5 Increase in receivables related to insurance proceeds — — 4.3 Liabilities accrued for software licensing agreement — 1.5 — (1) Cash paid for income taxes in 2023 was net of $4.9 million of PTCs that were sold to a third party. Restricted Cash The statements of cash flows include our activity related to cash, cash equivalents, and restricted cash. The following table reconciles the cash, cash equivalents, and restricted cash amounts reported within the balance sheets at December 31 to the total of these amounts shown on the statements of cash flows: (in millions) 2023 2022 2021 Cash and cash equivalents $ 1.4 $ 0.5 $ 2.4 Restricted cash included in other long-term assets — 38.0 — Cash, cash equivalents, and restricted cash $ 1.4 $ 38.5 $ 2.4 At December 31, 2022, our restricted cash consisted of cash used during January 2023 to purchase a 50% interest in a natural gas-fired cogeneration facility located in Whitewater, Wisconsin. This cash was included in other long-term assets. See Note 2, Acquisitions, for more information on the purchase of this facility. |
REGULATORY ENVIRONMENT
REGULATORY ENVIRONMENT | 12 Months Ended |
Dec. 31, 2023 | |
Regulated Operations [Abstract] | |
REGULATORY ENVIRONMENT | REGULATORY ENVIRONMENT 2024 Limited Rate Case Re-Opener In accordance with our rate order approved by the PSCW in December 2022, we filed a request with the PSCW in May 2023 for a limited electric rate case re-opener. The request reflected updated fuel costs and revenue requirements for the generation projects that were previously approved by the PSCW and were placed into service in 2023 or are expected to be placed into service in 2024. On December 20, 2023, the PSCW issued a final written order approving an electric rate decrease of $32.7 million (2.6%) for our Wisconsin retail electric operations, effective January 1, 2024. This amount includes the incremental decrease to our revenue requirements resulting from updated fuel costs. Our ROE and common equity component average were not addressed in the limited rate case re-opener. 2023 and 2024 Rates In April 2022, we filed a request with the PSCW to increase our retail electric and natural gas rates. Our request was updated in July 2022 to reflect new developments that impacted the original proposal. The requested increase in electric rates was driven by capital investments in new wind, solar, and battery storage; capital investments in natural gas generation; and changes in wholesale business with other utilities. Many of these investments had already been approved by the PSCW. The requested increase in natural gas rates primarily related to capital investments that had been made to maintain and improve safety and reliability. In September 2022, we entered into a settlement agreement with certain intervenors to resolve most of the outstanding issues in our rate case; however, the PSCW declined to approve the settlement agreement. In December 2022, the PSCW issued a final written order approving electric and natural gas base rate increases, effective January 1, 2023. The final order reflected the following: 2023 base rate increase Electric $ 120.5 million / 9.8% Gas $ 26.4 million / 7.1% ROE 9.8% Common equity component average on a financial basis 53.0% In addition to the above, the final order included the following terms: • We will keep our current earnings sharing mechanism, under which, if we earn above our authorized ROE: (i) we retain 100.0% of earnings for the first 15 basis points above the authorized ROE; (ii) 50.0% of the next 60 basis points is refunded to ratepayers; and (iii) 100.0% of any remaining excess earnings is required to be refunded to ratepayers. • We were required to complete an analysis of alternative recovery scenarios for generating units that will be retired prior to the end of their useful life. • We will not propose any changes to our real time pricing rates for large commercial and industrial electric customers through the end of 2024. • We were required to lower monthly residential and small commercial electric customer fixed charges by $3.33 from previously authorized rates. • We were required to offer an additional voluntary renewable energy pilot for commercial and industrial customers. • We will continue to work with PSCW staff and other interested parties to develop alternative low income assistance programs. We, along with WE, also collectively contributed $4.0 million to the Keep Wisconsin Warm Fund. • We were required to implement escrow accounting treatment for pension and OPEB costs in 2023 and 2024. • As discussed above, we were authorized to file a limited electric rate case re-opener for 2024. 2022 Rates In March 2021, we filed an application with the PSCW for the approval of certain accounting treatments that allowed us to maintain our electric and natural gas base rates through 2022 and forego filing a rate case for one year. In connection with the request, we also entered into an agreement, dated March 23, 2021, with various stakeholders. Pursuant to the terms of the agreement, the stakeholders fully supported the application. In September 2021, the PSCW issued a written order approving the application. The final order reflected the following: • We amortized, in 2022, certain previously deferred balances to offset approximately half of our forecasted revenue deficiency. • We were able to defer any increases in tax expense due to changes in tax law that occurred in 2021 and/or 2022. • We maintained our earnings sharing mechanism for 2022, with modification. The earnings sharing mechanism was modified to authorize us to retain 100.0% of the first 15 basis points of earnings above our then authorized ROE. The earnings sharing mechanism otherwise remained as previously authorized. 2020 and 2021 Rates In March 2019, we filed an application with the PSCW to increase our retail electric and natural gas 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 were effective January 1, 2020. The final order reflected the following: 2020 Effective rate increase Electric (1) (2) $ 15.8 million / 1.6% Gas (3) $ 4.3 million / 1.4% 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 impacts. The rate order reflected the majority of the unprotected deferred tax benefits from the Tax Legislation being amortized over two years. Approximately $11 million of tax benefits were amortized in 2020 and approximately $39 million were amortized in 2021. 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) The rate order was net of $21 million of refunds related to our 2018 earnings sharing mechanism. These refunds were made to customers evenly over two years, with half returned in 2020 and the remainder returned in 2021. (3) Amount is net of certain deferred tax benefits from the Tax Legislation that were utilized to reduce near-term rate impacts. The rate order reflected all of the unprotected deferred tax benefits from the Tax Legislation being amortized evenly over four years, which resulted in approximately $5 million of previously deferred tax benefits being amortized each year. 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. The rate order allows us to collect the previously deferred revenue requirement for ReACT™ costs above the authorized $275 million level. The total cost of the ReACT™ project was $342 million. This regulatory asset is being collected from customers over eight years. The PSCW approved us continuing to have an earnings sharing mechanism through 2021. The earnings sharing mechanism was modified from its previous structure to one that was consistent with other Wisconsin investor-owned utilities. Under this earnings sharing mechanism, if we earned above our authorized ROE: (i) we retained 100.0% of earnings for the first 25 basis points above the authorized ROE; (ii) 50.0% of the next 50 basis points were required to be refunded to customers; and (iii) 100.0% of any remaining excess earnings were required to be refunded to customers. In addition, the rate order also required 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. Recovery of Natural Gas Costs Due to the cold temperatures, wind, snow, and ice throughout the central part of the country during February 2021, the cost of gas purchased for our natural gas utility customers was temporarily driven significantly higher than our normal winter weather expectations. We have a regulatory mechanism in place for recovering all prudently incurred gas costs. In March 2021, we filed our revised natural gas rate sheets with the PSCW reflecting approximately $28 million of natural gas costs in excess of the benchmark set in our GCRM. We recovered these excess costs over a period of three months, beginning in April 2021. |
OTHER INCOME, NET
OTHER INCOME, NET | 12 Months Ended |
Dec. 31, 2023 | |
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) 2023 2022 2021 Non-service components of net periodic benefit costs $ 35.4 $ 35.3 $ 26.8 AFUDC-Equity 7.6 5.8 9.0 Other, net 2.9 1.2 2.4 Other income, net $ 45.9 $ 42.3 $ 38.2 |
NEW ACCOUNTING PRONOUNCEMENTS
NEW ACCOUNTING PRONOUNCEMENTS | 12 Months Ended |
Dec. 31, 2023 | |
Accounting Standards Update and Change in Accounting Principle [Abstract] | |
NEW ACCOUNTING PRONOUNCEMENTS | NEW ACCOUNTING PRONOUNCEMENTS Improvements to Income Tax Disclosures In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The amendments require additional disclosures, primarily related to income taxes paid and the rate reconciliation table. The amendments require disclosures on specific categories in the rate reconciliation table, as well as additional information for reconciling items that meet a quantitative threshold. For income taxes paid, additional disclosures are required to disaggregate federal, state, and foreign income taxes paid, with additional disclosures for income taxes paid that meet a quantitative threshold. The amendments are effective for annual periods beginning after December 15, 2024, with early adoption permitted. We plan to adopt these amendments beginning with our fiscal year ending on December 31, 2025, and are currently evaluating the impact this guidance may have on our financial statements and related disclosures. Improvements to Reportable Segment Disclosures In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures. The amendments require additional disclosures about reportable segments on an annual and interim basis. The amendments require disclosure of significant segment expenses that are (1) regularly provided to the chief operating decision maker and (2) included in the reported measure of segment profit or loss. The amendments also require disclosure of an amount for other segment items and a description of its composition. The new standard also allows companies to disclose multiple measures of segment profit or loss if those measures are used to assess performance and allocate resources. The amendments are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted. We plan to adopt these amendments beginning with our fiscal year ending on December 31, 2024, and are currently evaluating the impact this guidance may have 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 and in January 2021, the FASB issued ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope. These pronouncements provide temporary optional expedients and exceptions for applying GAAP principles to contract modifications and hedging relationships to ease the financial reporting burdens of the market transition from LIBOR and other interbank offered rates to alternative reference rates. These pronouncements were effective upon issuance on March 12, 2020 through December 31, 2022. In December 2022, the FASB issued ASU No. 2022-06, Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848, to extend the temporary accounting rules under Topic 848 from December 31, 2022 to December 31, 2024, after which entities will no longer be permitted to apply the relief in Topic 848. An entity may elect to apply the amendments prospectively from March 12, 2020 through December 31, 2024 by accounting topic. We do not anticipate this guidance having a significant impact on our financial statements and related disclosures. |
SCHEDULE II - VALUATION AND QUA
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | 12 Months Ended |
Dec. 31, 2023 | |
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract] | |
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | SCHEDULE II WISCONSIN PUBLIC SERVICE CORPORATION 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, 2023 $ 11.7 $ 5.6 $ 3.3 $ (9.7) $ 10.9 December 31, 2022 11.1 8.4 0.1 (7.9) 11.7 December 31, 2021 18.3 6.2 (7.0) (6.4) 11.1 (1) Net of recoveries. (2) Represents amounts written off to the reserve, net of adjustments to regulatory assets. |
Pay vs Performance Disclosure
Pay vs Performance Disclosure - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Pay vs Performance Disclosure | |||
Net income | $ 260.2 | $ 235 | $ 231.1 |
Insider Trading Arrangements
Insider Trading Arrangements | 3 Months Ended |
Dec. 31, 2023 | |
Trading Arrangements, by Individual | |
Rule 10b5-1 Arrangement Adopted | false |
Non-Rule 10b5-1 Arrangement Adopted | false |
Rule 10b5-1 Arrangement Terminated | false |
Non-Rule 10b5-1 Arrangement Terminated | false |
SUMMARY OF SIGNIFICANT ACCOUN_2
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 12 Months Ended |
Dec. 31, 2023 | |
Accounting Policies [Abstract] | |
Nature of operations | We are an electric and natural gas utility company that serves electric and natural gas customers in northeastern Wisconsin. We are subject to the jurisdiction of, and regulation by, the PSCW, which has general supervisory and regulatory powers over virtually all phases of the public utility industry in Wisconsin. In addition, we are subject to the jurisdiction of the FERC, which regulates our natural gas pipelines and wholesale electric rates. We are an indirect, wholly owned subsidiary of WEC Energy Group. |
Consolidation | As used in these notes, the term "financial statements" includes the income statements, balance sheets, statements of cash flows, and statements of equity, unless otherwise noted. |
Jointly owned facilities | These financial statements reflect our proportionate interests in certain jointly owned utility facilities. See Note 8, Jointly Owned Utility Facilities, for more information. |
Equity method 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. |
Basis of presentation | We prepare our financial statements in conformity with GAAP. |
Use of estimates | 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 4, 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. 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 Wisconsin, our 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 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 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. Under normal circumstances, 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. However, as a result of the extreme weather in the Midwest in February 2021, the cost of gas purchased for our natural gas customers was temporarily driven significantly higher than our normal winter weather expectations. See Note 23, Regulatory Environment, for more information on the recovery of these high natural gas costs. 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. 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 5, Credit Losses. 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, 2023 and 2022. 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. |
Materials, Supplies, and Inventories | Our inventories as of December 31 consisted of: (in millions) 2023 2022 Materials and supplies 79.9 59.3 Fossil fuel 52.1 40.2 Natural gas in storage 39.1 65.0 Total $ 171.1 $ 164.5 |
Regulatory assets and liabilities | The economic effects of regulation can result in regulated companies recording costs and revenues that are allowed in the ratemaking 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 6, Regulatory Assets and Liabilities, for more information. |
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 2.93%, 2.67%, and 2.66% in 2023, 2022, and 2021, 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 3 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. See Note 7, Property, Plant, and Equipment, for more information. |
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 7.46%, 7.55%, and 7.55% for 2023, 2022, and 2021, respectively. Our average AFUDC wholesale rates were 4.60%, 5.49%, and 1.04% for 2023, 2022, and 2021, respectively. We recorded the following AFUDC for the years ended December 31: (in millions) 2023 2022 2021 AFUDC-Debt $ 2.9 $ 2.3 $ 3.5 AFUDC-Equity 7.6 5.8 9.0 |
Impairment of goodwill and intangible assets | Goodwill and other intangible assets with indefinite lives are subject to an annual impairment test. Interim impairment tests are performed when impairment indicators are present. During the third quarter of each year, we perform an annual goodwill impairment test. The carrying amount of our goodwill is considered not recoverable if the carrying amount of our net assets exceeds our fair value. An impairment loss is recorded as the excess of the carrying amount of the goodwill over its fair value. For our indefinite-lived intangible assets, an impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds its fair value. An impairment loss is measured as the excess of the carrying amount of the intangible asset over its fair value. No impairment losses were recorded for our indefinite-lived intangible assets during the years ended December 31, 2023, 2022, and 2021. See Note 10, Goodwill and Intangible Assets, for more information. |
Impairment of long-lived assets | 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. 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 its fair value. 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 over its fair value. We assess the likelihood of a disallowance of part of the cost of recently completed plant by considering factors such as applicable regulatory environment changes, our own recent rate orders, as well as recent rate orders of other regulated entities in similar jurisdictions. When it becomes probable that part of the cost of recently completed plant will be disallowed for rate-making purposes, we assess whether a reasonable estimate of the amount of the disallowance can be made. The estimated amount of the probable disallowance will then be deducted from the reported cost of the plant and recognized as an impairment loss. 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. See Note 6, Regulatory Assets and Liabilities, and Note 7, Property, Plant, and Equipment, for more information. |
Impairment of equity method investments | We periodically assess the recoverability of equity method investments when factors indicate the carrying amount of such assets may be impaired. Equity method investments are assessed for impairment by comparing the fair values of these investments to their carrying amounts if a fair value assessment was completed or by reviewing for the presence of impairment indicators. If an impairment exists, and it is determined to be other-than-temporary, an impairment loss is recognized equal to the amount by which the carrying amount exceeds the investment's fair value. |
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. See Note 9, Asset Retirement Obligations, for more information. |
Stock-based compensation | Our employees participate in the WEC Energy Group stock-based compensation plans. In accordance with the 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. In addition to those shares of WEC Energy Group common stock that were subject to awards outstanding as of May 6, 2021, when the plan was last approved by shareholders, 9.0 million shares of WEC Energy Group common stock were reserved for issuance under the plan. 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 connection with certain termination of employment events following 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: 2023 2022 2021 Stock options granted 10,655 16,079 18,021 Estimated weighted-average fair value per stock option $ 19.58 $ 14.71 $ 13.20 Assumptions used to value the options: Risk-free interest rate 3.8% – 4.8% 0.2% – 1.6% 0.1% – 0.9% Dividend yield 3.2 % 3.2 % 2.9 % Expected volatility 22.0 % 21.0 % 21.0 % Expected life (years) 8.3 8.7 8.7 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. All grants of performance units are settled in cash and are accounted for as liability awards accordingly. Performance units accrue forfeitable dividend equivalents in the form of additional performance units. 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. 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. Under the terms of awards granted prior to 2023, participants may earn between 0% and 175% of the performance unit award based on WEC Energy Group's total shareholder return. Pursuant to the plan terms governing these awards, these percentages can be adjusted upwards or downwards by up to 10% based on WEC Energy Group's performance against additional performance measures, if any, adopted by the Compensation Committee. The WEC Energy Group Performance Unit Plan was amended and restated, effective January 1, 2023. In accordance with the amended plan, the Compensation Committee selected multiple performance measures that will be weighted to determine the ultimate payout for the awards granted in 2023 and 2024. The ultimate number of units awarded will be based on WEC Energy Group's total shareholder return compared to the total shareholder return of a peer group of companies over three years (55%), and WEC Energy Group's performance against the weighted average authorized ROE of all of its utility subsidiaries (45%). In addition, the Compensation Committee selected the level of WEC Energy Group's stock price to earnings ratio compared to its peer companies as a performance measure that can increase the payout by up to 25%. In no event can the performance unit payout be greater than 200% of the target award. See Note 11, Common Equity, for more information on WEC Energy Group's stock-based compensation plans. |
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 | We recognize a right of use asset and lease liability for operating and finance leases with a term of greater than one year. As a policy election, we account for each lease component separately from the nonlease components of a contract. 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 renewable generating facilities. 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. |
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. PTCs are recognized in the period in which such credits are generated. The amount of the credit is based upon power production from our qualifying generation facilities. 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 the benefit for loss method, where attributes are realized when WEC Energy Group is able to realize them. We recognize interest and penalties accrued related to unrecognized tax benefits in income tax expense in our income statements. The IRA contains a tax credit transferability provision that allows us to sell PTCs produced after December 31, 2022, to third parties. In September 2023, under this transferability provision, WEC Energy Group entered into an agreement to sell substantially all of our 2023 PTCs to a third party. We elect to account for tax credits transferred under the scope of ASC 740. We include the discount from the sale of tax credits as a component of income tax expense. We will also include any expected proceeds from the sale of tax credits in the evaluation of the realizability of deferred tax assets related to PTCs. The sale of tax credits is presented in the operating activities section of the statements of cash flows consistent with the presentation of cash taxes paid. In April 2023, the IRS issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting that taxpayers may use to determine whether expenses to repair, maintain, replace, or improve natural gas transmission and distribution property must be capitalized for tax purposes. We are currently evaluating the impact this guidance may have on our financial statements and related disclosures. See Note 16, Income Taxes, for more information. |
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, such as FTRs, are categorized in Level 3 due to the significance of unobservable or internally-developed inputs. Our FTRs are valued using MISO auction prices. |
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. Derivative accounting rules provide the option to present certain asset and liability derivative positions net on the balance sheets and to net the related cash collateral against these net derivative positions. We elected not to net these items. On our balance sheets, cash collateral provided to others is reflected in other current assets. See Note 18, Derivative Instruments, for more information. |
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. As of December 31, 2023, we had $20.6 million of standby letters of credit issued by financial institutions for the benefit of third parties that have extended credit to us, which automatically renew each year unless proper termination notice is given. These amounts are not reflected on our balance sheets. |
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. See Note 19, Employee Benefits, for more information. |
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 CCR landfills and manufactured gas plant sites. See Note 9, Asset Retirement Obligations, for more information regarding CCR landfills and Note 21, 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 CCR 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 concentration 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 mechanism 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, 2023. In addition, there were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2023. |
SUMMARY OF SIGNIFICANT ACCOUN_3
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Accounting Policies [Abstract] | |
Schedule of inventory | Our inventories as of December 31 consisted of: (in millions) 2023 2022 Materials and supplies 79.9 59.3 Fossil fuel 52.1 40.2 Natural gas in storage 39.1 65.0 Total $ 171.1 $ 164.5 |
Schedule of AFUDC amounts | We recorded the following AFUDC for the years ended December 31: (in millions) 2023 2022 2021 AFUDC-Debt $ 2.9 $ 2.3 $ 3.5 AFUDC-Equity 7.6 5.8 9.0 |
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: 2023 2022 2021 Stock options granted 10,655 16,079 18,021 Estimated weighted-average fair value per stock option $ 19.58 $ 14.71 $ 13.20 Assumptions used to value the options: Risk-free interest rate 3.8% – 4.8% 0.2% – 1.6% 0.1% – 0.9% Dividend yield 3.2 % 3.2 % 2.9 % Expected volatility 22.0 % 21.0 % 21.0 % Expected life (years) 8.3 8.7 8.7 |
RELATED PARTIES (Tables)
RELATED PARTIES (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Related Party Transactions [Abstract] | |
Schedule of receivables and payables with ATC | Our balance sheets included the following receivables and payables for services provided to or received from ATC: (in millions) December 31, 2023 December 31, 2022 Accounts receivable Services provided to ATC $ 0.7 $ 0.5 Amounts due from ATC for transmission infrastructure upgrades (1) 6.6 3.3 Accounts payable Services received from ATC 12.0 9.1 (1) |
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) 2023 2022 2021 Transactions with WE Natural gas related sales to WE (1) $ 1.3 $ 3.3 $ 2.9 Charges to WE for services and other items (2) 11.3 10.7 9.4 Charges from WE for services and other items (2) 16.2 13.3 11.8 Transactions with WG Natural gas related sales to WG (1) 1.4 0.4 0.1 Transactions with UMERC Natural gas related sales to UMERC (1) 3.1 4.0 2.6 Charges to UMERC for services and other items (2) 2.2 3.7 3.1 Transactions with Bluewater Charges from Bluewater for storage service fees (3) 12.1 10.7 10.3 Charges from Bluewater for other operating fees (3) 2.7 2.3 1.0 Natural gas related sales to Bluewater (1) 1.9 1.9 1.9 Transactions with WBS Charges to WBS for services and other items (2) 13.1 16.1 15.4 Charges from WBS for services and other items (2) 55.6 62.4 67.4 (5) Transactions with ATC Charges to ATC for services and construction 9.3 9.6 8.0 Charges from ATC for network transmission services 114.2 109.5 107.0 Net refund from ATC related to FERC ROE orders — — 2.3 Transactions with WRPC Rental payments to WRPC (4) 2.5 1.9 1.9 Charges to WRPC for operations 0.4 0.4 0.6 Charges from WRPC for services 2.8 2.6 2.4 (1) Includes amounts related to the 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 AIA. (3) We have a long-term service agreement with a wholly owned subsidiary of Bluewater that was previously approved by the PSCW. Bluewater owns natural gas storage facilities in Michigan and provides a portion of our current storage needs. (4) We have an agreement with WRPC whereby we receive 50% of the energy generated from its hydroelectric power generation facilities. (5) Includes $5.4 million for the transfer of certain software assets from WBS. |
OPERATING REVENUES (Tables)
OPERATING REVENUES (Tables) - Utility | 12 Months Ended |
Dec. 31, 2023 | |
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. 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 has different expectations of service, energy and demand requirements, and can be impacted differently by regulatory activities within their jurisdictions. Year Ended December 31 (in millions) 2023 2022 2021 Wisconsin Public Service Corporation Electric utility $ 1,309.9 $ 1,316.5 $ 1,176.7 Natural gas utility 368.0 465.5 338.8 Total revenues from contracts with customers 1,677.9 1,782.0 1,515.5 Other operating revenues 3.5 3.2 5.4 Total operating revenues $ 1,681.4 $ 1,785.2 $ 1,520.9 |
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: Year Ended December 31 (in millions) 2023 2022 2021 Residential $ 479.9 $ 460.4 $ 423.5 Small commercial and industrial 445.9 413.8 376.2 Large commercial and industrial 273.1 293.3 256.6 Other 8.7 8.8 8.4 Total retail revenues 1,207.6 1,176.3 1,064.7 Wholesale 79.2 95.4 86.7 Resale 17.8 27.3 11.4 Other utility revenues 5.3 17.5 13.9 Total electric utility operating revenues $ 1,309.9 $ 1,316.5 $ 1,176.7 |
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: Year Ended December 31 (in millions) 2023 2022 2021 Residential $ 219.8 $ 271.8 $ 202.0 Commercial and industrial 124.2 175.1 122.0 Total retail revenues 344.0 446.9 324.0 Transportation 22.3 20.1 19.4 Other utility revenues (1) 1.7 (1.5) (4.6) Total natural gas utility operating revenues $ 368.0 $ 465.5 $ 338.8 (1) |
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) 2023 2022 2021 Late payment charges $ 3.9 $ 3.8 $ 3.9 Rental revenues 0.3 0.3 0.1 Alternative revenues (1) (0.7) (0.9) 1.4 Total other operating revenues $ 3.5 $ 3.2 $ 5.4 (1) 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 wholesale customers subject to true-ups. |
CREDIT LOSSES (Tables)
CREDIT LOSSES (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
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. (in millions) December 31, 2023 December 31, 2022 Accounts receivable and unbilled revenues $ 230.1 $ 279.5 Allowance for credit losses 10.9 11.7 Accounts receivable and unbilled revenues, net (1) $ 219.2 $ 267.8 Total accounts receivable, net – past due greater than 90 days (1) $ 8.3 $ 8.4 Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1) 93.4 % 95.5 % (1) |
Rollforward of the allowances for credit losses | A rollforward of the allowance for credit losses is included below: Year Ended December 31 (in millions) 2023 2022 2021 Balance at January 1 $ 11.7 $ 11.1 $ 18.3 Provision for credit losses 5.6 8.4 6.2 Provision for credit losses deferred for future recovery or refund 3.3 0.1 (7.0) Write-offs charged against the allowance (14.9) (12.8) (10.0) Recoveries of amounts previously written off 5.2 4.9 3.6 Balance at December 31 $ 10.9 $ 11.7 $ 11.1 |
REGULATORY ASSETS AND LIABILI_2
REGULATORY ASSETS AND LIABILITIES (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
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) 2023 2022 See Note Regulatory assets (1) (2) Environmental remediation costs (3) $ 121.5 $ 118.5 21 Pension and OPEB costs (4) 62.0 48.6 19, 23 Income tax related items 57.2 61.5 16 Plant retirement related items 38.4 43.1 AROs 18.8 15.6 1(k), 9 Derivatives 12.5 22.5 1(p) Bluewater (5) 11.9 6.8 ReACT™ 10.4 13.0 23 Uncollectible expense 8.9 5.6 5 Energy efficiency programs (6) 5.5 13.4 Other, net 13.5 16.9 Total regulatory assets $ 360.6 $ 365.5 (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 $7.7 million and $9.6 million at December 31, 2023 and 2022, respectively. (2) As of December 31, 2023, we had $36.2 million of regulatory assets not earning a return. 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) As of December 31, 2023, we had made cash expenditures of $36.2 million related to these environmental remediation costs. The remaining $85.3 million represents our estimated future cash expenditures. (4) 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. (5) Primarily relates to costs associated with our long-term service agreement with Bluewater for natural gas storage services. The PSCW has approved escrow accounting for these costs. As a result, we defer as a regulatory asset or liability the difference between actual storage costs and those included in rates until recovery or refund is authorized in a future rate proceeding. (6) Represents amounts recoverable from customers related to programs designed to meet energy efficiency standards. |
Schedule of regulatory liabilities | The following regulatory liabilities were reflected on our balance sheets as of December 31: (in millions) 2023 2022 See Note Regulatory liabilities Income tax related items $ 331.4 $ 343.7 16 Removal costs (1) 191.2 186.5 Pension and OPEB benefits (2) 85.3 90.1 19, 23 Energy costs refundable through rate adjustments 36.3 9.9 1(d) Derivatives 4.1 7.9 1(p) Other, net 32.2 22.1 Total regulatory liabilities $ 680.5 $ 660.2 Balance sheet presentation Other current liabilities $ 8.5 $ 9.9 Regulatory liabilities 672.0 650.3 Total regulatory liabilities $ 680.5 $ 660.2 (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 9, 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. |
PROPERTY, PLANT, AND EQUIPMENT
PROPERTY, PLANT, AND EQUIPMENT (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment -Balances | Property, plant, and equipment consisted of the following at December 31: (in millions) 2023 2022 Electric – generation $ 3,108.8 $ 2,736.5 Electric – distribution 2,338.5 2,184.9 Natural gas – distribution, storage, and transmission 1,266.3 1,184.5 Property, plant, and equipment to be retired, net 259.8 273.1 Other 513.3 493.1 Less: Accumulated depreciation 1,857.8 1,662.6 Net 5,628.9 5,209.5 CWIP 172.5 167.2 Total property, plant, and equipment $ 5,801.4 $ 5,376.7 |
Schedule of activity related to severance liability | We have severance liabilities related to past and future plant retirements recorded in other current and other long-term liabilities on our balance sheets. Activity related to these severance liabilities for the years ended December 31 was as follows: (in millions) 2023 2022 2021 Severance liability at January 1 $ 2.7 $ 1.6 $ — Severance expense — 1.1 1.6 Total severance liability at December 31 $ 2.7 $ 2.7 $ 1.6 |
JOINTLY OWNED UTILITY FACILIT_2
JOINTLY OWNED UTILITY FACILITIES (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Jointly Owned Utility Plant, Net Ownership Amount [Abstract] | |
Schedule of jointly owned utility facilities | Information related to jointly owned utility facilities at December 31, 2023 was as follows: Jointly-Owned Utility Facilities Ownership Share of Capacity (MW) In-Service /Acquisition Date Operating Owner Property, Plant, and Equipment Accumulated Depreciation CWIP (in millions, except for percentages and MW) Weston Unit 4 (1) 70.0 % 384.8 2008 WPS $ 613.3 $ (227.3) $ 0.5 Columbia Energy Center Units 1 and 2 (1 ) (5) 27.5 % 312.3 1975 & 1978 WPL 433.1 (173.8) 3.5 Forward Wind (2) 44.6 % 61.5 2008 WPS 119.3 (56.8) — Two Creeks (3) 66.7 % 100.0 2020 WPS 136.9 (14.1) — Badger Hollow I (3) 66.7 % 100.0 2021 WPS 146.2 (9.7) 0.1 Red Barn (2) 90.0 % 82.4 2023 WPS 150.0 (3.2) — Weston RICE units (1) 50.0 % 65.0 2023 WPS 91.7 (1.2) — Whitewater (1) (4) 50.0 % 121.4 2023 WE 125.7 (93.6) 0.4 (1) Capacity is based on rated capacity, which is the net power output under average operating conditions with equipment in an average state of repair as of a given month in a given year. Values are primarily based on the net dependable expected capacity ratings for summer 2024 established by tests and may change slightly from year to year. The summer period is the most relevant for capacity planning purposes. This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand. (2) Capacity for wind generating facilities is based on nameplate capacity, which is the amount of energy a turbine should produce at optimal wind speeds. (3) Capacity for solar generating facilities is based on nameplate capacity, which is the maximum output that a generator should produce at continuous full power. (4) Effective January 1, 2023, we, along with WE, completed the acquisition of Whitewater. See Note 2, Acquisitions, for more information. (5) These units are expected to be retired by June 2026. See Note 7, Property, Plant, and Equipment, for more information. |
ASSET RETIREMENT OBLIGATIONS (T
ASSET RETIREMENT OBLIGATIONS (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
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) 2023 2022 2021 Balance as of January 1 $ 55.1 $ 55.8 $ 45.5 Accretion 2.1 2.0 1.8 Additions 2.2 (1) 0.7 10.7 (4) Revisions to estimated cash flows 1.6 1.4 (2.1) (5) Liabilities settled (4.3) (2) (4.8) (3) (0.1) Balance as of December 31 $ 56.7 $ 55.1 $ 55.8 (1) AROs increased primarily as a result of AROs being recorded for the legal requirement to dismantle, at retirement, the Red Barn wind-powered generation project. See Note 2, Acquisitions, for more information. (2) AROs decreased primarily due to the partial settlement of AROs for landfill and ash pond closure activities. (3) AROs decreased primarily due to the partial settlement of AROs for landfill and ash pond closure activities. (4) AROs increased primarily due to the legal requirement to dismantle, at retirement, the Badger Hollow I solar generation project. (5) AROs decreased primarily due to revisions made to removal estimates for wind generation projects, offset by revisions made to the removal estimates for fly ash landfills and ash ponds. |
COMMON EQUITY (Tables)
COMMON EQUITY (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Stockholders' Equity Note [Abstract] | |
Schedule of stock-based compensation expense and related 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) 2023 2022 2021 Stock options $ 1.0 $ 1.1 $ 1.1 Restricted stock 1.1 1.2 1.0 Performance units (0.4) (1) 3.9 0.4 Stock-based compensation expense $ 1.7 $ 6.2 $ 2.5 Related tax benefit $ 0.5 $ 1.7 $ 0.7 1) |
Schedule of stock option activity | The following is a summary of our employees' WEC Energy Group stock option activity during 2023: 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, 2023 62,168 $ 87.00 Granted 10,655 93.69 Transferred 2,454 75.82 Outstanding as of December 31, 2023 75,277 87.58 6.8 $ 0.3 Exercisable as of December 31, 2023 31,857 79.59 5.3 $ 0.3 |
Schedule of restricted stock activity | The following is a summary of our employees' WEC Energy Group restricted stock activity during 2023: Restricted Shares Number of Shares Weighted-Average Grant Date Fair Value Outstanding and unvested as of January 1, 2023 2,557 $ 93.84 Granted 1,587 93.69 Released (1,233) 93.07 Transferred 74 93.68 Outstanding and unvested as of December 31, 2023 2,985 94.07 |
SHORT-TERM DEBT AND LINES OF _2
SHORT-TERM DEBT AND LINES OF CREDIT (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
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) 2023 2022 Commercial paper Amount outstanding at December 31 $ 310.3 $ 194.9 Average interest rate on amounts outstanding at December 31 5.41 % 4.60 % |
Schedule of revolving credit facilities and remaining available capacity | 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 2023 Revolving credit facility September 2026 $ 400.0 Less: Letters of credit issued inside credit facility 1.3 Commercial paper outstanding 310.3 Available capacity under existing agreement $ 88.4 |
LONG-TERM DEBT (Tables)
LONG-TERM DEBT (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Debt Disclosure [Abstract] | |
Schedule of long-term debt instruments | The following table is a summary of our long-term debt outstanding (excluding finance leases) as of December 31: (in millions) Interest Rate Year Due 2023 2022 Senior Notes (unsecured) 5.35% 2025 $ 300.0 $ 300.0 6.08% 2028 50.0 50.0 5.55% 2036 125.0 125.0 3.671% 2042 300.0 300.0 4.752% 2044 450.0 450.0 3.30% 2049 300.0 300.0 2.85% 2051 450.0 450.0 Total 1,975.0 1,975.0 Unamortized debt issuance costs (14.5) (15.5) Unamortized discount, net (1.4) (1.5) Total long-term debt (1) $ 1,959.1 $ 1,958.0 (1) |
Schedule of future maturities of long-term debt | The following table shows the future maturities of our long-term debt outstanding (excluding obligations under finance leases) as of December 31, 2023: (in millions) Payments 2024 $ — 2025 300.0 2026 — 2027 — 2028 50.0 Thereafter 1,625.0 Total $ 1,975.0 |
LEASES (Tables)
LEASES (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Leases [Abstract] | |
Schedule of other lease information | Other information related to these leases for the years ended December 31 are as follows: Other information (dollar amounts in millions) 2023 2022 2021 Non-cash activities: Right of use assets obtained in exchange for finance lease liabilities $ 6.6 $ 10.2 $ 2.6 Reduction of right of use asset and finance lease liability due to a remeasurement — — (2.9) Weighted average remaining lease term 48.4 years 49.0 years 49.6 years Weighted average discount rate (1) 4.3 % 3.9 % 3.3 % (1) Because these 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. |
Schedule of finance lease right of use assets and obligations | The following table summarizes our finance lease right of use assets and obligations at December 31: (in millions) 2023 2022 Balance Sheet Location Right of use assets Finance lease right of use assets, net (1) $ 43.8 $ 38.0 Property, plant, and equipment, net Lease obligations Long-term finance lease liabilities $ 49.0 $ 41.9 Long-term debt (1) Amounts are net of accumulated amortization of $3.1 million and $2.2 million at December 31, 2023 and 2022, respectively. |
Schedule of future minimum lease payments for finance leases | Future minimum lease payments under our finance leases and the present value of our net minimum lease payments as of December 31, 2023, were as follows: (in millions) Total Finance Leases 2024 $ 1.4 2025 1.6 2026 1.6 2027 1.7 2028 1.7 Thereafter 126.6 Total minimum lease payments 134.6 Less: Interest (85.6) Present value of minimum lease payments 49.0 Less: Short-term lease liabilities — Long-term lease liabilities $ 49.0 |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Income Tax Disclosure [Abstract] | |
Summary of income tax expense | The following table is a summary of income tax expense for each of the years ended December 31: (in millions) 2023 2022 2021 Current tax expense (benefit) $ 17.8 $ 8.7 $ (18.3) Deferred income taxes, net 48.7 66.3 51.1 ITCs (3.8) (2.8) (1.6) Total income tax expense $ 62.7 $ 72.2 $ 31.2 |
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: 2023 2022 2021 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Amount Effective Tax Rate Statutory federal income tax $ 67.8 21.0 % $ 64.5 21.0 % $ 55.1 21.0 % State income taxes net of federal tax benefit 20.2 6.3 % 19.5 6.3 % 16.3 6.2 % PTCs, net (14.4) (4.5) % (0.6) (0.2) % — — % Federal excess deferred tax amortization (1) (5.7) (1.8) % (5.2) (1.7) % (5.2) (2.0) % Federal excess deferred tax amortization – Wisconsin unprotected (2) (3.8) (1.2) % (3.8) (1.2) % (33.0) (12.6) % ITCs (3.8) (1.2) % (2.8) (0.9) % (1.6) (0.6) % Other, net 2.4 0.8 % 0.6 0.2 % (0.4) (0.1) % Total income tax expense $ 62.7 19.4 % $ 72.2 23.5 % $ 31.2 11.9 % (1) 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. (2) In accordance with the rate order received from the PSCW in December 2019, we amortized 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. |
Components of deferred income taxes | The components of deferred income taxes as of December 31 were as follows: (in millions) 2023 2022 Deferred tax assets Tax gross up – regulatory items $ 94.8 $ 99.9 Future tax benefits 8.8 3.5 Other 21.3 23.3 Total deferred tax assets $ 124.9 $ 126.7 Deferred tax liabilities Property-related 935.7 878.3 Employee benefits and compensation 66.7 62.2 Other 46.9 46.9 Total deferred tax liabilities 1,049.3 987.4 Deferred tax liability, net $ 924.4 $ 860.7 |
Components of deferred tax assets associated with federal tax benefit carryforwards | The components of net deferred tax assets associated with federal tax benefit carryforwards as of December 31, 2023 and 2022 are summarized in the tables below: 2023 (in millions) Gross Value Deferred Tax Effect Earliest Year of Expiration Future tax benefits as of December 31, 2023 Federal tax credit $ — $ 8.8 2042 Balance as of December 31, 2023 $ — $ 8.8 2022 (in millions) Gross Value Deferred Tax Effect Earliest Year of Expiration Future tax benefits as of December 31, 2022 Federal tax credit $ — $ 3.5 2041 Balance as of December 31, 2022 $ — $ 3.5 |
FAIR VALUE MEASUREMENTS (Tables
FAIR VALUE MEASUREMENTS (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
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, 2023 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 0.6 $ 1.3 $ — $ 1.9 FTRs — — 2.0 2.0 Coal contracts — 0.3 — 0.3 Total derivative assets $ 0.6 $ 1.6 $ 2.0 $ 4.2 Derivative liabilities Natural gas contracts $ 7.4 $ 0.5 $ — $ 7.9 Coal contracts — 1.0 — 1.0 Total derivative liabilities $ 7.4 $ 1.5 $ — $ 8.9 December 31, 2022 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 1.2 $ 0.5 $ — $ 1.7 FTRs — — 4.1 4.1 Coal contracts — 1.8 — 1.8 Total derivative assets $ 1.2 $ 2.3 $ 4.1 $ 7.6 Derivative liabilities Natural gas contracts $ 14.5 $ 2.4 $ — $ 16.9 |
Reconciliation of changes in the 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) 2023 2022 2021 Balance at the beginning of the period $ 4.1 $ 1.4 $ 1.2 Purchases 6.3 11.7 3.1 Settlements (8.4) (9.0) (2.9) Balance at the end of the period $ 2.0 $ 4.1 $ 1.4 |
Schedule of carrying value and 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, 2023 December 31, 2022 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt (1) $ 1,959.1 $ 1,662.8 $ 1,958.0 $ 1,607.2 (1) The carrying amount of long-term debt excludes finance lease obligations of $49.0 million and $41.9 million at December 31, 2023 and 2022, respectively. |
DERIVATIVE INSTRUMENTS (Tables)
DERIVATIVE INSTRUMENTS (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of derivative assets and liabilities | The following table shows our derivative assets and derivative liabilities. None of the derivatives shown below were designated as hedging instruments. December 31, 2023 December 31, 2022 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Current Natural gas contracts $ 1.9 $ 7.4 $ 1.7 $ 16.3 FTRs 2.0 — 4.1 — Coal contracts 0.3 0.7 1.4 — Total current 4.2 8.1 7.2 16.3 Long-term Natural gas contracts — 0.5 — 0.6 Coal contracts — 0.3 0.4 — Total long-term — 0.8 0.4 0.6 Total $ 4.2 $ 8.9 $ 7.6 $ 16.9 |
Schedule of estimated notional sales volumes and realized gains (losses) | Our estimated notional sales volumes and realized gains and losses were as follows for the years ended: December 31, 2023 December 31, 2022 December 31, 2021 (in millions) Volumes Gains (Losses) Volumes Gains Volumes Gains Natural gas contracts 40.6 Dth $ (52.0) 33.4 Dth $ 43.1 37.5 Dth $ 21.8 FTRs 8.3 MWh 10.2 7.8 MWh 2.5 7.0 MWh 8.7 Total $ (41.8) $ 45.6 $ 30.5 |
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, 2023 December 31, 2022 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 4.2 $ 8.9 $ 7.6 $ 16.9 Gross amount not offset on the balance sheet (0.6) (7.5) (1) (1.4) (14.8) (2) Net amount $ 3.6 $ 1.4 $ 6.2 $ 2.1 (1) Includes cash collateral posted of $6.9 million. (2) |
EMPLOYEE BENEFITS (Tables)
EMPLOYEE BENEFITS (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
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) 2023 2022 2023 2022 Change in benefit obligation Obligation at January 1 $ 560.7 $ 773.1 $ 112.2 $ 146.9 Service cost 4.8 9.0 2.8 4.0 Interest cost 30.1 22.7 6.1 4.4 Net transfer from affiliates — — — 0.3 Actuarial loss (gain) 25.3 (204.9) 16.7 (36.2) Participant contributions — — 0.8 0.6 Benefit payments (34.2) (39.2) (9.9) (7.8) Obligation at December 31 $ 586.7 $ 560.7 $ 128.7 $ 112.2 Change in fair value of plan assets Fair value at January 1 $ 685.1 $ 859.4 $ 255.6 $ 303.6 Actual return on plan assets 62.2 (135.7) 24.5 (41.7) Employer contributions 0.6 0.6 0.9 0.9 Participant contributions — — 0.8 0.6 Benefit payments (34.2) (39.2) (9.9) (7.8) Fair value at December 31 $ 713.7 $ 685.1 $ 271.9 $ 255.6 Funded status at December 31 $ 127.0 $ 124.4 $ 143.2 $ 143.4 |
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) 2023 2022 2023 2022 Pension and OPEB assets $ 131.6 $ 129.5 $ 152.9 $ 152.6 Other long-term liabilities 4.6 5.1 9.7 9.2 Total net assets $ 127.0 $ 124.4 $ 143.2 $ 143.4 |
Defined Benefit Plan Disclosure [Line Items] | |
Amounts that had not yet been recognized in the entity's net periodic benefit cost | The following table shows the amounts that had not yet been recognized in our net periodic benefit cost as of December 31: Pension Benefits OPEB Benefits (in millions) 2023 2022 2023 2022 Net regulatory assets (liabilities) Net actuarial loss (gain) $ 53.2 $ 56.1 $ (28.1) $ (35.6) Prior service credits — — (21.0) (31.2) Total $ 53.2 $ 56.1 $ (49.1) $ (66.8) |
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) 2023 2022 2021 2023 2022 2021 Service cost $ 4.8 $ 9.0 $ 10.6 $ 2.8 $ 4.0 $ 4.3 Interest cost 30.1 22.7 21.9 6.1 4.4 4.2 Expected return on plan assets (51.3) (55.2) (51.8) (16.3) (21.0) (20.4) Plan curtailment — — — — — (6.4) Amortization of prior service credit — — — (10.2) (10.2) (10.3) Amortization of net actuarial loss (gain) 17.3 17.3 26.6 1.0 (2.5) (3.7) Net periodic benefit cost (credit) $ 0.9 $ (6.2) $ 7.3 $ (16.6) $ (25.3) $ (32.3) |
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 2023 2022 2023 2022 Discount rate 5.15% 5.50% 5.16% 5.50% Rate of compensation increase 4.00% 4.00% N/A N/A Interest credit rate 4.50% 4.00% N/A N/A Assumed medical cost trend rate (Pre 65) N/A N/A 6.25% 6.50% 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 2031 2031 Assumed medical cost trend rate (Post 65) N/A N/A 6.25% 6.00% 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 2030 2031 The weighted-average assumptions used to determine net periodic benefit cost for the plans were as follows for the years ended December 31: Pension Benefits 2023 2022 2021 Discount rate 5.50% 3.00% 2.74% Expected return on plan assets 6.75% 7.00% 7.00% Rate of compensation increase 4.00% 4.00% 4.00% Interest credit rate 4.00% 2.25% 2.25% OPEB Benefits 2023 2022 2021 Discount rate 5.50% 2.98% 2.95% Expected return on plan assets 6.50% 7.00% 7.00% Assumed medical cost trend rate (Pre 65) 6.50% 5.70% 5.85% Ultimate trend rate (Pre 65) 5.00% 5.00% 5.00% Year ultimate trend rate is reached (Pre 65) 2031 2028 2028 Assumed medical cost trend rate (Post 65) 6.00% 5.60% 5.70% Ultimate trend rate (Post 65) 5.00% 5.00% 5.00% Year ultimate trend rate is reached (Post 65) 2031 2028 2028 |
Investments recorded at fair value, by asset class | The following tables provide the fair values of our investments by asset class: December 31, 2023 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 $ 52.0 $ — $ — $ 52.0 $ 32.6 $ — $ — $ 32.6 International equity 53.7 — — 53.7 29.8 — — 29.8 Fixed income securities: (1) United States bonds — 176.7 — 176.7 33.9 61.3 — 95.2 International bonds — 22.8 — 22.8 — 2.9 — 2.9 $ 105.7 $ 199.5 $ — $ 305.2 $ 96.3 $ 64.2 $ — $ 160.5 Investments measured at net asset value: Equity securities 112.5 65.1 Fixed income securities 66.1 17.1 Other 229.9 29.2 Total $ 713.7 $ 271.9 (1) This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries. December 31, 2022 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 $ 70.2 $ — $ — $ 70.2 $ 28.4 $ — $ — $ 28.4 International equity 61.3 — — 61.3 27.3 — — 27.3 Fixed income securities: (1) United States bonds — 130.7 — 130.7 50.2 32.6 — 82.8 International bonds — 23.7 — 23.7 — 3.0 — 3.0 $ 131.5 $ 154.4 $ — $ 285.9 $ 105.9 $ 35.6 $ — $ 141.5 Investments measured at net asset value: Equity securities 141.6 58.6 Fixed income securities 53.0 24.7 Other 204.6 30.8 Total $ 685.1 $ 255.6 (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 2024 $ 37.2 $ 8.8 2025 37.1 9.0 2026 37.3 9.4 2027 37.6 9.7 2028 38.0 9.9 2029-2033 190.8 50.1 |
Pension Benefits | |
Defined Benefit Plan Disclosure [Line Items] | |
Information for pension and OPEB plans with an accumulated benefit obligation in excess of plan assets | The following table shows information for pension plans with an accumulated benefit obligation in excess of plan assets. There were no plan assets related to these pension plans. Amounts presented are as of December 31: (in millions) 2023 2022 Accumulated benefit obligation $ 4.7 $ 5.1 |
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. There were no plan assets related to these pension plans. Amounts presented are as of December 31: (in millions) 2023 2022 Projected benefit obligation $ 4.7 $ 5.1 |
OPEB Benefits | |
Defined Benefit Plan Disclosure [Line Items] | |
Information for pension and OPEB plans with an accumulated benefit obligation in excess of plan assets | The following table shows information for OPEB plans with an accumulated benefit obligation in excess of plan assets. Amounts presented are as of December 31: (in millions) 2023 2022 Accumulated benefit obligation $ 14.5 $ 14.4 Fair value of plan assets 4.8 5.3 |
SEGMENTS INFORMATION (Tables)
SEGMENTS INFORMATION (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Segment Reporting [Abstract] | |
Schedule of information related to reportable segments | The following tables show summarized financial information related to our reportable segments for the years ended December 31, 2023, 2022, and 2021. 2023 (in millions) Utility Other Wisconsin Public Service Corporation External revenues $ 1,681.4 $ — $ 1,681.4 Other operation and maintenance 434.3 — 434.3 Depreciation and amortization 226.9 — 226.9 Other income, net 43.8 2.1 45.9 Interest expense 89.0 — 89.0 Income tax expense 62.3 0.4 62.7 Net income 258.5 1.7 260.2 Capital expenditures and asset acquisitions 635.6 — 635.6 Total assets 7,017.5 13.6 7,031.1 2022 (in millions) Utility Other Wisconsin Public Service Corporation External revenues $ 1,785.2 $ — $ 1,785.2 Other operation and maintenance 362.5 — 362.5 Depreciation and amortization 199.8 — 199.8 Other income, net 41.0 1.3 42.3 Interest expense 70.5 — 70.5 Income tax expense 71.9 0.3 72.2 Net income 234.0 1.0 235.0 Capital expenditures 433.8 — 433.8 Total assets 6,696.0 12.8 6,708.8 2021 (in millions) Utility Other Wisconsin Public Service Corporation External revenues $ 1,520.9 $ — $ 1,520.9 Other operation and maintenance 406.4 — 406.4 Depreciation and amortization 188.6 — 188.6 Other income, net 36.8 1.4 38.2 Interest expense 64.7 — 64.7 Income tax expense 30.9 0.3 31.2 Net income 230.0 1.1 231.1 Capital expenditures 389.7 — 389.7 Total assets 6,224.3 11.4 6,235.7 |
COMMITMENTS AND CONTINGENCIES (
COMMITMENTS AND CONTINGENCIES (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
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, 2023: Payments Due By Period (in millions) Date Contracts Extend Through Total Amounts Committed 2024 2025 2026 2027 2028 Later Years Electric utility: Purchased power 2063 $ 310.6 $ 53.9 $ 54.9 $ 55.9 $ 50.5 $ 46.8 $ 48.6 Coal supply and transportation 2026 194.1 110.4 70.4 13.3 — — — Other 2043 100.6 13.9 13.3 12.9 11.6 10.2 38.7 Natural gas utility supply and transportation 2048 376.5 57.5 31.5 21.5 21.4 20.1 224.5 Total $ 981.8 $ 235.7 $ 170.1 $ 103.6 $ 83.5 $ 77.1 $ 311.8 |
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) 2023 2022 Regulatory assets $ 121.5 $ 118.5 Reserves for future environmental remediation 85.3 88.6 |
SUPPLEMENTAL CASH FLOW INFORM_2
SUPPLEMENTAL CASH FLOW INFORMATION (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract] | |
Schedule of supplemental cash flow information | Year Ended December 31 (in millions) 2023 2022 2021 Cash paid for interest, net of amount capitalized $ 87.6 $ 67.8 $ 63.2 Cash paid (received) for income taxes, net (1) 2.9 25.9 (55.2) Significant non-cash investing and financing transactions: Accounts payable related to construction costs 24.8 30.3 15.5 Increase in receivables related to insurance proceeds — — 4.3 Liabilities accrued for software licensing agreement — 1.5 — (1) Cash paid for income taxes in 2023 was net of $4.9 million of PTCs that were sold to a third party. |
Reconciliation of cash, cash equivalents, and restricted cash | The following table reconciles the cash, cash equivalents, and restricted cash amounts reported within the balance sheets at December 31 to the total of these amounts shown on the statements of cash flows: (in millions) 2023 2022 2021 Cash and cash equivalents $ 1.4 $ 0.5 $ 2.4 Restricted cash included in other long-term assets — 38.0 — Cash, cash equivalents, and restricted cash $ 1.4 $ 38.5 $ 2.4 |
REGULATORY ENVIRONMENT (Tables)
REGULATORY ENVIRONMENT (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
2023 and 2024 Rates | |
Public Utilities, General Disclosures | |
Schedule of regulatory decisions | The final order reflected the following: 2023 base rate increase Electric $ 120.5 million / 9.8% Gas $ 26.4 million / 7.1% ROE 9.8% Common equity component average on a financial basis 53.0% |
2020 and 2021 rates | |
Public Utilities, General Disclosures | |
Schedule of regulatory decisions | The final order reflected the following: 2020 Effective rate increase Electric (1) (2) $ 15.8 million / 1.6% Gas (3) $ 4.3 million / 1.4% 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 impacts. The rate order reflected the majority of the unprotected deferred tax benefits from the Tax Legislation being amortized over two years. Approximately $11 million of tax benefits were amortized in 2020 and approximately $39 million were amortized in 2021. 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) The rate order was net of $21 million of refunds related to our 2018 earnings sharing mechanism. These refunds were made to customers evenly over two years, with half returned in 2020 and the remainder returned in 2021. (3) Amount is net of certain deferred tax benefits from the Tax Legislation that were utilized to reduce near-term rate impacts. The rate order reflected all of the unprotected deferred tax benefits from the Tax Legislation being amortized evenly over four years, which resulted in approximately $5 million of previously deferred tax benefits being amortized each year. 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. |
OTHER INCOME, NET (Tables)
OTHER INCOME, NET (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
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) 2023 2022 2021 Non-service components of net periodic benefit costs $ 35.4 $ 35.3 $ 26.8 AFUDC-Equity 7.6 5.8 9.0 Other, net 2.9 1.2 2.4 Other income, net $ 45.9 $ 42.3 $ 38.2 |
SUMMARY OF SIGNIFICANT ACCOUN_4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES CASH AND CASH EQUIVALENTS (Details) | 12 Months Ended |
Dec. 31, 2023 | |
Accounting Policies [Abstract] | |
Maximum term of original maturity to classify instrument as cash equivalents | 3 months |
SUMMARY OF SIGNIFICANT ACCOUN_5
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES OPERATING REVENUES (Details) | 12 Months Ended |
Dec. 31, 2023 performance_obligations contract | |
Electric | |
Disaggregation of Operating Revenues | |
Number of days payment is due | 30 days |
Electric | Retail | |
Disaggregation of Operating Revenues | |
Number of performance obligations | 1 |
Percentage fuel and purchased power costs can vary from the rate case approved amounts before deferral is required | 2% |
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_6
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES CREDIT LOSSES (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Other | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts receivable and unbilled revenues | $ 0 | $ 0 |
SUMMARY OF SIGNIFICANT ACCOUN_7
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES MATERIALS, SUPPLIES, AND INVENTORIES (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Accounting Policies [Abstract] | ||
Materials and supplies | $ 79.9 | $ 59.3 |
Fossil fuel | 52.1 | 40.2 |
Natural gas in storage | 39.1 | 65 |
Total | $ 171.1 | $ 164.5 |
SUMMARY OF SIGNIFICANT ACCOUN_8
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES PROPERTY, PLANT, AND EQUIPMENT (Details) | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Property, plant, and equipment | |||
Annual utility composite depreciation rate (as a percent) | 2.93% | 2.67% | 2.66% |
Software | Minimum | |||
Property, plant, and equipment | |||
Estimated useful life | 3 years | ||
Software | Maximum | |||
Property, plant, and equipment | |||
Estimated useful life | 15 years |
SUMMARY OF SIGNIFICANT ACCOUN_9
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AFUDC (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
AFUDC | |||
AFUDC - Debt | $ 2.9 | $ 2.3 | $ 3.5 |
AFUDC - Equity | $ 7.6 | $ 5.8 | $ 9 |
Retail | |||
AFUDC | |||
Percentage of retail jurisdictional construction work in progress expenditures subject to AFUDC | 50% | ||
Average AFUDC rate (as a percent) | 7.46% | 7.55% | 7.55% |
Wholesale | |||
AFUDC | |||
Average AFUDC rate (as a percent) | 4.60% | 5.49% | 1.04% |
SUMMARY OF SIGNIFICANT ACCOU_10
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES ASSET IMPAIRMENT (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Accounting Policies [Abstract] | |||
Impairment losses for indefinite-lived intangible assets | $ 0 | $ 0 | $ 0 |
SUMMARY OF SIGNIFICANT ACCOU_11
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES STOCK-BASED COMPENSATION (Details) - $ / shares | 12 Months Ended | |||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | May 06, 2021 | |
Share-based Compensation Arrangement by Share-based Payment Award | ||||
Number of shares of WEC Energy Group common stock authorized for issuance | 9,000,000 | |||
Stock options | ||||
Share-based Compensation Arrangement by Share-based Payment Award | ||||
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% | |||
Period after the grant date during which stock options can't be exercised (in months) | 6 months | |||
Maximum term of awards | 10 years | |||
Stock options granted | 10,655 | 16,079 | 18,021 | |
Estimated weighted-average fair value per stock option (in dollars per share) | $ 19.58 | $ 14.71 | $ 13.20 | |
Risk-free interest rate, minimum (as a percent) | 3.80% | 0.20% | 0.10% | |
Risk-free interest rate, maximum (as a percent) | 4.80% | 1.60% | 0.90% | |
Dividend yield (as a percent) | 3.20% | 3.20% | 2.90% | |
Expected Volatility (as a percent) | 22% | 21% | 21% | |
Expected life (years) | 8 years 3 months 18 days | 8 years 8 months 12 days | 8 years 8 months 12 days | |
Restricted stock | ||||
Share-based Compensation Arrangement by Share-based Payment Award | ||||
Vesting period (in years) | 3 years | |||
Percentage to vest each year after the grant date | 33% | |||
Performance units | ||||
Share-based Compensation Arrangement by Share-based Payment Award | ||||
Vesting period (in years) | 3 years | |||
Performance units | Performance units granted prior to 2023 | ||||
Share-based Compensation Arrangement by Share-based Payment Award | ||||
Maximum adjustment to payout ratio | 10% | |||
Performance units | Performance units granted prior to 2023 | Minimum | ||||
Share-based Compensation Arrangement by Share-based Payment Award | ||||
Payout ratio (as a percent) | 0% | |||
Performance units | Performance units granted prior to 2023 | Maximum | ||||
Share-based Compensation Arrangement by Share-based Payment Award | ||||
Payout ratio (as a percent) | 175% | |||
Performance units | Performance units granted after January 1, 2023 | ||||
Share-based Compensation Arrangement by Share-based Payment Award | ||||
Vesting period (in years) | 3 years | |||
Maximum adjustment to payout ratio | 25% | |||
Percentage of payout based on total shareholder return | 55% | |||
Percentage of payout based on ROE | 45% | |||
Performance units | Performance units granted after January 1, 2023 | Maximum | ||||
Share-based Compensation Arrangement by Share-based Payment Award | ||||
Payout ratio (as a percent) | 200% |
SUMMARY OF SIGNIFICANT ACCOU_12
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - LEASES (Details) | Dec. 31, 2023 |
Accounting Policies [Abstract] | |
Minimum lease term to recognize right of use asset and lease liabilities | 1 year |
SUMMARY OF SIGNIFICANT ACCOU_13
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES GUARANTEES (Details) $ in Millions | Dec. 31, 2023 USD ($) |
Standby letters of credit | |
Guarantor Obligations | |
Guarantee | $ 20.6 |
SUMMARY OF SIGNIFICANT ACCOU_14
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES CUSTOMER CONCENTRATION OF CREDIT RISK (Details) - Customer concentration risk | 12 Months Ended |
Dec. 31, 2023 customer | |
Customer concentrations of credit risk | |
Number of customers that account for more than 10% of revenues | 0 |
Revenue Benchmark | Fair Value, Concentration of Risk, All Financial Instruments | |
Customer concentrations of credit risk | |
Threshold percentage of revenues from major customers | 10% |
ACQUISITIONS - RED BARN (Detail
ACQUISITIONS - RED BARN (Details) - Red Barn $ in Millions | 1 Months Ended |
Apr. 30, 2023 USD ($) MW | |
Asset Acquisition [Line Items] | |
Capacity of generation unit | MW | 82 |
Acquisition purchase price, expected | $ | $ 143.8 |
ACQUISITIONS - WHITEWATER (Deta
ACQUISITIONS - WHITEWATER (Details) - Whitewater $ in Millions | 1 Months Ended | |
Jan. 31, 2023 USD ($) | Jan. 01, 2023 MW | |
Asset Acquisition [Line Items] | ||
Capacity of generation unit | MW | 236.5 | |
Purchase price | $ | $ 38 | |
Ownership (as a percent) | 50% |
RELATED PARTIES - RECEIVABLES A
RELATED PARTIES - RECEIVABLES AND PAYABLES WITH ATC (Details) - ATC - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Related parties | ||
Services provided to ATC | $ 0.7 | $ 0.5 |
Amounts due from ATC for transmission infrastructure upgrades | 6.6 | 3.3 |
Services received from ATC | $ 12 | $ 9.1 |
RELATED PARTIES - OTHER TRANSAC
RELATED PARTIES - OTHER TRANSACTIONS (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Related parties | |||
Natural gas related sales | $ 1,681.4 | $ 1,785.2 | $ 1,520.9 |
Charges from related party for services and other items | 434.3 | 362.5 | 406.4 |
WRPC | |||
Related parties | |||
Charges to related party for services and other items | 0.4 | 0.4 | 0.6 |
Charges from related party for services and other items | 2.8 | 2.6 | 2.4 |
Rental payments to WRPC | $ 2.5 | $ 1.9 | $ 1.9 |
Percentage of energy generated that we receive | 50% | 50% | 50% |
WE | |||
Related parties | |||
Charges to related party for services and other items | $ 11.3 | $ 10.7 | $ 9.4 |
Charges from related party for services and other items | 16.2 | 13.3 | 11.8 |
WE | Natural gas | |||
Related parties | |||
Natural gas related sales | 1.3 | 3.3 | 2.9 |
WG | Natural gas | |||
Related parties | |||
Natural gas related sales | 1.4 | 0.4 | 0.1 |
UMERC | |||
Related parties | |||
Charges to related party for services and other items | 2.2 | 3.7 | 3.1 |
UMERC | Natural gas | |||
Related parties | |||
Natural gas related sales | 3.1 | 4 | 2.6 |
Bluewater | Natural gas | |||
Related parties | |||
Natural gas related sales | 1.9 | 1.9 | 1.9 |
Bluewater | Natural gas storage | |||
Related parties | |||
Natural gas related purchases | 12.1 | 10.7 | 10.3 |
Other Operating fees | 2.7 | 2.3 | 1 |
WBS | |||
Related parties | |||
Charges to related party for services and other items | 13.1 | 16.1 | 15.4 |
Charges from related party for services and other items | 55.6 | 62.4 | 67.4 |
Payments for transfer of certain software assets from WBS | 5.4 | ||
ATC | |||
Related parties | |||
Charges to related party for services and other items | 9.3 | 9.6 | 8 |
Charges from related party for services and other items | 114.2 | 109.5 | 107 |
Net refund from ATC related to FERC ROE orders | $ 0 | $ 0 | $ 2.3 |
OPERATING REVENUES - DISAGGREGA
OPERATING REVENUES - DISAGGREGATION OF OPERATING REVENUES BY SEGMENT (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Disaggregation of Operating Revenues | |||
Operating revenues | $ 1,681.4 | $ 1,785.2 | $ 1,520.9 |
Utility | |||
Disaggregation of Operating Revenues | |||
Operating revenues | 1,681.4 | 1,785.2 | 1,520.9 |
Utility | Other operating revenues | |||
Disaggregation of Operating Revenues | |||
Other operating revenues | 3.5 | 3.2 | 5.4 |
Utility | Transferred over time | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 1,677.9 | 1,782 | 1,515.5 |
Utility | Electric | Transferred over time | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 1,309.9 | 1,316.5 | 1,176.7 |
Utility | Natural gas | Transferred over time | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | $ 368 | $ 465.5 | $ 338.8 |
OPERATING REVENUES - DISAGGRE_2
OPERATING REVENUES - DISAGGREGATION OF ELECTRIC UTILITY OPERATING REVENUES BY CUSTOMER CLASS (Details) - Utility - Revenues from contracts with customers - Transferred over time - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | $ 1,677.9 | $ 1,782 | $ 1,515.5 |
Electric | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 1,309.9 | 1,316.5 | 1,176.7 |
Electric | Total retail revenues | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 1,207.6 | 1,176.3 | 1,064.7 |
Electric | Residential | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 479.9 | 460.4 | 423.5 |
Electric | Small commercial and industrial | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 445.9 | 413.8 | 376.2 |
Electric | Large commercial and industrial | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 273.1 | 293.3 | 256.6 |
Electric | Other | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 8.7 | 8.8 | 8.4 |
Electric | Wholesale | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 79.2 | 95.4 | 86.7 |
Electric | Resale | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 17.8 | 27.3 | 11.4 |
Electric | Other utility revenues | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | $ 5.3 | $ 17.5 | $ 13.9 |
OPERATING REVENUES - DISAGGRE_3
OPERATING REVENUES - DISAGGREGATION OF NATURAL GAS UTILITY OPERATING REVENUES BY CUSTOMER CLASS (Details) - Utility - Revenues from contracts with customers - Transferred over time - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | $ 1,677.9 | $ 1,782 | $ 1,515.5 |
Natural gas | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 368 | 465.5 | 338.8 |
Natural gas | Total retail revenues | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 344 | 446.9 | 324 |
Natural gas | Residential | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 219.8 | 271.8 | 202 |
Natural gas | Commercial and industrial | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 124.2 | 175.1 | 122 |
Natural gas | Transport | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 22.3 | 20.1 | 19.4 |
Natural gas | Other utility revenues | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | $ 1.7 | $ (1.5) | $ (4.6) |
OPERATING REVENUES - OTHER OPER
OPERATING REVENUES - OTHER OPERATING REVENUES (Details) - Utility - Other operating revenues - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Disaggregation of Operating Revenues | |||
Other operating revenues | $ 3.5 | $ 3.2 | $ 5.4 |
Late payment charges | |||
Disaggregation of Operating Revenues | |||
Other operating revenues | 3.9 | 3.8 | 3.9 |
Rental revenues | |||
Disaggregation of Operating Revenues | |||
Other operating revenues | 0.3 | 0.3 | 0.1 |
Alternative revenues | |||
Disaggregation of Operating Revenues | |||
Other operating revenues | $ (0.7) | $ (0.9) | $ 1.4 |
CREDIT LOSSES - GROSS RECEIVABL
CREDIT LOSSES - GROSS RECEIVABLES AND RELATED ALLOWANCES (Details) - Utility - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 |
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable and unbilled revenues | $ 230.1 | $ 279.5 | ||
Allowance for credit losses | 10.9 | 11.7 | $ 11.1 | $ 18.3 |
Accounts receivable and unbilled revenues, net | 219.2 | 267.8 | ||
Total accounts receivable, net - past due greater than 90 days | $ 8.3 | $ 8.4 | ||
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms | 93.40% | 95.50% | ||
Amount of net accounts receivable with regulatory protections | $ 124 | |||
Percent of net accounts receivable with regulatory protections | 56.60% |
CREDIT LOSSES - ROLLFORWARD OF
CREDIT LOSSES - ROLLFORWARD OF ALLOWANCES (Details) - Utility - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | |||
Balance at January 1 | $ 11.7 | $ 11.1 | $ 18.3 |
Provision for credit losses | 5.6 | 8.4 | 6.2 |
Write-offs charged against the allowance | (14.9) | (12.8) | (10) |
Recoveries of amounts previously written off | 5.2 | 4.9 | 3.6 |
Balance at December 31 | 10.9 | 11.7 | 11.1 |
Uncollectible expense | |||
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | |||
Provision for credit losses deferred for future recovery or refund | $ 3.3 | $ 0.1 | $ (7) |
REGULATORY ASSETS AND LIABILI_3
REGULATORY ASSETS AND LIABILITIES - REGULATORY ASSETS (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Regulatory assets | ||
Regulatory assets | $ 360.6 | $ 365.5 |
Allowance for return on equity capitalized for regulatory purposes | 7.7 | 9.6 |
Regulatory assets not earning a return | 36.2 | |
Estimated future cash expenditures for environmental remediation | 85.3 | 88.6 |
Environmental remediation costs | ||
Regulatory assets | ||
Regulatory assets | 121.5 | 118.5 |
Cash expenditures for environmental remediation costs | 36.2 | |
Estimated future cash expenditures for environmental remediation | 85.3 | |
Pension and OPEB costs | ||
Regulatory assets | ||
Regulatory assets | 62 | 48.6 |
Income tax related items | ||
Regulatory assets | ||
Regulatory assets | 57.2 | 61.5 |
Plant retirement related items | ||
Regulatory assets | ||
Regulatory assets | 38.4 | 43.1 |
Asset retirement obligations (AROs) | ||
Regulatory assets | ||
Regulatory assets | 18.8 | 15.6 |
Derivatives | ||
Regulatory assets | ||
Regulatory assets | 12.5 | 22.5 |
Bluewater | ||
Regulatory assets | ||
Regulatory assets | 11.9 | 6.8 |
ReACT | ||
Regulatory assets | ||
Regulatory assets | 10.4 | 13 |
Uncollectible expense | ||
Regulatory assets | ||
Regulatory assets | 8.9 | 5.6 |
Energy efficiency programs | ||
Regulatory assets | ||
Regulatory assets | 5.5 | 13.4 |
Other, net | ||
Regulatory assets | ||
Regulatory assets | $ 13.5 | $ 16.9 |
REGULATORY ASSETS AND LIABILI_4
REGULATORY ASSETS AND LIABILITIES - REGULATORY LIABILITIES (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Regulatory liabilities | ||
Other current liabilities | $ 8.5 | $ 9.9 |
Regulatory liabilities | 672 | 650.3 |
Total regulatory liabilities | 680.5 | 660.2 |
Income tax related items | ||
Regulatory liabilities | ||
Total regulatory liabilities | 331.4 | 343.7 |
Removal costs | ||
Regulatory liabilities | ||
Total regulatory liabilities | 191.2 | 186.5 |
Pension and OPEB benefits | ||
Regulatory liabilities | ||
Total regulatory liabilities | 85.3 | 90.1 |
Energy costs refundable through rate adjustments | ||
Regulatory liabilities | ||
Total regulatory liabilities | 36.3 | 9.9 |
Derivatives | ||
Regulatory liabilities | ||
Total regulatory liabilities | 4.1 | 7.9 |
Other, net | ||
Regulatory liabilities | ||
Total regulatory liabilities | $ 32.2 | $ 22.1 |
REGULATORY ASSETS AND LIABILI_5
REGULATORY ASSETS AND LIABILITIES - PLANT RETIREMENTS (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Regulatory assets | ||
Regulatory assets | $ 360.6 | $ 365.5 |
Edgewater Unit 4 | ||
Regulatory assets | ||
Regulatory assets | 2.1 | |
Pulliam power plant | ||
Regulatory assets | ||
Regulatory assets | $ 33 |
PROPERTY, PLANT, AND EQUIPMEN_2
PROPERTY, PLANT, AND EQUIPMENT - Balances (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Property, plant, and equipment | ||
Accumulated depreciation | $ 2,033.4 | $ 1,820.6 |
Net property, plant, and equipment | 5,801.4 | 5,376.7 |
Regulated operations | ||
Property, plant, and equipment | ||
Accumulated depreciation | 1,857.8 | 1,662.6 |
Net | 5,628.9 | 5,209.5 |
CWIP | 172.5 | 167.2 |
Net property, plant, and equipment | 5,801.4 | 5,376.7 |
Electric - generation | Regulated operations | ||
Property, plant, and equipment | ||
Property, plant, and equipment | 3,108.8 | 2,736.5 |
Electric - distribution | Regulated operations | ||
Property, plant, and equipment | ||
Property, plant, and equipment | 2,338.5 | 2,184.9 |
Natural gas - distribution, storage, and transmission | Regulated operations | ||
Property, plant, and equipment | ||
Property, plant, and equipment | 1,266.3 | 1,184.5 |
Property, plant, and equipment to be retired, net | Regulated operations | ||
Property, plant, and equipment | ||
Property, plant, and equipment to be retired, net | 259.8 | 273.1 |
Other | Regulated operations | ||
Property, plant, and equipment | ||
Property, plant, and equipment | 513.3 | $ 493.1 |
Columbia Energy Center Units 1 and 2 | ||
Property, plant, and equipment | ||
Net book value of plant to be retired | $ 259.8 |
PROPERTY, PLANT, AND EQUIPMEN_3
PROPERTY, PLANT, AND EQUIPMENT - Severance Liability (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Property, Plant and Equipment [Abstract] | |||
Severance liability at January 1 | $ 2.7 | $ 1.6 | $ 0 |
Severance expense | 0 | 1.1 | 1.6 |
Severance liability at December 31 | $ 2.7 | $ 2.7 | $ 1.6 |
JOINTLY OWNED UTILITY FACILIT_3
JOINTLY OWNED UTILITY FACILITIES (Details) $ in Millions | Dec. 31, 2023 USD ($) MW |
Weston Unit 4 | |
Jointly owned utility facilities | |
Joint plant ownership percentage | 70% |
Share of capacity (MW) | MW | 384.8 |
Property, plant, and equipment | $ 613.3 |
Accumulated depreciation | (227.3) |
Construction work in progress | $ 0.5 |
Columbia Energy Center Units 1 and 2 | |
Jointly owned utility facilities | |
Joint plant ownership percentage | 27.50% |
Share of capacity (MW) | MW | 312.3 |
Property, plant, and equipment | $ 433.1 |
Accumulated depreciation | (173.8) |
Construction work in progress | $ 3.5 |
Forward Wind | |
Jointly owned utility facilities | |
Joint plant ownership percentage | 44.60% |
Share of capacity (MW) | MW | 61.5 |
Property, plant, and equipment | $ 119.3 |
Accumulated depreciation | (56.8) |
Construction work in progress | $ 0 |
Two Creeks | |
Jointly owned utility facilities | |
Joint plant ownership percentage | 66.70% |
Share of capacity (MW) | MW | 100 |
Property, plant, and equipment | $ 136.9 |
Accumulated depreciation | (14.1) |
Construction work in progress | $ 0 |
Badger Hollow I | |
Jointly owned utility facilities | |
Joint plant ownership percentage | 66.70% |
Share of capacity (MW) | MW | 100 |
Property, plant, and equipment | $ 146.2 |
Accumulated depreciation | (9.7) |
Construction work in progress | $ 0.1 |
Red Barn | |
Jointly owned utility facilities | |
Joint plant ownership percentage | 90% |
Share of capacity (MW) | MW | 82.4 |
Property, plant, and equipment | $ 150 |
Accumulated depreciation | (3.2) |
Construction work in progress | $ 0 |
Weston RICE units | |
Jointly owned utility facilities | |
Joint plant ownership percentage | 50% |
Share of capacity (MW) | MW | 65 |
Property, plant, and equipment | $ 91.7 |
Accumulated depreciation | (1.2) |
Construction work in progress | $ 0 |
Whitewater | |
Jointly owned utility facilities | |
Joint plant ownership percentage | 50% |
Share of capacity (MW) | MW | 121.4 |
Property, plant, and equipment | $ 125.7 |
Accumulated depreciation | (93.6) |
Construction work in progress | $ 0.4 |
Koshkonong | |
Jointly owned utility facilities | |
Joint plant ownership percentage | 15% |
Jointly owned utility plant, proportionate ownership share of solar capacity | MW | 45 |
Paris | |
Jointly owned utility facilities | |
Joint plant ownership percentage | 15% |
Construction work in progress | $ 55.2 |
Jointly owned utility plant, proportionate ownership share of solar capacity | MW | 30 |
Jointly owned utility plant, proportionate ownership share of battery storage | MW | 17 |
Darien | |
Jointly owned utility facilities | |
Joint plant ownership percentage | 15% |
Construction work in progress | $ 36.6 |
Jointly owned utility plant, proportionate ownership share of solar capacity | MW | 37 |
ASSET RETIREMENT OBLIGATIONS (D
ASSET RETIREMENT OBLIGATIONS (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Changes to asset retirement obligations | |||
Balance as of January 1 | $ 55.1 | $ 55.8 | $ 45.5 |
Accretion | 2.1 | 2 | 1.8 |
Additions | 2.2 | 0.7 | 10.7 |
Revisions to estimated cash flows | 1.6 | 1.4 | (2.1) |
Liabilities settled | (4.3) | (4.8) | (0.1) |
Balance as of December 31 | $ 56.7 | $ 55.1 | $ 55.8 |
GOODWILL AND INTANGIBLE - GOODW
GOODWILL AND INTANGIBLE - GOODWILL (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |
Sep. 30, 2023 | Dec. 31, 2023 | Dec. 31, 2022 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |||
Changes to the carrying amount of goodwill | $ 0 | $ 0 | |
Accumulated impairment loss | $ 0 | ||
Goodwill impairment loss | $ 0 |
GOODWILL AND INTANGIBLES - INDE
GOODWILL AND INTANGIBLES - INDEFINITE LIVED INTANGIBLE ASSETS (Details) - Spectrum frequencies - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Indefinite-Lived Intangible Assets | ||
Indefinite-lived intangible assets | $ 5.3 | $ 3.8 |
Changes to the carrying amount of indefinite-lived assets | $ 1.5 |
COMMON EQUITY - STOCK-BASED COM
COMMON EQUITY - STOCK-BASED COMPENSATION EXPENSE (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Share Based Compensation Arrangement By Share Based Payment Award | |||
Stock-based compensation expense | $ 1.7 | $ 6.2 | $ 2.5 |
Related tax benefit | 0.5 | 1.7 | 0.7 |
Stock options | |||
Share Based Compensation Arrangement By Share Based Payment Award | |||
Stock-based compensation expense | 1 | 1.1 | 1.1 |
Restricted stock | |||
Share Based Compensation Arrangement By Share Based Payment Award | |||
Stock-based compensation expense | 1.1 | 1.2 | 1 |
Performance units | |||
Share Based Compensation Arrangement By Share Based Payment Award | |||
Stock-based compensation expense | $ (0.4) | $ 3.9 | $ 0.4 |
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, 2024 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Options Activity | ||||
Outstanding, shares, beginning balance | 75,277 | 62,168 | ||
Granted, shares | 10,655 | 16,079 | 18,021 | |
Transferred, shares | 2,454 | |||
Outstanding, shares, ending balance | 75,277 | 62,168 | ||
Options - Weighted Average Exercise Price | ||||
Outstanding, Weighted-Average Exercise Price, Beginning | $ 87.58 | $ 87 | ||
Granted, Weighted-Average Exercise Price | 93.69 | |||
Transferred, Weighted-Average Exercise Price | 75.82 | |||
Outstanding, Weighted-Average Exercise Price, Ending | $ 87.58 | $ 87 | ||
Options - Additional Disclosures | ||||
Outstanding, Weighted-Average Remaining Contractual Life (Years) | 6 years 9 months 18 days | |||
Outstanding, Aggregate Intrinsic Value | $ 0.3 | |||
Exercisable, shares | 31,857 | |||
Exercisable, Weighted-Average Exercise Price | $ 79.59 | |||
Exercisable, Weighted-Average Remaining Contractual Life (Years) | 5 years 3 months 18 days | |||
Exercisable, Aggregate Intrinsic Value | $ 0.3 | |||
Exercised, shares | 0 | |||
Intrinsic value of options exercised | $ 0.9 | $ 0.3 | ||
Tax benefit from option exercises | $ 0.2 | $ 0.1 | ||
Compensation cost not yet recognized | $ 0.3 | |||
Weighted-average period over which unrecognized compensation cost is expected to be recognized | 1 year 7 months 6 days | |||
Estimated weighted-average fair value per stock option (in dollars per share) | $ 19.58 | $ 14.71 | $ 13.20 | |
Subsequent event | ||||
Options Activity | ||||
Granted, shares | 11,878 | |||
Options - Weighted Average Exercise Price | ||||
Granted, Weighted-Average Exercise Price | $ 85.05 | |||
Options - Additional Disclosures | ||||
Estimated weighted-average fair value per stock option (in dollars per share) | $ 16.20 | |||
WEC Energy Group | ||||
Options - Additional Disclosures | ||||
Cash received by WEC Energy Group from options exercised by WPS employees | $ 2.4 | $ 0.6 |
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, 2024 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Restricted Stock Activity | ||||
Outstanding, shares, beginning of period | 2,985 | 2,557 | ||
Granted, shares | 1,587 | |||
Released, shares | (1,233) | |||
Transferred, shares | 74 | |||
Outstanding, shares, end of period | 2,985 | 2,557 | ||
Restricted Stock Weighted-Average Grant Date Fair Value | ||||
Outstanding, weighted-average grant date fair value, beginning of period | $ 94.07 | $ 93.84 | ||
Granted, weighted-average grant date fair value | 93.69 | |||
Released, weighted-average grant date fair value | 93.07 | |||
Transferred, Weighted-Average Exercise Price | 93.68 | |||
Outstanding, weighted-average grant date fair value, end of period | $ 94.07 | $ 93.84 | ||
Restricted Stock - Additional Disclosures | ||||
Intrinsic value of released restricted shares | $ 0.1 | $ 0.1 | $ 0.1 | |
Compensation cost not yet recognized | $ 0.5 | |||
Weighted-average period over which unrecognized compensation cost is expected to be recognized | 1 year 8 months 12 days | |||
Subsequent event | ||||
Restricted Stock Activity | ||||
Granted, shares | 2,783 | |||
Restricted Stock Weighted-Average Grant Date Fair Value | ||||
Granted, weighted-average grant date fair value | $ 85.05 |
COMMON EQUITY - PERFORMANCE UNI
COMMON EQUITY - PERFORMANCE UNITS (Details) - Performance units - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2024 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Share-based Compensation Arrangement by Share-based Payment Award | ||||
Performance units granted | 6,905 | 6,608 | 5,437 | |
Intrinsic value of settled performance units | $ 0.4 | $ 0.7 | $ 1.2 | |
Tax benefit from distribution of performance units | $ 0.1 | $ 0.2 | $ 0.2 | |
Performance units outstanding | 19,718 | |||
Liability recorded on balance sheet | $ 0.5 | |||
Compensation cost not yet recognized | $ 2.3 | |||
Weighted-average period over which unrecognized compensation cost is expected to be recognized | 1 year 10 months 24 days | |||
Subsequent event | ||||
Share-based Compensation Arrangement by Share-based Payment Award | ||||
Performance units granted | 9,061 | |||
Intrinsic value of settled performance units | $ 0.1 |
COMMON EQUITY - DIVIDEND RESTRI
COMMON EQUITY - DIVIDEND RESTRICTIONS (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2023 USD ($) | |
Dividend Payment Restrictions | |
Restricted retained earnings | $ 647 |
Public Service Commission of Wisconsin | Minimum | |
Dividend Payment Restrictions | |
Common equity ratio required to be maintained (as a percent) | 53% |
PREFERRED STOCK (Details)
PREFERRED STOCK (Details) - $ / shares | Dec. 31, 2023 | Dec. 31, 2022 |
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | ||
Authorized shares | 1,000,000 | 1,000,000 |
Par value (in dollars per share) | $ 100 | $ 100 |
Shares outstanding | 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, 2023 | Dec. 31, 2022 | |
Short-term borrowings | ||
Debt to capitalization ratio | 65% | |
Commercial paper | ||
Short-term borrowings | ||
Short-term borrowings outstanding | $ 310.3 | $ 194.9 |
Average interest rate on amounts outstanding (as a percent) | 5.41% | 4.60% |
Average amount of short-term borrowings outstanding during the year | $ 151.4 | |
Weighted average interest rate during the year | 5.17% |
SHORT-TERM DEBT AND LINES OF _4
SHORT-TERM DEBT AND LINES OF CREDIT - CREDIT FACILITIES (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 USD ($) extension | Dec. 31, 2022 USD ($) | |
Short-term borrowings | ||
Available capacity under existing agreements | $ 88.4 | |
Number of extensions available on a credit facility | extension | 2 | |
Length of credit facility extension | 1 year | |
Letters of credit | ||
Short-term borrowings | ||
Letters of credit issued inside credit facility | $ 1.3 | |
Commercial paper | ||
Short-term borrowings | ||
Short-term borrowings outstanding | 310.3 | $ 194.9 |
Credit facility maturing September 2026 | ||
Short-term borrowings | ||
Total short-term credit capacity | $ 400 |
LONG-TERM DEBT (Details)
LONG-TERM DEBT (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Long-term debt | ||
Total | $ 1,975 | $ 1,975 |
Unamortized debt issuance costs | (14.5) | (15.5) |
Unamortized discount, net | (1.4) | (1.5) |
Long-term debt | 1,959.1 | 1,958 |
Finance lease obligations | 49 | 41.9 |
Future maturities of long-term debt | ||
2024 | 0 | |
2025 | 300 | |
2026 | 0 | |
2027 | 0 | |
2028 | 50 | |
Thereafter | 1,625 | |
Total | $ 1,975 | 1,975 |
5.35% WPS Senior Notes due November 10, 2025 | ||
Long-term debt | ||
Interest rate | 5.35% | |
Senior notes (unsecured) | $ 300 | 300 |
Senior Notes (unsecured), 6.08% due 2028 | ||
Long-term debt | ||
Interest rate | 6.08% | |
Senior notes (unsecured) | $ 50 | 50 |
Senior Notes (unsecured), 5.55% due 2036 | ||
Long-term debt | ||
Interest rate | 5.55% | |
Senior notes (unsecured) | $ 125 | 125 |
Senior Notes (unsecured), 3.671% due 2042 | ||
Long-term debt | ||
Interest rate | 3.671% | |
Senior notes (unsecured) | $ 300 | 300 |
Senior Notes (unsecured), 4.752% due 2044 | ||
Long-term debt | ||
Interest rate | 4.752% | |
Senior notes (unsecured) | $ 450 | 450 |
Senior Notes (unsecured), 3.30% due 2049 | ||
Long-term debt | ||
Interest rate | 3.30% | |
Senior notes (unsecured) | $ 300 | 300 |
Senior Notes (unsecured), 2.85% due 2051 | ||
Long-term debt | ||
Interest rate | 2.85% | |
Senior notes (unsecured) | $ 450 | $ 450 |
LEASES - LAND LEASES - UTILITY
LEASES - LAND LEASES - UTILITY SOLAR GENERATION (Details) - Land Lease - Utility Solar Generation | 12 Months Ended |
Dec. 31, 2023 renewal_terms | |
Lessee, Lease, Description [Line Items] | |
Minimum number of contract renewals | 1 |
Lease term | 50 years |
LEASES - OTHER INFORMATION (Det
LEASES - OTHER INFORMATION (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Other information | |||
Right-of-use assets obtained in exchange for finance lease liabilities | $ 6.6 | $ 10.2 | $ 2.6 |
Reduction of right-of-use asset and finance liability due to a remeasurement | $ 0 | $ 0 | $ (2.9) |
Weighted average remaining lease term | 48 years 4 months 24 days | 49 years | 49 years 7 months 6 days |
Weighted average discount rate | 4.30% | 3.90% | 3.30% |
LEASES - FINANCE LEASE RIGHT OF
LEASES - FINANCE LEASE RIGHT OF USE ASSETS AND OBLIGATIONS (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Leases [Abstract] | ||
Finance lease right of use assets, net | $ 43.8 | $ 38 |
Long-term lease liabilities | 49 | 41.9 |
Accumulated amortization | $ 3.1 | $ 2.2 |
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration] | Property, plant, and equipment, net of accumulated depreciation and amortization of $2,033.4 and $1,820.6, respectively | Property, plant, and equipment, net of accumulated depreciation and amortization of $2,033.4 and $1,820.6, respectively |
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration] | Long-term debt | Long-term debt |
LEASES - FUTURE MINIMUM LEASE P
LEASES - FUTURE MINIMUM LEASE PAYMENTS (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Leases [Abstract] | ||
2024 | $ 1.4 | |
2025 | 1.6 | |
2026 | 1.6 | |
2027 | 1.7 | |
2028 | 1.7 | |
Thereafter | 126.6 | |
Total minimum lease payments | 134.6 | |
Less: interest | (85.6) | |
Present value of minimum lease payments | 49 | $ 41.9 |
Less: short-term lease liabilities | 0 | |
Long-term lease liabilities | $ 49 | $ 41.9 |
INCOME TAXES - SUMMARY OF INCOM
INCOME TAXES - SUMMARY OF INCOME TAX EXPENSE (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Provision for income taxes | |||
Current tax expense (benefit) | $ 17.8 | $ 8.7 | $ (18.3) |
Deferred income taxes, net | 48.7 | 66.3 | 51.1 |
ITCs | (3.8) | (2.8) | (1.6) |
Total income tax expense | $ 62.7 | $ 72.2 | $ 31.2 |
INCOME TAXES - STATUTORY RATE R
INCOME TAXES - STATUTORY RATE RECONCILIATION (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Jan. 01, 2020 | |
Reconciliation of federal income taxes to the provision for income taxes reported in the income statement | ||||
Statutory federal income tax | $ 67.8 | $ 64.5 | $ 55.1 | |
State income taxes net of federal tax benefit | 20.2 | 19.5 | 16.3 | |
PTCs, net | (14.4) | (0.6) | 0 | |
Federal Excess deferred tax amortization | (5.7) | (5.2) | (5.2) | |
Federal excess deferred tax amortization - Wisconsin unprotected | (3.8) | (3.8) | (33) | |
ITCs | (3.8) | (2.8) | (1.6) | |
Other, net | 2.4 | 0.6 | (0.4) | |
Total income tax expense | $ 62.7 | $ 72.2 | $ 31.2 | |
Reconciliation of federal income taxes to the provision for income taxes reported in the income statement (as a percent) | ||||
Statutory federal income tax | 21% | 21% | 21% | |
State income taxes net of federal tax benefit | 6.30% | 6.30% | 6.20% | |
PTCs, net | (4.50%) | (0.20%) | 0% | |
Federal excess deferred tax amortization | (1.80%) | (1.70%) | (2.00%) | |
Federal excess deferred tax amortization - Wisconsin unprotected | (1.20%) | (1.20%) | (12.60%) | |
ITCs | (1.20%) | (0.90%) | (0.60%) | |
Other, net | 0.80% | 0.20% | (0.10%) | |
Total income tax expense | 19.40% | 23.50% | 11.90% | |
2018 and 2019 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 | $ 0 | $ 0 | |
2020 and 2021 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 | $ 0 | $ 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 | |||
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 |
INCOME TAXES - COMPONENTS OF DE
INCOME TAXES - COMPONENTS OF DEFERRED INCOME TAXES (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Deferred tax assets | ||
Tax gross up - regulatory items | $ 94.8 | $ 99.9 |
Future tax benefits | 8.8 | 3.5 |
Other | 21.3 | 23.3 |
Total deferred tax assets | 124.9 | 126.7 |
Deferred income tax liabilities | ||
Property-related | 935.7 | 878.3 |
Employee benefits and compensation | 66.7 | 62.2 |
Other | 46.9 | 46.9 |
Total deferred tax liabilities | 1,049.3 | 987.4 |
Deferred tax liability, net | $ 924.4 | $ 860.7 |
INCOME TAXES - SUMMARY OF OPERA
INCOME TAXES - SUMMARY OF OPERATING LOSS CARRYFORWARDS (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Income taxes | ||
Balance of future tax benefits | $ 0 | $ 0 |
Future tax benefits | 8.8 | 3.5 |
Federal Tax Jurisdiction | ||
Income taxes | ||
Federal tax credit carryforwards | 0 | 0 |
Federal tax credit carryforwards, deferred tax effect | $ 8.8 | $ 3.5 |
INCOME TAXES - UNRECOGNIZED TAX
INCOME TAXES - UNRECOGNIZED TAX BENEFITS (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Income Tax Disclosure [Abstract] | |||
Unrecognized tax benefits | $ 0 | $ 0 | |
Interest expense in the income statements | 0 | 0 | $ 0 |
Penalties in the income statements | 0 | 0 | $ 0 |
Accrued interest on the balance sheets | 0 | 0 | |
Accrued penalties on the 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, 2023 | Dec. 31, 2022 |
Assets | ||
Derivative assets | $ 4.2 | $ 7.6 |
Liabilities | ||
Derivative liabilities | 8.9 | 16.9 |
Fair value measurements on a recurring basis | ||
Assets | ||
Derivative assets | 4.2 | 7.6 |
Liabilities | ||
Derivative liabilities | 8.9 | |
Fair value measurements on a recurring basis | Level 1 | ||
Assets | ||
Derivative assets | 0.6 | 1.2 |
Liabilities | ||
Derivative liabilities | 7.4 | |
Fair value measurements on a recurring basis | Level 2 | ||
Assets | ||
Derivative assets | 1.6 | 2.3 |
Liabilities | ||
Derivative liabilities | 1.5 | |
Fair value measurements on a recurring basis | Level 3 | ||
Assets | ||
Derivative assets | 2 | 4.1 |
Liabilities | ||
Derivative liabilities | 0 | |
Fair value measurements on a recurring basis | Natural gas contracts | ||
Assets | ||
Derivative assets | 1.9 | 1.7 |
Liabilities | ||
Derivative liabilities | 7.9 | 16.9 |
Fair value measurements on a recurring basis | Natural gas contracts | Level 1 | ||
Assets | ||
Derivative assets | 0.6 | 1.2 |
Liabilities | ||
Derivative liabilities | 7.4 | 14.5 |
Fair value measurements on a recurring basis | Natural gas contracts | Level 2 | ||
Assets | ||
Derivative assets | 1.3 | 0.5 |
Liabilities | ||
Derivative liabilities | 0.5 | 2.4 |
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 | 2 | 4.1 |
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 | 2 | 4.1 |
Fair value measurements on a recurring basis | Coal contracts | ||
Assets | ||
Derivative assets | 0.3 | 1.8 |
Liabilities | ||
Derivative liabilities | 1 | |
Fair value measurements on a recurring basis | Coal contracts | Level 1 | ||
Assets | ||
Derivative assets | 0 | 0 |
Liabilities | ||
Derivative liabilities | 0 | |
Fair value measurements on a recurring basis | Coal contracts | Level 2 | ||
Assets | ||
Derivative assets | 0.3 | 1.8 |
Liabilities | ||
Derivative liabilities | 1 | |
Fair value measurements on a recurring basis | Coal contracts | Level 3 | ||
Assets | ||
Derivative assets | 0 | $ 0 |
Liabilities | ||
Derivative liabilities | $ 0 |
FAIR VALUE MEASUREMENTS - LEVEL
FAIR VALUE MEASUREMENTS - LEVEL 3 RECONCILIATION (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Level 3 rollforward | |||
Balance at the beginning of the period | $ 4.1 | $ 1.4 | $ 1.2 |
Purchases | 6.3 | 11.7 | 3.1 |
Settlements | (8.4) | (9) | (2.9) |
Balance at the end of the period | $ 2 | $ 4.1 | $ 1.4 |
FAIR VALUE MEASUREMENTS - FINAN
FAIR VALUE MEASUREMENTS - FINANCIAL INSTRUMENTS (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Financial instruments | ||
Finance lease obligations | $ 49 | $ 41.9 |
Carrying amount | ||
Financial instruments | ||
Long-term debt | 1,959.1 | 1,958 |
Finance lease obligations | 49 | 41.9 |
Fair value | ||
Financial instruments | ||
Long-term debt | $ 1,662.8 | $ 1,607.2 |
DERIVATIVE INSTRUMENTS - DERIVA
DERIVATIVE INSTRUMENTS - DERIVATIVE ASSETS AND LIABILITIES (Details) $ in Millions | Dec. 31, 2023 USD ($) Instruments | Dec. 31, 2022 USD ($) Instruments |
Derivative assets | ||
Current derivative assets | $ 4.2 | $ 7.2 |
Long-term derivative assets | 0 | 0.4 |
Total derivative assets | $ 4.2 | $ 7.6 |
Current derivative assets balance sheet location | Other | Other |
Long-term derivative assets balance sheet location | Other | Other |
Derivative liabilities | ||
Current derivative liabilities | $ 8.1 | $ 16.3 |
Long-term derivative liabilities | 0.8 | 0.6 |
Total derivative liabilities | $ 8.9 | $ 16.9 |
Current derivative liabilities balance sheet location | Other | Other |
Long-term derivative liabilities balance sheet location | Other | Other |
Natural gas contracts | ||
Derivative assets | ||
Current derivative assets | $ 1.9 | $ 1.7 |
Long-term derivative assets | 0 | 0 |
Derivative liabilities | ||
Current derivative liabilities | 7.4 | 16.3 |
Long-term derivative liabilities | 0.5 | 0.6 |
FTRs | ||
Derivative assets | ||
Current derivative assets | 2 | 4.1 |
Derivative liabilities | ||
Current derivative liabilities | 0 | 0 |
Coal contracts | ||
Derivative assets | ||
Current derivative assets | 0.3 | 1.4 |
Long-term derivative assets | 0 | 0.4 |
Derivative liabilities | ||
Current derivative liabilities | 0.7 | 0 |
Long-term derivative liabilities | $ 0.3 | $ 0 |
Derivatives designated as hedging instruments | ||
Derivative instruments | ||
Number of derivative instruments | Instruments | 0 | 0 |
DERIVATIVE INSTRUMENTS - GAINS
DERIVATIVE INSTRUMENTS - GAINS (LOSSES) AND NOTIONAL VOLUMES (Details) MWh in Millions, MMBTU in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 USD ($) MWh MMBTU | Dec. 31, 2022 USD ($) MMBTU MWh | Dec. 31, 2021 USD ($) MMBTU MWh | |
Realized gains (losses) on derivatives | |||
Gains (losses) | $ (41.8) | $ 45.6 | $ 30.5 |
Realized gains and losses on derivatives income statement location | Cost of sales | Cost of sales | Cost of sales |
Natural gas contracts | |||
Realized gains (losses) on derivatives | |||
Gains (losses) | $ (52) | $ 43.1 | $ 21.8 |
Notional sales volumes | |||
Notional sales volumes | MMBTU | 40.6 | 33.4 | 37.5 |
FTRs | |||
Realized gains (losses) on derivatives | |||
Gains (losses) | $ 10.2 | $ 2.5 | $ 8.7 |
Notional sales volumes | |||
Notional sales volumes | MWh | 8.3 | 7.8 | 7 |
DERIVATIVE INSTRUMENTS - BALANC
DERIVATIVE INSTRUMENTS - BALANCE SHEET OFFSETTING (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Cash collateral | ||
Cash collateral posted | $ 15.9 | $ 26.6 |
Offsetting derivative assets | ||
Gross amount recognized on the balance sheet | 4.2 | 7.6 |
Gross amount not offset on the balance sheet | (0.6) | (1.4) |
Net amount | 3.6 | 6.2 |
Offsetting derivative liabilities | ||
Gross amount recognized on the balance sheet | 8.9 | 16.9 |
Gross amount not offset on the balance sheet | (7.5) | (14.8) |
Net amount | 1.4 | 2.1 |
Cash collateral posted | $ 6.9 | $ 13.4 |
EMPLOYEE BENEFITS - CHANGE IN B
EMPLOYEE BENEFITS - CHANGE IN BENEFIT OBLIGATION AND PLAN ASSETS (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Pension Benefits | |||
Change in benefit obligation | |||
Obligation at January 1 | $ 560.7 | $ 773.1 | |
Service cost | 4.8 | 9 | $ 10.6 |
Interest cost | 30.1 | 22.7 | 21.9 |
Net transfer from affiliates | 0 | 0 | |
Actuarial loss (gain) | 25.3 | (204.9) | |
Participant contributions | 0 | 0 | |
Benefit payments | (34.2) | (39.2) | |
Obligation at December 31 | 586.7 | 560.7 | 773.1 |
Change in fair value of plan assets | |||
Beginning balance at January 1 | 685.1 | 859.4 | |
Actual return on plan assets | 62.2 | (135.7) | |
Employer contributions | 0.6 | 0.6 | |
Participant contributions | 0 | 0 | |
Benefit payments | (34.2) | (39.2) | |
Ending balance at December 31 | 713.7 | 685.1 | 859.4 |
Funded status at December 31 | 127 | 124.4 | |
OPEB Benefits | |||
Change in benefit obligation | |||
Obligation at January 1 | 112.2 | 146.9 | |
Service cost | 2.8 | 4 | 4.3 |
Interest cost | 6.1 | 4.4 | 4.2 |
Net transfer from affiliates | 0 | 0.3 | |
Actuarial loss (gain) | 16.7 | (36.2) | |
Participant contributions | 0.8 | 0.6 | |
Benefit payments | (9.9) | (7.8) | |
Obligation at December 31 | 128.7 | 112.2 | 146.9 |
Change in fair value of plan assets | |||
Beginning balance at January 1 | 255.6 | 303.6 | |
Actual return on plan assets | 24.5 | (41.7) | |
Employer contributions | 0.9 | 0.9 | |
Participant contributions | 0.8 | 0.6 | |
Benefit payments | (9.9) | (7.8) | |
Ending balance at December 31 | 271.9 | 255.6 | $ 303.6 |
Funded status at December 31 | $ 143.2 | $ 143.4 |
EMPLOYEE BENEFITS - AMOUNTS REC
EMPLOYEE BENEFITS - AMOUNTS RECOGNIZED ON THE BALANCE SHEETS (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Defined Benefit Plan Disclosure [Line Items] | ||
Pension and OPEB assets | $ 284.5 | $ 282.1 |
Pension Benefits | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Pension and OPEB assets | 131.6 | 129.5 |
Other long-term liabilities | 4.6 | 5.1 |
Total net assets | 127 | 124.4 |
OPEB Benefits | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Pension and OPEB assets | 152.9 | 152.6 |
Other long-term liabilities | 9.7 | 9.2 |
Total net assets | $ 143.2 | $ 143.4 |
EMPLOYEE BENEFITS - ACCUMULATED
EMPLOYEE BENEFITS - ACCUMULATED BENEFIT OBLIGATIONS (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Pension Plan | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Accumulated benefit obligation | $ 548.1 | $ 525.9 |
Information for pension and OPEB plans with an accumulated benefit obligation in excess of plan assets | ||
Accumulated benefit obligation | 4.7 | 5.1 |
Fair value of plan assets | 0 | 0 |
Information for pension plans with a projected benefit obligation in excess of plan assets | ||
Projected benefit obligation | 4.7 | 5.1 |
Fair value of plan assets | 0 | 0 |
OPEB Benefits | ||
Information for pension and OPEB plans with an accumulated benefit obligation in excess of plan assets | ||
Accumulated benefit obligation | 14.5 | 14.4 |
Fair value of plan assets | $ 4.8 | $ 5.3 |
EMPLOYEE BENEFITS - AMOUNTS NOT
EMPLOYEE BENEFITS - AMOUNTS NOT YET RECOGNIZED IN NET PERIODIC BENEFIT COST (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Pension Benefits | ||
Net regulatory assets (liabilities) | ||
Net actuarial loss (gain) | $ 53.2 | $ 56.1 |
Prior service credits | 0 | 0 |
Total | 53.2 | 56.1 |
OPEB Benefits | ||
Net regulatory assets (liabilities) | ||
Net actuarial loss (gain) | (28.1) | (35.6) |
Prior service credits | (21) | (31.2) |
Total | $ (49.1) | $ (66.8) |
EMPLOYEE BENEFITS - NET PERIODI
EMPLOYEE BENEFITS - NET PERIODIC BENEFIT COST (CREDIT) (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Components of net periodic benefit cost (credit) (including amounts capitalized to the balance sheets) | |||
Regulatory assets | $ 360.6 | $ 365.5 | |
Pension Benefits | |||
Components of net periodic benefit cost (credit) (including amounts capitalized to the balance sheets) | |||
Service cost | 4.8 | 9 | $ 10.6 |
Interest cost | 30.1 | 22.7 | 21.9 |
Expected return on plan assets | (51.3) | (55.2) | (51.8) |
Plan curtailment | 0 | 0 | 0 |
Amortization of prior service credit | 0 | 0 | 0 |
Amortization of net actuarial loss (gain) | 17.3 | 17.3 | 26.6 |
Net periodic benefit cost (credit) | 0.9 | (6.2) | 7.3 |
Pension Benefits | Pension and Other Postretirement Plans Cost | |||
Components of net periodic benefit cost (credit) (including amounts capitalized to the balance sheets) | |||
Regulatory assets | 6.7 | ||
OPEB Benefits | |||
Components of net periodic benefit cost (credit) (including amounts capitalized to the balance sheets) | |||
Service cost | 2.8 | 4 | 4.3 |
Interest cost | 6.1 | 4.4 | 4.2 |
Expected return on plan assets | (16.3) | (21) | (20.4) |
Plan curtailment | 0 | 0 | (6.4) |
Amortization of prior service credit | (10.2) | (10.2) | (10.3) |
Amortization of net actuarial loss (gain) | 1 | (2.5) | (3.7) |
Net periodic benefit cost (credit) | (16.6) | $ (25.3) | $ (32.3) |
OPEB Benefits | Pension and Other Postretirement Plans Cost | |||
Components of net periodic benefit cost (credit) (including amounts capitalized to the balance sheets) | |||
Regulatory assets | $ 6.8 |
EMPLOYEE BENEFITS - ASSUMPTIONS
EMPLOYEE BENEFITS - ASSUMPTIONS (Details) | 12 Months Ended | |||
Dec. 31, 2024 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Pension Benefits | Benefit obligation assumptions | ||||
Weighted average assumptions - benefit obligations | ||||
Discount rate | 5.15% | 5.50% | 3% | |
Rate of compensation increase | 4% | 4% | ||
Interest credit rate | 4.50% | 4% | ||
Pension Benefits | Net periodic benefit cost assumptions | ||||
Weighted average assumptions - net periodic benefit cost | ||||
Discount rate | 5.50% | 3% | 2.74% | |
Expected return on plan assets | 6.75% | 7% | 7% | |
Rate of compensation increase | 4% | 4% | 4% | |
Interest credit rate | 4% | 2.25% | 2.25% | |
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 | 5.16% | 5.50% | 2.98% | |
OPEB Benefits | Benefit obligation assumptions | Pre 65 | ||||
Medical cost trend rates | ||||
Assumed medical cost trend rate | 6.25% | 6.50% | ||
Ultimate trend rate | 5% | 5% | ||
Year ultimate trend rate is reached | 2031 | 2031 | ||
OPEB Benefits | Benefit obligation assumptions | Post 65 | ||||
Medical cost trend rates | ||||
Assumed medical cost trend rate | 6.25% | 6% | ||
Ultimate trend rate | 5% | 5% | ||
Year ultimate trend rate is reached | 2030 | 2031 | ||
OPEB Benefits | Net periodic benefit cost assumptions | ||||
Weighted average assumptions - net periodic benefit cost | ||||
Discount rate | 5.50% | 2.98% | 2.95% | |
Expected return on plan assets | 6.50% | 7% | 7% | |
OPEB Benefits | Net periodic benefit cost assumptions | Subsequent event | ||||
Weighted average assumptions - net periodic benefit cost | ||||
Expected return on plan assets | 6.50% | |||
OPEB Benefits | Net periodic benefit cost assumptions | Pre 65 | ||||
Medical cost trend rates | ||||
Assumed medical cost trend rate | 6.50% | 5.70% | 5.85% | |
Ultimate trend rate | 5% | 5% | 5% | |
Year ultimate trend rate is reached | 2031 | 2028 | 2028 | |
OPEB Benefits | Net periodic benefit cost assumptions | Post 65 | ||||
Medical cost trend rates | ||||
Assumed medical cost trend rate | 6% | 5.60% | 5.70% | |
Ultimate trend rate | 5% | 5% | 5% | |
Year ultimate trend rate is reached | 2031 | 2028 | 2028 |
EMPLOYEE BENEFITS - TARGET ASSE
EMPLOYEE BENEFITS - TARGET ASSET ALLOCATIONS (Details) | Dec. 31, 2023 |
Pension Plan | Equity securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 25% |
Pension Plan | Fixed income securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 55% |
Pension Plan | Private equity and real estate | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 20% |
OPEB Plan | Equity securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 45% |
OPEB Plan | Fixed income securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 45% |
OPEB Plan | Real estate investments | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 10% |
EMPLOYEE BENEFITS - PLAN ASSETS
EMPLOYEE BENEFITS - PLAN ASSETS (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 |
Pension Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | $ 713.7 | $ 685.1 | $ 859.4 |
Pension Plan | Level 1, 2, and 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 305.2 | 285.9 | |
Pension Plan | Level 1, 2, and 3 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 52 | 70.2 | |
Pension Plan | Level 1, 2, and 3 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 53.7 | 61.3 | |
Pension Plan | Level 1, 2, and 3 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 176.7 | 130.7 | |
Pension Plan | Level 1, 2, and 3 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 22.8 | 23.7 | |
Pension Plan | Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 105.7 | 131.5 | |
Pension Plan | Level 1 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 52 | 70.2 | |
Pension Plan | Level 1 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 53.7 | 61.3 | |
Pension Plan | Level 1 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Plan | Level 1 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Plan | Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 199.5 | 154.4 | |
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 | 176.7 | 130.7 | |
Pension Plan | Level 2 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 22.8 | 23.7 | |
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 | Equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 112.5 | 141.6 | |
Pension Plan | Investments measured at net asset value per share | Fixed income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 66.1 | 53 | |
Pension Plan | Investments measured at net asset value per share | Other investments | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 229.9 | 204.6 | |
OPEB Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 271.9 | 255.6 | $ 303.6 |
OPEB Plan | Level 1, 2, and 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 160.5 | 141.5 | |
OPEB Plan | Level 1, 2, and 3 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 32.6 | 28.4 | |
OPEB Plan | Level 1, 2, and 3 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 29.8 | 27.3 | |
OPEB Plan | Level 1, 2, and 3 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 95.2 | 82.8 | |
OPEB Plan | Level 1, 2, and 3 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 2.9 | 3 | |
OPEB Plan | Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 96.3 | 105.9 | |
OPEB Plan | Level 1 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 32.6 | 28.4 | |
OPEB Plan | Level 1 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 29.8 | 27.3 | |
OPEB Plan | Level 1 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 33.9 | 50.2 | |
OPEB Plan | Level 1 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
OPEB Plan | Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 64.2 | 35.6 | |
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 | 61.3 | 32.6 | |
OPEB Plan | Level 2 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 2.9 | 3 | |
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 | Equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 65.1 | 58.6 | |
OPEB Plan | Investments measured at net asset value per share | Fixed income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 17.1 | 24.7 | |
OPEB Plan | Investments measured at net asset value per share | Other investments | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | $ 29.2 | $ 30.8 |
EMPLOYEE BENEFITS - CASH FLOWS
EMPLOYEE BENEFITS - CASH FLOWS (Details) $ in Millions | Dec. 31, 2023 USD ($) |
Pension Benefits | |
Defined Benefit Plan Disclosure [Line Items] | |
Expected contributions to the plans during the next year | $ 0.6 |
2024 | 37.2 |
2025 | 37.1 |
2026 | 37.3 |
2027 | 37.6 |
2028 | 38 |
2029 through 2033 | 190.8 |
OPEB Benefits | |
Defined Benefit Plan Disclosure [Line Items] | |
Expected contributions to the plans during the next year | 0.9 |
2024 | 8.8 |
2025 | 9 |
2026 | 9.4 |
2027 | 9.7 |
2028 | 9.9 |
2029 through 2033 | $ 50.1 |
EMPLOYEE BENEFITS - DEFINED CON
EMPLOYEE BENEFITS - DEFINED CONTRIBUTION BENEFIT PLANS (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Retirement Benefits [Abstract] | |||
Total costs incurred for defined contribution benefit plans | $ 12.8 | $ 11.7 | $ 11 |
SEGMENTS INFORMATION (Details)
SEGMENTS INFORMATION (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 USD ($) numberOfSegments | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | |
Segment reporting information | |||
Number of reportable segments | numberOfSegments | 2 | ||
Operating revenues | $ 1,681.4 | $ 1,785.2 | $ 1,520.9 |
Other operation and maintenance | 434.3 | 362.5 | 406.4 |
Depreciation and amortization | 226.9 | 199.8 | 188.6 |
Other income, net | 45.9 | 42.3 | 38.2 |
Interest expense | 89 | 70.5 | 64.7 |
Income tax expense | 62.7 | 72.2 | 31.2 |
Net income | 260.2 | 235 | 231.1 |
Capital expenditures and asset acquisitions | 635.6 | 433.8 | 389.7 |
Total assets | 7,031.1 | 6,708.8 | 6,235.7 |
Utility | |||
Segment reporting information | |||
Operating revenues | 1,681.4 | 1,785.2 | 1,520.9 |
Other operation and maintenance | 434.3 | 362.5 | 406.4 |
Depreciation and amortization | 226.9 | 199.8 | 188.6 |
Other income, net | 43.8 | 41 | 36.8 |
Interest expense | 89 | 70.5 | 64.7 |
Income tax expense | 62.3 | 71.9 | 30.9 |
Net income | 258.5 | 234 | 230 |
Capital expenditures and asset acquisitions | 635.6 | 433.8 | 389.7 |
Total assets | 7,017.5 | 6,696 | 6,224.3 |
Other | |||
Segment reporting information | |||
Operating revenues | 0 | 0 | 0 |
Other operation and maintenance | 0 | 0 | 0 |
Depreciation and amortization | 0 | 0 | 0 |
Other income, net | 2.1 | 1.3 | 1.4 |
Interest expense | 0 | 0 | 0 |
Income tax expense | 0.4 | 0.3 | 0.3 |
Net income | 1.7 | 1 | 1.1 |
Capital expenditures and asset acquisitions | 0 | 0 | 0 |
Total assets | $ 13.6 | $ 12.8 | $ 11.4 |
COMMITMENTS AND CONTINGENCIES -
COMMITMENTS AND CONTINGENCIES - UNCONDITIONAL PURCHASE OBLIGATIONS (Details) $ in Millions | Dec. 31, 2023 USD ($) |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | $ 981.8 |
2024 | 235.7 |
2025 | 170.1 |
2026 | 103.6 |
2027 | 83.5 |
2028 | 77.1 |
Later Years | 311.8 |
Purchased power | Electric | |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | 310.6 |
2024 | 53.9 |
2025 | 54.9 |
2026 | 55.9 |
2027 | 50.5 |
2028 | 46.8 |
Later Years | 48.6 |
Coal supply and transportation | Electric | |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | 194.1 |
2024 | 110.4 |
2025 | 70.4 |
2026 | 13.3 |
2027 | 0 |
2028 | 0 |
Later Years | 0 |
Other | Electric | |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | 100.6 |
2024 | 13.9 |
2025 | 13.3 |
2026 | 12.9 |
2027 | 11.6 |
2028 | 10.2 |
Later Years | 38.7 |
Natural gas utility supply and transportation | Natural gas | |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | 376.5 |
2024 | 57.5 |
2025 | 31.5 |
2026 | 21.5 |
2027 | 21.4 |
2028 | 20.1 |
Later Years | $ 224.5 |
COMMITMENTS AND CONTINGENCIES_2
COMMITMENTS AND CONTINGENCIES - ENVIRONMENTAL MATTERS (Details) $ in Millions | 1 Months Ended | 12 Months Ended | ||||||||
Aug. 31, 2023 | May 31, 2023 performance_obligations MW | Apr. 30, 2023 MMBTU | Jan. 31, 2023 micrograms | May 31, 2021 | Dec. 31, 2020 micrograms performance_obligations | Dec. 31, 2023 USD ($) MW | Feb. 07, 2024 micrograms | Jun. 30, 2023 USD ($) | Dec. 31, 2022 USD ($) | |
Manufactured Gas Plant Remediation | ||||||||||
Regulatory assets | $ | $ 360.6 | $ 365.5 | ||||||||
Estimated future cash expenditures for environmental remediation | $ | 85.3 | 88.6 | ||||||||
Environmental remediation costs | ||||||||||
Manufactured Gas Plant Remediation | ||||||||||
Regulatory assets | $ | 121.5 | 118.5 | ||||||||
Estimated future cash expenditures for environmental remediation | $ | $ 85.3 | |||||||||
Cross State Air Pollution Rule | Electric | Maximum | ||||||||||
Air Quality | ||||||||||
RICE unit megawatts needed to be subject to the rule | MW | 25 | |||||||||
Mercury and Air Toxics Standards | Electric | ||||||||||
Air Quality | ||||||||||
Current level of particulate matter in pounds per million british thermal unit | MMBTU | 0.03 | |||||||||
EPA proposed lower limit for particulate matter | MMBTU | 0.01 | |||||||||
Even lower level of particulate matter that the EPA is seeking comments on | MMBTU | 0.006 | |||||||||
National Ambient Air Quality Standards | Electric | ||||||||||
Air Quality | ||||||||||
Number of revisions necessary to meet the 2012 standard for particulate matter | performance_obligations | 0 | |||||||||
Current level of micrograms per cubic meter that particulate matter needs to be below | micrograms | 12 | |||||||||
Current level of micrograms per cubic meter under the 24-Hour standard that particulate matter needs to be below | micrograms | 35 | |||||||||
National Ambient Air Quality Standards | Electric | Minimum | ||||||||||
Air Quality | ||||||||||
Period of time for EPA review of ozone plan | 3 years | |||||||||
Proposed primary (health-based) annual standard | micrograms | 9 | |||||||||
The EPA is taking comments on this full range of micrograms per cubic meter | micrograms | 8 | |||||||||
National Ambient Air Quality Standards | Electric | Maximum | ||||||||||
Air Quality | ||||||||||
Period of time for EPA review of ozone plan | 5 years | |||||||||
Proposed primary (health-based) annual standard | micrograms | 10 | |||||||||
The EPA is taking comments on this full range of micrograms per cubic meter | micrograms | 11 | |||||||||
National Ambient Air Quality Standards | Electric | Maximum | Subsequent event | ||||||||||
Air Quality | ||||||||||
New primary annual PM2.5 level | micrograms | 9 | |||||||||
Climate Change | Electric | ||||||||||
Air Quality | ||||||||||
Number of applicable GHG performance standards for coal plants | performance_obligations | 0 | |||||||||
Percent capacity factor that if combined cycle natural gas plants are above it causes the rule to be highly dependent on hydrogen or carbon capture | 50% | |||||||||
Percent capacity factor for simple cycle natural gas fired combustion turbines that there are no applicable limits if the capacity factor is less than this | 20% | |||||||||
Rules that are being proposed for natural gas-fired stationary combustion turbines | performance_obligations | 1 | |||||||||
Number of subcategories of combustion turbine unit annual capacity factors that the proposed rule will be broken up into | performance_obligations | 3 | |||||||||
Capacity of coal generation retired, in megawatts | MW | 400 | |||||||||
Capacity of fossil-fueled generation to be retired by the end of 2031, in megawatts | MW | 1,800 | |||||||||
Company goal for percentage of carbon dioxide emission reductions by the end of 2025 | 60% | |||||||||
Company goal for percentage of carbon dioxide emissions reduction below 2005 levels by the end of 2030 | 80% | |||||||||
Climate Change | Electric | Maximum | ||||||||||
Air Quality | ||||||||||
RICE unit megawatts needed to be subject to the rule | MW | 25 | |||||||||
Steam Electric Effluent Guidelines | Electric | ||||||||||
Water Quality | ||||||||||
Capital investment that was required to be in compliance with the ELG rule | $ | $ 8 | |||||||||
Manufactured Gas Plant Remediation | Natural gas | ||||||||||
Manufactured Gas Plant Remediation | ||||||||||
Estimated future cash expenditures for environmental remediation | $ | $ 85.3 | 88.6 | ||||||||
Manufactured Gas Plant Remediation | Natural gas | Environmental remediation costs | ||||||||||
Manufactured Gas Plant Remediation | ||||||||||
Regulatory assets | $ | $ 121.5 | $ 118.5 | ||||||||
Renewables, Efficiency, and Conservation | Wisconsin | Electric | ||||||||||
Renewables, Efficiency, and Conservation | ||||||||||
Annual renewable portfolio requirement for Wisconsin, as a percent | 10% | |||||||||
Required renewable energy percent achieved | 9.74% | |||||||||
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, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Supplemental cash flow information | |||
Cash paid for interest, net of amount capitalized | $ 87.6 | $ 67.8 | $ 63.2 |
Cash paid (received) for income taxes, net | 2.9 | 25.9 | (55.2) |
Cash received for sale of PTCs to a third party | 4.9 | ||
Significant non-cash investing and financing transactions | |||
Accounts payable related to construction costs | 24.8 | 30.3 | 15.5 |
Increase in receivables related to insurance proceeds | 0 | 0 | 4.3 |
Liabilities accrued for software licensing agreement | $ 0 | $ 1.5 | $ 0 |
SUPPLEMENTAL CASH FLOW INFORM_4
SUPPLEMENTAL CASH FLOW INFORMATION - RECONCILIATION OF CASH, CASH EQUIVALENTS, AND RESTRICTED CASH (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Jan. 01, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 |
Reconciliation of cash, cash equivalents, and restricted cash | |||||
Cash and cash equivalents | $ 1.4 | $ 0.5 | $ 2.4 | ||
Restricted cash included in other long-term assets | 0 | 38 | 0 | ||
Cash, cash equivalents, and restricted cash | $ 1.4 | $ 38.5 | $ 2.4 | $ 2.7 | |
Whitewater | |||||
Whitewater acquisition | |||||
Ownership (as a percent) | 50% |
REGULATORY ENVIRONMENT - 2024 L
REGULATORY ENVIRONMENT - 2024 LIMITED RATE CASE RE-OPENER (Details) - Public Service Commission of Wisconsin (PSCW) - 2024 Rate Case Re-Opener - Electric $ in Millions | Dec. 20, 2023 USD ($) |
Public Utilities, General Disclosures | |
Approved rate decrease | $ 32.7 |
Approved rate decrease (as a percent) | 2.60% |
REGULATORY ENVIRONMENT - 2023 A
REGULATORY ENVIRONMENT - 2023 AND 2024 RATES (Details) - Public Service Commission of Wisconsin (PSCW) - 2023 and 2024 Rates | 1 Months Ended |
Dec. 31, 2022 USD ($) | |
Public Utilities, General Disclosures | |
Approved return on equity (as a percent) | 9.80% |
Approved common equity component average (as a percent) | 53% |
Percentage of first 15 basis points of additional earnings retained by the utility | 100% |
Return on equity in excess of authorized amount (as a percent) | 0.15% |
Percentage of additional earnings between 15 and 75 basis points refunded to customers | 50% |
Return on equity in excess of first 15 basis points above authorized amount (as a percent) | 0.60% |
Percentage of earnings in excess of 75 basis points refunded to customers | 100% |
Decrease in certain customer fixed charges | $ 3.33 |
Commitments to contribute to Keep Wisconsin Warm Fund | 4,000,000 |
Electric | |
Public Utilities, General Disclosures | |
Approved rate increase | $ 120,500,000 |
Approved rate increase (as a percent) | 9.80% |
Natural gas | |
Public Utilities, General Disclosures | |
Approved rate increase | $ 26,400,000 |
Approved rate increase (as a percent) | 7.10% |
REGULATORY ENVIRONMENT - 2022 R
REGULATORY ENVIRONMENT - 2022 RATES (Details) - Public Service Commission of Wisconsin (PSCW) - 2022 Rates | 1 Months Ended |
Sep. 30, 2021 | |
Public Utilities, General Disclosures | |
Period to forego filing a rate case | 1 year |
Percentage of first 15 basis points of additional earnings retained by the utility | 100% |
Return on equity in excess of authorized amount (as a percent) | 0.15% |
REGULATORY ENVIRONMENT - WI 202
REGULATORY ENVIRONMENT - WI 2020 and 2021 RATES (Details) - Public Service Commission of Wisconsin (PSCW) $ in Millions | 1 Months Ended |
Dec. 31, 2019 USD ($) | |
2020 and 2021 rates | |
Public Utilities, General Disclosures | |
Approved return on equity (as a percent) | 10% |
Approved common equity component average (as a percent) | 52.50% |
Percentage of first 25 basis points of additional earnings retained by the utility | 100% |
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% |
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% |
2020 and 2021 rates | Electric | |
Public Utilities, General Disclosures | |
Approved rate increase | $ 15.8 |
Approved rate increase (as a percent) | 1.60% |
Authorized Revenue Requirement For ReACT | $ 275 |
Cost of the ReACT project, excluding AFUDC | $ 342 |
2020 and 2021 rates | Electric | ReACT | |
Public Utilities, General Disclosures | |
Recovery period of regulatory asset | 8 years |
2020 and 2021 rates | Electric | Tax Cuts and Jobs Act of 2017 | |
Public Utilities, General Disclosures | |
Amortization period | 2 years |
2020 and 2021 rates | Electric | Earnings sharing mechanism | |
Public Utilities, General Disclosures | |
Amortization period | 2 years |
Amortization of regulatory liabilities | $ 21 |
2020 and 2021 rates | Natural gas | |
Public Utilities, General Disclosures | |
Approved rate increase | $ 4.3 |
Approved rate increase (as a percent) | 1.40% |
2020 and 2021 rates | Natural gas | Tax Cuts and Jobs Act of 2017 | |
Public Utilities, General Disclosures | |
Amortization period | 4 years |
2020 rates | Electric | Tax Cuts and Jobs Act of 2017 | |
Public Utilities, General Disclosures | |
Amortization of regulatory liabilities | $ 11 |
2020 rates | Natural gas | Tax Cuts and Jobs Act of 2017 | |
Public Utilities, General Disclosures | |
Amortization of regulatory liabilities | 5 |
2021 rates | Electric | Tax Cuts and Jobs Act of 2017 | |
Public Utilities, General Disclosures | |
Amortization of regulatory liabilities | 39 |
2021 rates | Natural gas | Tax Cuts and Jobs Act of 2017 | |
Public Utilities, General Disclosures | |
Amortization of regulatory liabilities | $ 5 |
REGULATORY ENVIRONMENT - RECOVE
REGULATORY ENVIRONMENT - RECOVERY OF NATURAL GAS COSTS (Details) - Public Service Commission of Wisconsin (PSCW) - Energy costs recoverable through rate adjustments $ in Millions | Mar. 31, 2021 USD ($) |
Public Utilities, General Disclosures | |
Amounts recoverable from customers | $ 28 |
Recovery period of regulatory asset | 3 months |
OTHER INCOME, NET (Details)
OTHER INCOME, NET (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Other Income and Expenses [Abstract] | |||
Non-service components of net periodic benefit costs | Other income, net | Other income, net | Other income, net |
Non-service components of net periodic benefit costs | $ 35.4 | $ 35.3 | $ 26.8 |
AFUDC-Equity | 7.6 | 5.8 | 9 |
Other, net | 2.9 | 1.2 | 2.4 |
Other income, net | $ 45.9 | $ 42.3 | $ 38.2 |
SCHEDULE II - VALUATION AND Q_2
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Valuation and qualifying accounts | |||
Balance at beginning of period | $ 11.7 | $ 11.1 | $ 18.3 |
Expense | 5.6 | 8.4 | 6.2 |
Deferral | 3.3 | 0.1 | (7) |
Net write-offs | (9.7) | (7.9) | (6.4) |
Balance at end of period | $ 10.9 | $ 11.7 | $ 11.1 |