COVER PAGE
COVER PAGE | 3 Months Ended |
Mar. 31, 2023 shares | |
Cover [Abstract] | |
Document type | 10-Q |
Document Quarterly Report | true |
Document period end date | Mar. 31, 2023 |
Document Transition Report | false |
Entity File Number | 001-01245 |
Entity registrant name | WISCONSIN ELECTRIC POWER COMPANY |
Entity Tax Identification Number | 39-0476280 |
Entity Incorporation, State or Country Code | WI |
Entity Address, Address Line One | 231 West Michigan Street |
Entity Address, Address Line Two | P.O. Box 2046 |
Entity Address, City or Town | Milwaukee |
Entity Address, State or Province | WI |
Entity Address, Postal Zip Code | 53201 |
City Area Code | 414 |
Local Phone Number | 221-2345 |
Entity Current Reporting Status | Yes |
Entity Interactive Data Current | Yes |
Entity filer category | Non-accelerated Filer |
Small business | false |
Emerging growth company | false |
Entity Shell Company | false |
Entity common stock, shares outstanding | 33,289,327 |
Entity central index key | 0000107815 |
Current fiscal year end date | --12-31 |
Document fiscal year focus | 2023 |
Document fiscal period focus | Q1 |
Amendment flag | false |
CONDENSED CONSOLIDATED INCOME S
CONDENSED CONSOLIDATED INCOME STATEMENTS - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2023 | Mar. 31, 2022 | |
Income Statement [Abstract] | ||
Operating revenues | $ 1,091.9 | $ 1,072 |
Operating expenses | ||
Cost of sales | 444.5 | 444.2 |
Other operation and maintenance | 232.3 | 192.6 |
Depreciation and amortization | 127.8 | 119.1 |
Property and revenue taxes | 29.9 | 27 |
Total operating expenses | 834.5 | 782.9 |
Operating income | 257.4 | 289.1 |
Other income, net | 15.1 | 10.6 |
Interest expense | 117.8 | 113.4 |
Other expense | (102.7) | (102.8) |
Income before income taxes | 154.7 | 186.3 |
Income tax expense | 32.7 | 47.5 |
Net income | 122 | 138.8 |
Preferred stock dividend requirements | 0.3 | 0.3 |
Net income attributed to common shareholder | $ 121.7 | $ 138.5 |
CONDENSED CONSOLIDATED BALANCE
CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions | Mar. 31, 2023 | Dec. 31, 2022 |
Current assets | ||
Cash and cash equivalents | $ 11.4 | $ 6.1 |
Accounts receivable and unbilled revenues, net of reserves of $53.7 and $49.7, respectively | 595.5 | 582.6 |
Accounts receivable from related parties | 93.7 | 113.2 |
Materials, supplies, and inventories | 238.8 | 292.9 |
Prepaid taxes | 75.4 | 113.1 |
Other prepayments | 27.2 | 25.6 |
Collateral on deposit | 80.8 | 46.7 |
Other | 6.8 | 27.1 |
Current assets | 1,129.6 | 1,207.3 |
Long-term assets | ||
Property, plant, and equipment, net of accumulated depreciation and amortization of $5,491.7 and $5,450.3, respectively | 10,794.4 | 10,718.6 |
Regulatory assets (March 31, 2023 and December 31, 2022 include $90.9 and $92.4, respectively, related to WEPCo Environmental Trust) | 2,854.4 | 2,817.5 |
Pension and OPEB assets | 145.2 | 143.3 |
Other | 85.6 | 133.5 |
Long-term assets | 13,879.6 | 13,812.9 |
Total assets | 15,009.2 | 15,020.2 |
Current liabilities | ||
Short-term debt | 127.5 | 460.7 |
Current portion of long-term debt (related to WEPCo Environmental Trust) | 8.9 | 8.9 |
Current portion of finance lease obligations | 78.8 | 112.3 |
Accounts payable | 228.4 | 400.5 |
Accounts payable to related parties | 174.4 | 179.4 |
Derivative liabilities | 66.7 | 28.8 |
Other | 223.8 | 181.7 |
Current liabilities | 908.5 | 1,372.3 |
Long-term liabilities | ||
Long-term debt (March 31, 2023 and December 31, 2022 each include $94.1 related to WEPCo Environmental Trust) | 3,352.2 | 3,351.5 |
Finance lease obligations | 2,701 | 2,702.3 |
Deferred income taxes | 1,472.8 | 1,467.3 |
Regulatory liabilities | 1,611.5 | 1,637.4 |
Pension and OPEB obligations | 28.1 | 30.8 |
Other | 290.6 | 291.4 |
Long-term liabilities | 9,456.2 | 9,480.7 |
Commitments and contingencies (Note 17) | ||
Common shareholder's equity | ||
Common stock – $10 par value; 65,000,000 shares authorized; 33,289,327 shares outstanding | 332.9 | 332.9 |
Additional paid in capital | 2,162.3 | 1,746.8 |
Retained earnings | 2,118.9 | 2,057.1 |
Common shareholder's equity | 4,614.1 | 4,136.8 |
Preferred stock | 30.4 | 30.4 |
Total liabilities and equity | $ 15,009.2 | $ 15,020.2 |
CONDENSED CONSOLIDATED BALANC_2
CONDENSED CONSOLIDATED BALANCE SHEETS (PARENTHETICALS) - USD ($) $ in Millions | Mar. 31, 2023 | Dec. 31, 2022 |
Statement of Financial Position [Abstract] | ||
Accounts receivable and unbilled revenues, reserves | $ 53.7 | $ 49.7 |
Property, plant, and equipment, accumulated depreciation and amortization | $ 5,491.7 | $ 5,450.3 |
Common stock, par value (in dollars per share) | $ 10 | $ 10 |
Common stock, shares authorized | 65,000,000 | 65,000,000 |
Common stock, shares outstanding | 33,289,327 | 33,289,327 |
Regulatory assets (March 31, 2023 and December 31, 2022 include $90.9 and $92.4, respectively, related to WEPCo Environmental Trust) | $ 2,854.4 | $ 2,817.5 |
Long-term debt (March 31, 2023 and December 31, 2022 each include $94.1 related to WEPCo Environmental Trust) | 3,352.2 | 3,351.5 |
WEPCo Environmental Trust | ||
Regulatory assets (March 31, 2023 and December 31, 2022 include $90.9 and $92.4, respectively, related to WEPCo Environmental Trust) | 90.9 | 92.4 |
Long-term debt (March 31, 2023 and December 31, 2022 each include $94.1 related to WEPCo Environmental Trust) | $ 94.1 | $ 94.1 |
CONDENSED CONSOLIDATED STATEMEN
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2023 | Mar. 31, 2022 | |
Operating activities | ||
Net income | $ 122 | $ 138.8 |
Reconciliation to cash provided by operating activities | ||
Depreciation and amortization | 127.8 | 119.1 |
Deferred income taxes and ITCs, net | (0.1) | 16 |
Change in – | ||
Accounts receivable and unbilled revenues, net | 7.8 | (19) |
Materials, supplies, and inventories | 59 | 39.9 |
Prepaid taxes | 37.7 | 25.7 |
Collateral on deposit | (34.1) | 0.3 |
Other current assets | (0.7) | 4.9 |
Accounts payable | (141.8) | (105.9) |
Accrued taxes | 24.9 | 31.2 |
Amounts refundable to customers | 31.1 | 17.5 |
Accrued interest | 22.6 | 29.2 |
Collateral received | 0 | 34.6 |
Other current liabilities | (36.1) | (22) |
Other, net | (4.6) | (2.1) |
Net cash provided by operating activities | 215.5 | 308.2 |
Investing activities | ||
Capital expenditures | (208.7) | (139.5) |
Acquisition of Whitewater | (38) | 0 |
Insurance proceeds received for property damage | 0 | 41 |
Other, net | (2.6) | (0.6) |
Net cash used in investing activities | (249.3) | (99.1) |
Financing activities | ||
Change in short-term debt | (333.2) | (351) |
Payments for finance lease obligations | (18.3) | (18.6) |
Equity contribution from parent | 415 | 280 |
Payment of dividends to parent | (60) | (110) |
Other, net | (0.3) | (0.3) |
Net cash provided by (used in) financing activities | 3.2 | (199.9) |
Net change in cash, cash equivalents, and restricted cash | (30.6) | 9.2 |
Cash, cash equivalents, and restricted cash at beginning of period | 47.7 | 3 |
Cash, cash equivalents, and restricted cash at end of period | $ 17.1 | $ 12.2 |
CONDENSED CONSOLIDATED STATEM_2
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY - USD ($) $ in Millions | Total | Total common shareholder's equity | Common stock | Additional paid in capital | Retained earnings | Preferred stock |
Balance at Dec. 31, 2021 | $ 3,944.7 | $ 3,914.3 | $ 332.9 | $ 1,290.9 | $ 2,290.5 | $ 30.4 |
Statements of equity | ||||||
Net income attributed to common shareholder | 138.5 | 138.5 | 0 | 0 | 138.5 | 0 |
Payment of dividends to parent | (110) | (110) | 0 | 0 | (110) | 0 |
Equity contribution from parent | 280 | 280 | 0 | 280 | 0 | 0 |
Stock-based compensation and other | 0.6 | 0.6 | 0 | 0.7 | (0.1) | 0 |
Balance at Mar. 31, 2022 | 4,253.8 | 4,223.4 | 332.9 | 1,571.6 | 2,318.9 | 30.4 |
Balance at Dec. 31, 2022 | 4,167.2 | 4,136.8 | 332.9 | 1,746.8 | 2,057.1 | 30.4 |
Statements of equity | ||||||
Net income attributed to common shareholder | 121.7 | 121.7 | 0 | 0 | 121.7 | 0 |
Payment of dividends to parent | (60) | (60) | 0 | 0 | (60) | 0 |
Equity contribution from parent | 415 | 415 | 0 | 415 | 0 | 0 |
Stock-based compensation and other | 0.6 | 0.6 | 0 | 0.5 | 0.1 | 0 |
Balance at Mar. 31, 2023 | $ 4,644.5 | $ 4,614.1 | $ 332.9 | $ 2,162.3 | $ 2,118.9 | $ 30.4 |
GENERAL INFORMATION
GENERAL INFORMATION | 3 Months Ended |
Mar. 31, 2023 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
GENERAL INFORMATION | GENERAL INFORMATION Wisconsin Electric Power Company serves approximately 1.2 million electric customers and 0.5 million natural gas customers. As used in these notes, the term "financial statements" refers to the condensed consolidated financial statements. This includes the income statements, balance sheets, statements of cash flows, and statements of equity, unless otherwise noted. In this report, when we refer to "the Company," "us," "we," "our," or "ours," we are referring to Wisconsin Electric Power Company and its subsidiary. On our financial statements, we consolidate VIEs of which we are the primary beneficiary. We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2022. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three months ended March 31, 2023, are not necessarily indicative of expected results for 2023 due to seasonal variations and other factors. In management's opinion, we have included all adjustments, normal and recurring in nature, necessary for a fair presentation of our financial results. |
ACQUISITIONS
ACQUISITIONS | 3 Months Ended |
Mar. 31, 2023 | |
Asset Acquisition [Abstract] | |
ACQUISITIONS | 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. Acquisitions of Electric Generation Facilities in Wisconsin In February 2023, WPS, along with an unaffiliated entity, received approval from the PSCW to acquire 100 MWs of West Riverside's nameplate capacity, in the first of two potential option exercises. WPS also received approval to transfer its ownership interest to us. The transaction is expected to close during the second quarter of 2023, and our investment is expected to be approximately $102 million. West Riverside is a commercially operational dual fueled combined cycle generation facility in Beloit, Wisconsin. In January 2023, we, along with WPS, completed the acquisition of Whitewater, a commercially operational 236.5 MW dual fueled (natural gas and low sulfur fuel oil) combined cycle electric generation facility in Whitewater, Wisconsin. Our share of the cost of this facility was $38.0 million for 50% of the capacity. |
OPERATING REVENUES
OPERATING REVENUES | 3 Months Ended |
Mar. 31, 2023 | |
Revenue from Contract with Customer [Abstract] | |
OPERATING REVENUES | OPERATING REVENUES For more information about our operating revenues, see Note 1(d), Operating Revenues, in our 2022 Annual Report on Form 10-K. 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. Three Months Ended March 31 (in millions) 2023 2022 Wisconsin Electric Power Company Electric utility $ 843.9 $ 831.1 Natural gas utility 243.6 235.9 Total revenues from contracts with customers 1,087.5 1,067.0 Other operating revenues 4.4 5.0 Total operating revenues $ 1,091.9 $ 1,072.0 Revenues from Contracts with Customers Electric Utility Operating Revenues The following table disaggregates electric utility operating revenues by customer class: Three Months Ended March 31 (in millions) 2023 2022 Residential $ 357.4 $ 335.4 Small commercial and industrial 284.6 268.0 Large commercial and industrial 139.1 136.8 Other 5.7 5.4 Total retail revenues 786.8 745.6 Wholesale 11.7 20.6 Resale 33.4 51.0 Steam 11.0 12.1 Other utility revenues 1.0 1.8 Total electric utility operating revenues $ 843.9 $ 831.1 Natural Gas Utility Operating Revenues The following table disaggregates natural gas utility operating revenues by customer class: Three Months Ended March 31 (in millions) 2023 2022 Residential $ 179.2 $ 165.7 Commercial and industrial 87.9 83.3 Total retail revenues 267.1 249.0 Transportation 6.8 5.6 Other utility revenues (1) (30.3) (18.7) Total natural gas utility operating revenues $ 243.6 $ 235.9 (1) Includes the revenues subject to our purchased gas recovery mechanism. During both quarters, we over-collected natural gas costs due to these costs being lower than what was anticipated in rates. Other Operating Revenues Other operating revenues consist primarily of the following: Three Months Ended March 31 (in millions) 2023 2022 Late payment charges $ 3.7 $ 3.5 Rental revenues 0.4 0.9 Alternative revenues (1) 0.3 0.6 Total other operating revenues $ 4.4 $ 5.0 (1) See Note 1(d), Operating Revenues, in our 2022 Annual Report on Form 10-K for more information on alternative revenues. |
CREDIT LOSSES
CREDIT LOSSES | 3 Months Ended |
Mar. 31, 2023 | |
Credit Loss [Abstract] | |
CREDIT LOSSES | 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 March 31, 2023 and December 31, 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. We have included a table below that shows our gross third-party receivable balances and related allowance for credit losses. (in millions) March 31, 2023 December 31, 2022 Accounts receivable and unbilled revenues $ 649.2 $ 632.3 Allowance for credit losses 53.7 49.7 Accounts receivable and unbilled revenues, net (1) $ 595.5 $ 582.6 Total accounts receivable, net – past due greater than 90 days (1) $ 39.3 $ 35.8 Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1) 98.5 % 97.5 % (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 March 31, 2023, $349.7 million, or 58.7%, 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: Three Months Ended March 31 (in millions) 2023 2022 Balance at January 1 $ 49.7 $ 51.4 Provision for credit losses 6.6 6.1 Provision for credit losses deferred for future recovery or refund 13.8 7.1 Write-offs charged against the allowance (20.3) (18.8) Recoveries of amounts previously written off 3.9 6.0 Balance at March 31 $ 53.7 $ 51.8 There was a $4.0 million increase in the allowance for credit losses at March 31, 2023, compared to January 1, 2023, driven by an increase in past due accounts receivable balances. An increase in past due balances is a trend we generally see over the winter moratorium months, when we are not allowed to disconnect customer service as a result of non-payment. The winter moratorium begins on November 1 and ends on April 15. |
REGULATORY ASSETS AND LIABILITI
REGULATORY ASSETS AND LIABILITIES | 3 Months Ended |
Mar. 31, 2023 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
REGULATORY ASSETS AND LIABILITIES | REGULATORY ASSETS AND LIABILITIES The following regulatory assets and liabilities were reflected on our balance sheets at March 31, 2023 and December 31, 2022. For more information on our regulatory assets and liabilities, see Note 6, Regulatory Assets and Liabilities, in our 2022 Annual Report on Form 10-K. (in millions) March 31, 2023 December 31, 2022 Regulatory assets Finance leases $ 1,083.7 $ 1,072.0 Plant retirement related items 623.4 632.7 Income tax related items 379.0 382.1 Pension and OPEB costs 334.2 337.2 System support resource 120.9 123.5 Securitization 90.9 92.4 Derivatives 80.3 40.3 Asset retirement obligations 41.2 41.1 Uncollectible expense 30.2 16.4 Energy efficiency programs 16.5 17.7 We Power generation 12.1 21.6 Other, net 42.0 40.5 Total regulatory assets $ 2,854.4 $ 2,817.5 (in millions) March 31, 2023 December 31, 2022 Regulatory liabilities Removal costs $ 729.0 $ 718.1 Income tax related items 708.1 716.1 Pension and OPEB benefits 143.4 144.4 Energy costs refundable through rate adjustments (1) 32.8 1.8 Electric transmission costs 8.3 0.2 Derivatives 1.8 39.1 Other, net 20.5 19.1 Total regulatory liabilities $ 1,643.9 $ 1,638.8 Balance sheet presentation Other current liabilities $ 32.4 $ 1.4 Regulatory liabilities 1,611.5 1,637.4 Total regulatory liabilities $ 1,643.9 $ 1,638.8 (1) The increase in these regulatory liabilities was primarily due to lower natural gas costs incurred during the first quarter of 2023, compared to what was anticipated in rates. |
PROPERTY, PLANT, AND EQUIPMENT
PROPERTY, PLANT, AND EQUIPMENT | 3 Months Ended |
Mar. 31, 2023 | |
Property, Plant and Equipment [Abstract] | |
PROPERTY, PLANT, AND EQUIPMENT | PROPERTY, PLANT, AND EQUIPMENT Plant to be Retired Oak Creek Power Plant Units 5 – 8 As a result of a PSCW approval for the construction of a solar and battery project received in December 2022, retirement of the OCPP generating units 5 – 8 became probable. In early 2023, WEC Energy Group received additional approvals for electric generation facilities, including West Riverside and the Koshkonong Solar-Battery Park. OCPP units 5 and 6 are expected to be retired by May 2024, while units 7 and 8 are expected to be retired by late 2025. The total net book value of our ownership share of units 5 – 8 was $812.9 million at March 31, 2023, which does not include deferred taxes. These amounts were 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. |
COMMON EQUITY
COMMON EQUITY | 3 Months Ended |
Mar. 31, 2023 | |
Equity [Abstract] | |
COMMON EQUITY | COMMON EQUITY Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to WEC Energy Group in the form of cash dividends, loans, or advances. In addition, Wisconsin law prohibits us from making loans to or guaranteeing obligations of WEC Energy Group or its subsidiaries. See Note 10, Common Equity, in our 2022 Annual Report on Form 10-K for additional information on these and other restrictions. We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future. |
SHORT-TERM DEBT AND LINES OF CR
SHORT-TERM DEBT AND LINES OF CREDIT | 3 Months Ended |
Mar. 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: (in millions, except percentages) March 31, 2023 December 31, 2022 Commercial paper Amount outstanding $ 127.5 $ 460.7 Weighted-average interest rate on amounts outstanding 5.01 % 4.59 % Our average amount of commercial paper borrowings based on daily outstanding balances during the three months ended March 31, 2023 was $127.6 million with a weighted-average interest rate during the period of 4.68%. The information in the table below relates to our revolving credit facility used to support our commercial paper borrowing program, including available capacity under this facility: (in millions) Maturity March 31, 2023 Revolving credit facility September 2026 $ 500.0 Less: Letters of credit issued inside credit facility 1.0 Commercial paper outstanding 127.5 Available capacity under existing credit facility $ 371.5 |
MATERIALS, SUPPLIES, AND INVENT
MATERIALS, SUPPLIES, AND INVENTORIES | 3 Months Ended |
Mar. 31, 2023 | |
Inventory Disclosure [Abstract] | |
MATERIALS, SUPPLIES, AND INVENTORIES | MATERIALS, SUPPLIES, AND INVENTORIES Our inventory consisted of: (in millions) March 31, 2023 December 31, 2022 Materials and supplies $ 158.4 $ 150.6 Fossil fuel 61.1 62.7 Natural gas in storage 19.3 79.6 Total $ 238.8 $ 292.9 Substantially all materials and supplies, fossil fuel, and natural gas in storage inventories are recorded using the weighted-average cost method of accounting. |
INCOME TAXES
INCOME TAXES | 3 Months Ended |
Mar. 31, 2023 | |
Income Tax Disclosure [Abstract] | |
INCOME TAXES | INCOME TAXES The provision for income taxes 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: Three Months Ended March 31, 2023 Three Months Ended March 31, 2022 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Statutory federal income tax $ 32.4 21.0 % $ 39.1 21.0 % State income taxes net of federal tax benefit 9.3 6.0 % 11.6 6.2 % Federal excess deferred tax amortization (5.3) (3.5) % (7.5) (4.0) % PTCs (5.1) (3.3) % (0.5) (0.3) % AFUDC - Equity (2.2) (1.4) % (1.3) (0.7) % Domestic production activities deferral 1.6 1.0 % 2.0 1.1 % Other, net 2.0 1.3 % 4.1 2.2 % Total income tax expense $ 32.7 21.1 % $ 47.5 25.5 % The effective tax rates of 21.1% and 25.5% for the three months ended March 31, 2023 and 2022, respectively, differ from the United States statutory federal income tax rate of 21%, primarily due to state income taxes. This item was partially offset by the impact of the protected deferred tax benefits associated with the Tax Legislation, as discussed in more detail below, and PTCs. The Tax Legislation required us to remeasure the deferred income taxes at our utility segment and we began to amortize the resulting excess protected deferred income taxes beginning in 2018 in accordance with normalization requirements (see federal excess deferred tax amortization line above). See Note 23, Regulatory Environment, in our 2022 Annual Report on Form 10-K for more information about the impact of the Tax Legislation. |
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS | 3 Months Ended |
Mar. 31, 2023 | |
Fair Value Disclosures [Abstract] | |
FAIR VALUE MEASUREMENTS | 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. 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: March 31, 2023 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 0.1 $ 0.7 $ — $ 0.8 FTRs — — 0.8 0.8 Coal contracts — 0.3 — 0.3 Total derivative assets $ 0.1 $ 1.0 $ 0.8 $ 1.9 Derivative liabilities Natural gas contracts $ 58.0 $ 0.4 $ — $ 58.4 Coal contracts — 14.1 — 14.1 Total derivative liabilities $ 58.0 $ 14.5 $ — $ 72.5 December 31, 2022 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 1.6 $ 2.5 $ — $ 4.1 FTRs — — 2.0 2.0 Coal contracts — 32.7 — 32.7 Total derivative assets $ 1.6 $ 35.2 $ 2.0 $ 38.8 Derivative liabilities Natural gas contracts $ 29.3 $ 0.7 $ — $ 30.0 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 and Operating Reserves Markets. The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy: Three Months Ended March 31 (in millions) 2023 2022 Balance at the beginning of the period $ 2.0 $ 1.0 Settlements (1.2) (0.6) Balance at the end of the period $ 0.8 $ 0.4 Fair Value of Financial Instruments The following table shows the financial instruments included on our balance sheets that were not recorded at fair value: March 31, 2023 December 31, 2022 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock $ 30.4 $ 23.1 $ 30.4 $ 22.7 Long-term debt, including current portion 3,361.1 3,237.0 3,360.4 3,143.2 The fair values of our long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy. |
DERIVATIVE INSTRUMENTS
DERIVATIVE INSTRUMENTS | 3 Months Ended |
Mar. 31, 2023 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
DERIVATIVE INSTRUMENTS | 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 an asset or liability 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. On our balance sheets, we classify derivative assets and liabilities as current or long-term based on the maturities of the underlying contracts. Derivative assets and liabilities not shown separately on our balance sheets are included in the other current and other long-term line items. The following table shows our derivative assets and derivative liabilities. None of the derivatives shown below are designated as hedging instruments. March 31, 2023 December 31, 2022 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Current Natural gas contracts $ 0.8 $ 57.6 $ 4.1 $ 28.8 FTRs 0.8 — 2.0 — Coal contracts 0.2 9.1 17.6 — Total current 1.8 66.7 23.7 28.8 Long-term Natural gas contracts — 0.8 — 1.2 Coal contracts 0.1 5.0 15.1 — Total long-term 0.1 5.8 15.1 1.2 Total $ 1.9 $ 72.5 $ 38.8 $ 30.0 Realized gains and losses on derivatives are primarily recorded in cost of sales Three Months Ended March 31, 2023 Three Months Ended March 31, 2022 (in millions) Volumes Gains (Losses) Volumes Gains Natural gas contracts 18.9 Dth $ (29.2) 18.7 Dth $ 8.2 FTRs 4.9 MWh 0.1 5.0 MWh 0.2 Total $ (29.1) $ 8.4 On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At March 31, 2023 and December 31, 2022, we had posted cash collateral of $80.8 million and $46.7 million, respectively. These amounts were recorded on our balance sheets in collateral on deposit. The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets: March 31, 2023 December 31, 2022 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 1.9 $ 72.5 $ 38.8 $ 30.0 Gross amount not offset on the balance sheet (0.2) (58.1) (1) (1.8) (29.5) (2) Net amount $ 1.7 $ 14.4 $ 37.0 $ 0.5 (1) Includes cash collateral posted of $57.9 million. (2) Includes cash collateral posted of $27.7 million. |
GUARANTEES
GUARANTEES | 3 Months Ended |
Mar. 31, 2023 | |
Guarantees [Abstract] | |
GUARANTEES | GUARANTEESAs of March 31, 2023, we had $26.0 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
EMPLOYEE BENEFITS | 3 Months Ended |
Mar. 31, 2023 | |
Retirement Benefits [Abstract] | |
EMPLOYEE BENEFITS | EMPLOYEE BENEFITS The following tables show the components of net periodic benefit cost (credit) for our benefit plans. Pension Benefits Three Months Ended March 31 (in millions) 2023 2022 Service cost $ 2.8 $ 3.6 Interest cost 11.9 8.2 Expected return on plan assets (16.4) (17.9) Amortization of net actuarial loss 1.9 7.3 Net periodic benefit cost $ 0.2 $ 1.2 OPEB Benefits Three Months Ended March 31 (in millions) 2023 2022 Service cost $ 0.7 $ 1.0 Interest cost 1.9 1.4 Expected return on plan assets (3.4) (4.4) Amortization of prior service credit (0.2) (0.3) Amortization of net actuarial gain (2.2) (3.0) Net periodic benefit credit $ (3.2) $ (5.3) During the three months ended March 31, 2023, we made contributions and payments of $3.2 million related to our pension plans and an insignificant amount related to our OPEB plans. We expect to make contributions and payments of $0.2 million related to our OPEB plans and an insignificant amount related to our pension plans during the remainder of 2023, dependent upon various factors affecting us, including our liquidity position and possible tax law changes. Effective January 1, 2023, the PSCW approved escrow accounting for pension and OPEB costs. As a result, as of March 31, 2023, we recorded a $0.2 million regulatory asset for pension costs and a $1.3 million regulatory asset for OPEB costs. The above tables do not reflect any adjustments for the creation of these regulatory assets. |
SEGMENT INFORMATION
SEGMENT INFORMATION | 3 Months Ended |
Mar. 31, 2023 | |
Segment Reporting [Abstract] | |
SEGMENT INFORMATION | SEGMENT INFORMATIONWe use net income attributed to common shareholder to measure segment profitability and to allocate resources to our business. At March 31, 2023, we reported two segments, which are described below. Our utility segment includes our electric utility operations, including steam operations, and our natural gas utility operations. • Our electric utility operations are engaged in the generation, distribution, and sale of electricity to customers in southeastern Wisconsin (including metropolitan Milwaukee), east central Wisconsin, and northern Wisconsin. In addition, our steam operations produce, distribute, and sell steam to customers in metropolitan Milwaukee. • 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 in southeastern, east central, and northern Wisconsin. No significant items were reported in the other segment during the three months ended March 31, 2023 and 2022. All of our operations and assets are located within the United States. |
VARIABLE INTEREST ENTITIES
VARIABLE INTEREST ENTITIES | 3 Months Ended |
Mar. 31, 2023 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
VARIABLE INTEREST ENTITIES | VARIABLE INTEREST ENTITIES The primary beneficiary of a VIE must consolidate the entity's assets and liabilities. In addition, certain disclosures are required for significant interest holders in VIEs. We assess our relationships with potential VIEs, such as our coal suppliers, natural gas suppliers, coal transporters, natural gas transporters, and other counterparties related to PPAs, investments, and joint ventures. In making this assessment, we consider, along with other factors, the potential that our contracts or other arrangements provide subordinated financial support, the obligation to absorb the entity's losses, the right to receive residual returns of the entity, and the power to direct the activities that most significantly impact the entity's economic performance. WEPCo Environmental Trust Finance I, LLC In November 2020, the PSCW issued a financing order approving the securitization of $100 million of undepreciated environmental control costs related to our retired Pleasant Prairie power plant, the carrying costs accrued on the $100 million during the securitization process, and the related financing fees. The financing order also authorized us to form WEPCo Environmental Trust, a bankruptcy-remote special purpose entity, for the sole purpose of issuing ETBs to recover the costs approved in the financing order. WEPCo Environmental Trust is our wholly owned subsidiary. In May 2021, WEPCo Environmental Trust issued ETBs and used the proceeds to acquire environmental control property from us. The environmental control property is recorded as a regulatory asset on our balance sheets and includes the right to impose, collect, and receive a non-bypassable environmental control charge from our retail electric distribution customers until the ETBs are paid in full and all financing costs have been recovered. The ETBs are secured by the environmental control property. Cash collections from the environmental control charge and funds on deposit in trust accounts are the sole sources of funds to satisfy the debt obligation. The bondholders have no recourse to us or any of our affiliates. We act as the servicer of the environmental control property on behalf of WEPCo Environmental Trust and are responsible for metering, calculating, billing, and collecting the environmental control charge. As necessary, we are authorized to implement periodic adjustments of the environmental control charge. The adjustments are designed to ensure the timely payment of principal, interest, and other ongoing financing costs. We remit all collections of the environmental control charge to WEPCo Environmental Trust's indenture trustee. WEPCo Environmental Trust is a VIE primarily because its equity capitalization is insufficient to support its operations. As described above, we have the power to direct the activities that most significantly impact WEPCo Environmental Trust's economic performance. Therefore, we are considered the primary beneficiary of WEPCo Environmental Trust, and consolidation is required. The following table summarizes the impact of WEPCo Environmental Trust on our balance sheet. (in millions) March 31, 2023 December 31, 2022 Assets Other current assets (restricted cash) $ 5.1 $ 3.0 Regulatory assets 90.9 92.4 Other long-term assets (restricted cash) 0.6 0.6 Liabilities Current portion of long-term debt 8.9 8.9 Accounts payable 0.1 — Other current liabilities (accrued interest) 0.5 0.1 Long-term debt 94.1 94.1 Power Purchase Commitment On May 31, 2022, our PPA with LSP-Whitewater Limited Partnership that represented a variable interest expired. This agreement was for 236.5 MWs of firm capacity from a natural gas-fired cogeneration facility, and we accounted for it as a finance lease. |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 3 Months Ended |
Mar. 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. Our minimum future commitments related to these purchase obligations as of March 31, 2023, were approximately $7.9 billion. 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 sulfur dioxide, 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. Air Quality Cross State Air Pollution Rule – Good Neighbor Plan In March 2023, the EPA issued its final Good Neighbor Plan, which requires significant reductions in ozone-forming emissions of NOx from power plants and industrial facilities. The rule took effect for the 2023 ozone season. After review of the final rule, we believe that we are well positioned to meet the requirements. Our planned 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 may be subject to the emission limits and operational requirements of the rule beginning in 2026. The EPA has exempted LDCs from the final rule but included new language defining an LDC that we are still evaluating. 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, which could have an adverse effect on our utilities. The EPA is also seeking comments on an even lower limit of 0.006 lb/MMBtu. We are still evaluating the proposed rule revisions to understand the impacts, if any, to 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 a previously issued EPA staff-written Integrated Science Assessment for ozone which supported the reconsideration of the 2015 standard. The EPA staff issued a draft Policy Assessment in March 2023 in support of revisiting the 2020 decision to retain the 2015 ozone standards with no changes and indicated that they intend to publish their reconsideration in early 2024, with an anticipated final rule by early 2025. 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. In April 2022, the EPA proposed to find that the Milwaukee and Chicago, IL-IN-WI nonattainment areas did not meet the marginal attainment deadline of August 2021 and should be adjusted to "moderate" nonattainment status for the 2015 standard. In October 2022, the EPA published its final reclassifications from "marginal" to "moderate" for these areas, effective November 7, 2022. Accordingly, the WDNR was required to submit a SIP revision to the EPA to address the moderate nonattainment status, which it did in December 2022. 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 . 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 is also taking comments on the full range (between 8 and 11 µg/m 3 ) included in the CASAC's latest report. The EPA has announced it plans to issue a final decision on the reconsideration in summer 2023. All counties within our service territory are in attainment with the current 2012 standards. If the EPA lowers the annual standard to 10 or 11 µg/m 3 , our generating facilities within our service territory should remain in attainment. If the EPA lowers it to below 10 µg/m 3 , there could be some nonattainment areas that may affect permitting of some smaller ancillary equipment located at our facilities. After finalization of the rule, the WDNR will need to draft and submit a SIP for the EPA's approval. Climate Change The Affordable Clean Energy rule, which replaced the Clean Power Plan, was vacated by the D.C. Circuit Court of Appeals in January 2021. In October 2021, the Supreme Court agreed to review the D.C. Circuit Court's ruling and in June 2022, the Supreme Court issued its decision. The Supreme Court found that the EPA may regulate GHGs under section 111 of the Clean Air Act but cannot rely on generation shifting to lower carbon emitting sources to do so. A new GHG replacement rule for existing sources is under review by the OMB. In January 2021, the EPA finalized a rule to revise the New Source Performance Standards for GHG emissions from new, modified, and reconstructed fossil-fueled power plants; however, it was vacated by the D.C. Circuit Court of Appeals in April 2021. A new GHG replacement rule for new, modified, and reconstructed sources is under review by the OMB. WEC Energy Group continues to move forward on the ESG Progress Plan, which is heavily focused on reducing GHG emissions. The EPA released proposed regulations for the Mandatory Greenhouse Gas Reporting Rule, 40 Code of Federal Regulations Part 98, in June 2022. The proposed revisions could impact the reporting required of our local natural gas distribution operations and underground natural gas storage facilities. The EPA intends to issue a new supplemental notice of proposed rulemaking in the second quarter of 2023 with an anticipated final rule to be issued in the fourth quarter of 2023 for all subparts of this rule. The 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 1,500 MWs of coal-fired generation since the beginning of 2018. Through its ESG Progress Plan, WEC Energy Group expects to retire approximately 1,500 MWs of additional fossil-fueled generation by the end of 2026, which includes the planned retirements in 2024-2025 of OCPP Units 5-8. See Note 6, Property, Plant, and Equipment, for more information on the timing of the 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 making 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 net-zero CO 2 emissions 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, except for the ERGS units, which were permitted and received a final BTA determination under the rules governing new facilities. 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 a final BTA determination for Valley power plant. We have received interim BTA determinations for PWGS and OCPP Units 5-8. We believe that existing technology installed at the OCPP facility meets the BTA requirements; however, depending on the timing of the permit reissuance, all four generating units at the OCPP may be retired prior to the WDNR making a final BTA decision, anticipated in 2025. We are engaged in discussions with the WDNR regarding the current status of the BTA determination at PWGS. There is uncertainty about whether existing technology meets all of the WDNR's BTA requirements. We will not be in a position to determine what, if any, modifications may be needed at PWGS until the WDNR issues the WPDES permit renewal for PWGS, expected during the second quarter of 2023. As a result of past capital investments completed to address Section 316(b) compliance, we believe our fleet overall is well positioned to continue to meet this regulation. 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 and wet FGD wastewaters at existing facilities and created new requirements for several types of power plant wastewaters. The two new requirements that affect us relate to discharge limits for BATW and wet FGD wastewater. 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. Through 2023, we expect that compliance costs associated with the ELG rule will require $100 million in capital investment. A $10 million BATW modification to OC 7 and OC 8 was completed and placed in-service in mid-2021, and in December 2021, the PSCW issued a Certificate of Authority approving the $90 million ERGS FGD wastewater treatment system modification. The BATW modifications do not require PSCW approval prior to construction. All of these ELG required projects are either in-service or are on track for completion by the WPDES permit deadline in December 2023. 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) FGD wastewater; 3) CCR leachate; and 4) legacy wastewaters. The most significant proposed ELG rule change is a ZLD requirement for FGD wastewater. Under the proposed rule, this new ZLD requirement must be met by a date determined by the WDNR that is as soon as possible beginning 60 days following publication of the final rule, but no later than December 31, 2029. The proposed rule would also create a subcategory for "early adopters" that have already installed a compliant biological treatment system by the date of the proposed rule (March 29, 2023). Early adopters would not be required to install further FGD wastewater treatment, provided the facility owner also agrees to permanently cease combustion of coal by December 31, 2032. Although we are currently completing a $90 million biological treatment system at ERGS, which we expect to be complete later this year, the expected timing of the project's completion would not comply with the deadline imposed by the EPA to qualify for early adopter status. In addition, we do not believe that, upon its completion, the biological treatment system would be compliant with FGD wastewater treatment requirements as proposed. We are assessing the potential impact, as well as working with the Edison Electric Institute to submit comments to the EPA, regarding this proposed rule revision. If the supplemental ELG rule is finalized as proposed, we anticipate that our coal fueled facilities either meet, or will meet, the proposed rule provisions that apply to BATW. By the end of 2023, we anticipate ERGS and OCPP Units 5 and 6 will have compliant dry bottom ash transport systems. At this time, we do not anticipate significant costs related to complying with the proposed rule as it relates to CCR leachate and legacy wastewater. Waters of the United States In January 2023, the EPA and the United States Army Corps of Engineers together released a final rule revising the definition of WOTUS. This rule became effective on March 20, 2023. The final rule states that it is based on the pre-2015 definition of "waters of the United States." The pre-2015 approach involves applying factors established through case law and agency precedents to determine whether a wetland or surface drainage feature is subject to federal jurisdiction. The recent rulemaking could be affected by a significant pending Supreme Court case involving WOTUS determination. In October 2022, the Supreme Court heard oral arguments in a case, Sackett v. Environmental Protection Agency , to evaluate the proper test for determining whether wetlands are WOTUS. A decision by the Supreme Court is expected during the second quarter of 2023. At this point, our projects requiring federal permits are moving ahead, but we are monitoring these recent developments to better understand potential future impacts. The Sackett case, once decided, should provide some clarity regarding the definition of WOTUS. We will continue to monitor this litigation and any subsequent agency action. Land Quality Manufactured Gas Plant Remediation We have identified sites at which we or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. We are responsible for the environmental remediation of these sites. We are also working with the state of Wisconsin in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure. The future costs for detailed site investigation, future remediation, and monitoring are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation. Historically, our regulators have allowed us to recover incurred costs, net of insurance recoveries and recoveries from potentially responsible parties, associated with the remediation of manufactured gas plant sites. Accordingly, we have established regulatory assets for costs associated with these sites. We have established the following regulatory assets and reserves for manufactured gas plant sites: (in millions) March 31, 2023 December 31, 2022 Regulatory assets $ 14.1 $ 14.6 Reserves for future environmental remediation (1) 10.3 10.3 (1) Recorded within other long-term liabilities on our balance sheets. Coal Combustion Residuals Rule In January 2023, the EPA released a notice regarding their intent to revise the CCR rule. The EPA is drafting regulations for CCR storage at inactive generating units or "legacy units." The EPA is also considering proposing corrective action requirements for all CCR contamination at any regulated facility, regardless of how or when the CCR was placed at such site. Our legacy units are currently regulated by the states in which they are located. The proposed rule is expected in summer 2023. In February 2023, the EPA published notice in the Federal Register of a proposed consent decree to resolve a citizen suit related to conducting a review of Resource Conservation and Recovery Act regulations pertaining to the CCR rule. We are still evaluating the proposed language to understand the impact, if any, to our operations. Enforcement and Litigation Matters We are involved in legal and administrative proceedings before various courts and agencies with respect to matters arising in the ordinary course of business. Although we are unable to predict the outcome of these matters, management believes that appropriate reserves have been established and that final settlement of these actions will not have a material impact on our financial condition or results of operations. |
SUPPLEMENTAL CASH FLOW INFORMAT
SUPPLEMENTAL CASH FLOW INFORMATION | 3 Months Ended |
Mar. 31, 2023 | |
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract] | |
SUPPLEMENTAL CASH FLOW INFORMATION | SUPPLEMENTAL CASH FLOW INFORMATION Non-Cash Transactions Three Months Ended March 31 (in millions) 2023 2022 Cash paid for interest, net of amount capitalized $ 94.2 $ 83.6 Significant non-cash investing and financing transactions: Accounts payable related to construction costs 46.2 51.4 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 to the total of these amounts shown on the statements of cash flows: (in millions) March 31, 2023 December 31, 2022 Cash and cash equivalents $ 11.4 $ 6.1 Restricted cash included in other current assets 5.1 3.0 Restricted cash included in other long-term assets 0.6 38.6 Cash, cash equivalents, and restricted cash $ 17.1 $ 47.7 Our restricted cash consisted of the following: • Cash on deposit in a financial institution that is restricted to satisfy the requirements of a debt agreement at WEPCo Environmental Trust. See Note 16, Variable Interest Entities, for more information. • Cash used during January 2023 to purchase a natural gas-fired cogeneration facility located in Whitewater, Wisconsin. This cash was included in other long-term assets at December 31, 2022. See Note 2, Acquisitions, for more information. |
NEW ACCOUNTING PRONOUNCEMENTS
NEW ACCOUNTING PRONOUNCEMENTS | 3 Months Ended |
Mar. 31, 2023 | |
Accounting Standards Update and Change in Accounting Principle [Abstract] | |
NEW ACCOUNTING PRONOUNCEMENTS | NEW ACCOUNTING PRONOUNCEMENTS Reference Rate Reform In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional expedients and exceptions to provide relief for applying GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met. The amendments apply only to contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform. Under ASU No. 2020-04, this relief was effective for all entities beginning 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, which extends the relief for applying GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform to December 31, 2024. We are currently evaluating the impact this guidance may have on our financial statements and related disclosures. |
GENERAL INFORMATION (Policies)
GENERAL INFORMATION (Policies) | 3 Months Ended |
Mar. 31, 2023 | |
Accounting policies | |
Consolidation | As used in these notes, the term "financial statements" refers to the condensed consolidated financial statements. This includes the income statements, balance sheets, statements of cash flows, and statements of equity, unless otherwise noted. In this report, when we refer to "the Company," "us," "we," "our," or "ours," we are referring to Wisconsin Electric Power Company and its subsidiary. On our financial statements, we consolidate VIEs of which we are the primary beneficiary. |
Basis of accounting | We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2022. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three months ended March 31, 2023, are not necessarily indicative of expected results for 2023 due to seasonal variations and other factors. In management's opinion, we have included all adjustments, normal and recurring in nature, necessary for a fair presentation of our financial results. |
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 March 31, 2023 and December 31, 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. |
Fair value measurements | Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods. Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. |
Derivative instruments | We use derivatives as part of our risk management program to manage the risks associated with the price volatility of purchased power, generation, and natural gas costs for the benefit of our customers. Our approach is non-speculative and designed to mitigate risk. Our regulated hedging programs are approved by the PSCW. We record derivative instruments on our balance sheets as an asset or liability 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. |
New accounting pronouncements | Reference Rate Reform In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional expedients and exceptions to provide relief for applying GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met. The amendments apply only to contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform. Under ASU No. 2020-04, this relief was effective for all entities beginning 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, which extends the relief for applying GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform to December 31, 2024. We are currently evaluating the impact this guidance may have on our financial statements and related disclosures. |
OPERATING REVENUES (Tables)
OPERATING REVENUES (Tables) - Utility segment | 3 Months Ended |
Mar. 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. Three Months Ended March 31 (in millions) 2023 2022 Wisconsin Electric Power Company Electric utility $ 843.9 $ 831.1 Natural gas utility 243.6 235.9 Total revenues from contracts with customers 1,087.5 1,067.0 Other operating revenues 4.4 5.0 Total operating revenues $ 1,091.9 $ 1,072.0 |
Revenues from contracts with customers | Electric | |
Disaggregation of Operating Revenues | |
Operating revenues disaggregated by revenue source | The following table disaggregates electric utility operating revenues by customer class: Three Months Ended March 31 (in millions) 2023 2022 Residential $ 357.4 $ 335.4 Small commercial and industrial 284.6 268.0 Large commercial and industrial 139.1 136.8 Other 5.7 5.4 Total retail revenues 786.8 745.6 Wholesale 11.7 20.6 Resale 33.4 51.0 Steam 11.0 12.1 Other utility revenues 1.0 1.8 Total electric utility operating revenues $ 843.9 $ 831.1 |
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 by customer class: Three Months Ended March 31 (in millions) 2023 2022 Residential $ 179.2 $ 165.7 Commercial and industrial 87.9 83.3 Total retail revenues 267.1 249.0 Transportation 6.8 5.6 Other utility revenues (1) (30.3) (18.7) Total natural gas utility operating revenues $ 243.6 $ 235.9 (1) Includes the revenues subject to our purchased gas recovery mechanism. During both quarters, we over-collected natural gas costs due to these costs being lower than what was anticipated in rates. |
Other operating revenues | |
Disaggregation of Operating Revenues | |
Operating revenues disaggregated by revenue source | Other operating revenues consist primarily of the following: Three Months Ended March 31 (in millions) 2023 2022 Late payment charges $ 3.7 $ 3.5 Rental revenues 0.4 0.9 Alternative revenues (1) 0.3 0.6 Total other operating revenues $ 4.4 $ 5.0 (1) See Note 1(d), Operating Revenues, in our 2022 Annual Report on Form 10-K for more information on alternative revenues. |
CREDIT LOSSES (Tables)
CREDIT LOSSES (Tables) | 3 Months Ended |
Mar. 31, 2023 | |
Credit Loss [Abstract] | |
Schedule of gross receivables and related allowances for credit losses | We have included a table below that shows our gross third-party receivable balances and related allowance for credit losses. (in millions) March 31, 2023 December 31, 2022 Accounts receivable and unbilled revenues $ 649.2 $ 632.3 Allowance for credit losses 53.7 49.7 Accounts receivable and unbilled revenues, net (1) $ 595.5 $ 582.6 Total accounts receivable, net – past due greater than 90 days (1) $ 39.3 $ 35.8 Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1) 98.5 % 97.5 % |
Rollforward of the allowances for credit losses | A rollforward of the allowance for credit losses is included below: Three Months Ended March 31 (in millions) 2023 2022 Balance at January 1 $ 49.7 $ 51.4 Provision for credit losses 6.6 6.1 Provision for credit losses deferred for future recovery or refund 13.8 7.1 Write-offs charged against the allowance (20.3) (18.8) Recoveries of amounts previously written off 3.9 6.0 Balance at March 31 $ 53.7 $ 51.8 |
REGULATORY ASSETS AND LIABILI_2
REGULATORY ASSETS AND LIABILITIES (Tables) | 3 Months Ended |
Mar. 31, 2023 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Schedule of regulatory assets | (in millions) March 31, 2023 December 31, 2022 Regulatory assets Finance leases $ 1,083.7 $ 1,072.0 Plant retirement related items 623.4 632.7 Income tax related items 379.0 382.1 Pension and OPEB costs 334.2 337.2 System support resource 120.9 123.5 Securitization 90.9 92.4 Derivatives 80.3 40.3 Asset retirement obligations 41.2 41.1 Uncollectible expense 30.2 16.4 Energy efficiency programs 16.5 17.7 We Power generation 12.1 21.6 Other, net 42.0 40.5 Total regulatory assets $ 2,854.4 $ 2,817.5 |
Schedule of regulatory liabilities | (in millions) March 31, 2023 December 31, 2022 Regulatory liabilities Removal costs $ 729.0 $ 718.1 Income tax related items 708.1 716.1 Pension and OPEB benefits 143.4 144.4 Energy costs refundable through rate adjustments (1) 32.8 1.8 Electric transmission costs 8.3 0.2 Derivatives 1.8 39.1 Other, net 20.5 19.1 Total regulatory liabilities $ 1,643.9 $ 1,638.8 Balance sheet presentation Other current liabilities $ 32.4 $ 1.4 Regulatory liabilities 1,611.5 1,637.4 Total regulatory liabilities $ 1,643.9 $ 1,638.8 (1) The increase in these regulatory liabilities was primarily due to lower natural gas costs incurred during the first quarter of 2023, compared to what was anticipated in rates. |
SHORT-TERM DEBT AND LINES OF _2
SHORT-TERM DEBT AND LINES OF CREDIT (Tables) | 3 Months Ended |
Mar. 31, 2023 | |
Short-Term Debt [Abstract] | |
Schedule of short-term borrowings and weighted-average interest rates | The following table shows our short-term borrowings and their corresponding weighted-average interest rates: (in millions, except percentages) March 31, 2023 December 31, 2022 Commercial paper Amount outstanding $ 127.5 $ 460.7 Weighted-average interest rate on amounts outstanding 5.01 % 4.59 % |
Schedule of revolving credit facility 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 available capacity under this facility: (in millions) Maturity March 31, 2023 Revolving credit facility September 2026 $ 500.0 Less: Letters of credit issued inside credit facility 1.0 Commercial paper outstanding 127.5 Available capacity under existing credit facility $ 371.5 |
MATERIALS, SUPPLIES, AND INVE_2
MATERIALS, SUPPLIES, AND INVENTORIES (Tables) | 3 Months Ended |
Mar. 31, 2023 | |
Inventory Disclosure [Abstract] | |
Schedule of inventory | Our inventory consisted of: (in millions) March 31, 2023 December 31, 2022 Materials and supplies $ 158.4 $ 150.6 Fossil fuel 61.1 62.7 Natural gas in storage 19.3 79.6 Total $ 238.8 $ 292.9 |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 3 Months Ended |
Mar. 31, 2023 | |
Income Tax Disclosure [Abstract] | |
Schedule of effective income tax rate reconciliation | The provision for income taxes 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: Three Months Ended March 31, 2023 Three Months Ended March 31, 2022 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Statutory federal income tax $ 32.4 21.0 % $ 39.1 21.0 % State income taxes net of federal tax benefit 9.3 6.0 % 11.6 6.2 % Federal excess deferred tax amortization (5.3) (3.5) % (7.5) (4.0) % PTCs (5.1) (3.3) % (0.5) (0.3) % AFUDC - Equity (2.2) (1.4) % (1.3) (0.7) % Domestic production activities deferral 1.6 1.0 % 2.0 1.1 % Other, net 2.0 1.3 % 4.1 2.2 % Total income tax expense $ 32.7 21.1 % $ 47.5 25.5 % |
FAIR VALUE MEASUREMENTS (Tables
FAIR VALUE MEASUREMENTS (Tables) | 3 Months Ended |
Mar. 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: March 31, 2023 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 0.1 $ 0.7 $ — $ 0.8 FTRs — — 0.8 0.8 Coal contracts — 0.3 — 0.3 Total derivative assets $ 0.1 $ 1.0 $ 0.8 $ 1.9 Derivative liabilities Natural gas contracts $ 58.0 $ 0.4 $ — $ 58.4 Coal contracts — 14.1 — 14.1 Total derivative liabilities $ 58.0 $ 14.5 $ — $ 72.5 December 31, 2022 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 1.6 $ 2.5 $ — $ 4.1 FTRs — — 2.0 2.0 Coal contracts — 32.7 — 32.7 Total derivative assets $ 1.6 $ 35.2 $ 2.0 $ 38.8 Derivative liabilities Natural gas contracts $ 29.3 $ 0.7 $ — $ 30.0 |
Reconciliation of changes in fair value of items categorized as level 3 measurements | The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy: Three Months Ended March 31 (in millions) 2023 2022 Balance at the beginning of the period $ 2.0 $ 1.0 Settlements (1.2) (0.6) Balance at the end of the period $ 0.8 $ 0.4 |
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 were not recorded at fair value: March 31, 2023 December 31, 2022 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock $ 30.4 $ 23.1 $ 30.4 $ 22.7 Long-term debt, including current portion 3,361.1 3,237.0 3,360.4 3,143.2 |
DERIVATIVE INSTRUMENTS (Tables)
DERIVATIVE INSTRUMENTS (Tables) | 3 Months Ended |
Mar. 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 are designated as hedging instruments. March 31, 2023 December 31, 2022 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Current Natural gas contracts $ 0.8 $ 57.6 $ 4.1 $ 28.8 FTRs 0.8 — 2.0 — Coal contracts 0.2 9.1 17.6 — Total current 1.8 66.7 23.7 28.8 Long-term Natural gas contracts — 0.8 — 1.2 Coal contracts 0.1 5.0 15.1 — Total long-term 0.1 5.8 15.1 1.2 Total $ 1.9 $ 72.5 $ 38.8 $ 30.0 |
Schedule of estimated notional volumes and realized gains and losses | Our estimated notional sales volumes and realized gains and losses were as follows: Three Months Ended March 31, 2023 Three Months Ended March 31, 2022 (in millions) Volumes Gains (Losses) Volumes Gains Natural gas contracts 18.9 Dth $ (29.2) 18.7 Dth $ 8.2 FTRs 4.9 MWh 0.1 5.0 MWh 0.2 Total $ (29.1) $ 8.4 |
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: March 31, 2023 December 31, 2022 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 1.9 $ 72.5 $ 38.8 $ 30.0 Gross amount not offset on the balance sheet (0.2) (58.1) (1) (1.8) (29.5) (2) Net amount $ 1.7 $ 14.4 $ 37.0 $ 0.5 (1) Includes cash collateral posted of $57.9 million. (2) Includes cash collateral posted of $27.7 million. |
EMPLOYEE BENEFITS (Tables)
EMPLOYEE BENEFITS (Tables) | 3 Months Ended |
Mar. 31, 2023 | |
Retirement Benefits [Abstract] | |
Schedule of net benefit cost (credit) | The following tables show the components of net periodic benefit cost (credit) for our benefit plans. Pension Benefits Three Months Ended March 31 (in millions) 2023 2022 Service cost $ 2.8 $ 3.6 Interest cost 11.9 8.2 Expected return on plan assets (16.4) (17.9) Amortization of net actuarial loss 1.9 7.3 Net periodic benefit cost $ 0.2 $ 1.2 OPEB Benefits Three Months Ended March 31 (in millions) 2023 2022 Service cost $ 0.7 $ 1.0 Interest cost 1.9 1.4 Expected return on plan assets (3.4) (4.4) Amortization of prior service credit (0.2) (0.3) Amortization of net actuarial gain (2.2) (3.0) Net periodic benefit credit $ (3.2) $ (5.3) |
VARIABLE INTEREST ENTITIES (Tab
VARIABLE INTEREST ENTITIES (Tables) | 3 Months Ended |
Mar. 31, 2023 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Schedule of balance sheet impact of WEPCo Environmental Trust | The following table summarizes the impact of WEPCo Environmental Trust on our balance sheet. (in millions) March 31, 2023 December 31, 2022 Assets Other current assets (restricted cash) $ 5.1 $ 3.0 Regulatory assets 90.9 92.4 Other long-term assets (restricted cash) 0.6 0.6 Liabilities Current portion of long-term debt 8.9 8.9 Accounts payable 0.1 — Other current liabilities (accrued interest) 0.5 0.1 Long-term debt 94.1 94.1 |
COMMITMENTS AND CONTINGENCIES (
COMMITMENTS AND CONTINGENCIES (Tables) | 3 Months Ended |
Mar. 31, 2023 | |
Commitments and Contingencies Disclosure [Abstract] | |
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: (in millions) March 31, 2023 December 31, 2022 Regulatory assets $ 14.1 $ 14.6 Reserves for future environmental remediation (1) 10.3 10.3 (1) Recorded within other long-term liabilities on our balance sheets. |
SUPPLEMENTAL CASH FLOW INFORM_2
SUPPLEMENTAL CASH FLOW INFORMATION (Tables) | 3 Months Ended |
Mar. 31, 2023 | |
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract] | |
Schedule of supplemental cash flow information | Three Months Ended March 31 (in millions) 2023 2022 Cash paid for interest, net of amount capitalized $ 94.2 $ 83.6 Significant non-cash investing and financing transactions: Accounts payable related to construction costs 46.2 51.4 |
Reconciliation Of Cash And Restricted Cash | The following table reconciles the cash, cash equivalents, and restricted cash amounts reported within the balance sheets to the total of these amounts shown on the statements of cash flows: (in millions) March 31, 2023 December 31, 2022 Cash and cash equivalents $ 11.4 $ 6.1 Restricted cash included in other current assets 5.1 3.0 Restricted cash included in other long-term assets 0.6 38.6 Cash, cash equivalents, and restricted cash $ 17.1 $ 47.7 |
GENERAL INFORMATION - GENERAL (
GENERAL INFORMATION - GENERAL (Details) customer in Millions | Mar. 31, 2023 customer |
Electric | |
Product Information [Line Items] | |
Number Of Customers | 1.2 |
Natural gas | |
Product Information [Line Items] | |
Number Of Customers | 0.5 |
ACQUISITIONS - WEST RIVERSIDE (
ACQUISITIONS - WEST RIVERSIDE (Details) - West Riverside Energy Center $ in Millions | 1 Months Ended |
Feb. 28, 2023 USD ($) MW | |
Asset Acquisition [Line Items] | |
Capacity of generation unit (in megawatts) | MW | 100 |
Asset acquisition price, estimated | $ | $ 102 |
ACQUISITIONS - WHITEWATER (Deta
ACQUISITIONS - WHITEWATER (Details) - Whitewater cogeneration facility $ in Millions | 1 Months Ended | |
Jan. 31, 2023 USD ($) | Jan. 01, 2023 MW | |
Asset Acquisition [Line Items] | ||
Capacity of generation unit (in megawatts) | MW | 236.5 | |
Asset acquisition price, estimated | $ | $ 38 | |
Ownership (as a percentage) | 50% |
OPERATING REVENUES - DISAGGREGA
OPERATING REVENUES - DISAGGREGATION OF OPERATING REVENUES FOR UTILITY SEGMENT (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2023 | Mar. 31, 2022 | |
Disaggregation of Operating Revenues | ||
Total operating revenues | $ 1,091.9 | $ 1,072 |
Utility segment | ||
Disaggregation of Operating Revenues | ||
Total operating revenues | 1,091.9 | 1,072 |
Utility segment | Other operating revenues | ||
Disaggregation of Operating Revenues | ||
Other operating revenues | 4.4 | 5 |
Utility segment | Transferred over time | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 1,087.5 | 1,067 |
Utility segment | Electric | Transferred over time | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 843.9 | 831.1 |
Utility segment | Natural gas | Transferred over time | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | $ 243.6 | $ 235.9 |
OPERATING REVENUES - DISAGGRE_2
OPERATING REVENUES - DISAGGREGATION OF ELECTRIC UTILITY OPERATING REVENUES BY CUSTOMER CLASS (Details) - Revenues from contracts with customers - Utility segment - Transferred over time - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2023 | Mar. 31, 2022 | |
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | $ 1,087.5 | $ 1,067 |
Electric | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 843.9 | 831.1 |
Electric | Total retail | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 786.8 | 745.6 |
Electric | Residential | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 357.4 | 335.4 |
Electric | Small commercial and industrial | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 284.6 | 268 |
Electric | Large commercial and industrial | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 139.1 | 136.8 |
Electric | Other | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 5.7 | 5.4 |
Electric | Wholesale | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 11.7 | 20.6 |
Electric | Resale | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 33.4 | 51 |
Electric | Steam | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 11 | 12.1 |
Electric | Other utility | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | $ 1 | $ 1.8 |
OPERATING REVENUES - DISAGGRE_3
OPERATING REVENUES - DISAGGREGATION OF NATURAL GAS UTILITY OPERATING REVENUES BY CUSTOMER CLASS (Details) - Revenues from contracts with customers - Utility segment - Transferred over time - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2023 | Mar. 31, 2022 | |
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | $ 1,087.5 | $ 1,067 |
Natural gas | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 243.6 | 235.9 |
Natural gas | Total retail | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 267.1 | 249 |
Natural gas | Residential | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 179.2 | 165.7 |
Natural gas | Commercial and industrial | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 87.9 | 83.3 |
Natural gas | Transportation | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 6.8 | 5.6 |
Natural gas | Other utility | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | $ (30.3) | $ (18.7) |
OPERATING REVENUES - OTHER OPER
OPERATING REVENUES - OTHER OPERATING REVENUES (Details) - Utility segment - Other operating revenues - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2023 | Mar. 31, 2022 | |
Disaggregation of Operating Revenues | ||
Other operating revenues | $ 4.4 | $ 5 |
Late payment charges | ||
Disaggregation of Operating Revenues | ||
Other operating revenues | 3.7 | 3.5 |
Rental revenues | ||
Disaggregation of Operating Revenues | ||
Other operating revenues | 0.4 | 0.9 |
Alternative revenues | ||
Disaggregation of Operating Revenues | ||
Other operating revenues | $ 0.3 | $ 0.6 |
CREDIT LOSSES - GROSS RECEIVABL
CREDIT LOSSES - GROSS RECEIVABLES AND RELATED ALLOWANCES (Details) - USD ($) $ in Millions | Mar. 31, 2023 | Dec. 31, 2022 | Mar. 31, 2022 | Dec. 31, 2021 |
Utility segment | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Allowance for credit losses | $ 53.7 | $ 49.7 | $ 51.8 | $ 51.4 |
Utility segment | Third-party receivables | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable and unbilled revenues | 649.2 | 632.3 | ||
Allowance for credit losses | 53.7 | 49.7 | ||
Accounts receivable and unbilled revenues, net | 595.5 | 582.6 | ||
Total accounts receivable, net - past due greater than 90 days | $ 39.3 | $ 35.8 | ||
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms | 98.50% | 97.50% | ||
Amount of net accounts receivable with regulatory protections | $ 349.7 | |||
Percent of net accounts receivable with regulatory protections | 58.70% | |||
Other Segment | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable and unbilled revenues | $ 0 | $ 0 |
CREDIT LOSSES - ROLLFORWARD OF
CREDIT LOSSES - ROLLFORWARD OF ALLOWANCES (Details) - Utility segment - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2023 | Mar. 31, 2022 | |
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | ||
Balance at beginning of period | $ 49.7 | $ 51.4 |
Provision for credit losses | 6.6 | 6.1 |
Write-offs charged against the allowance | (20.3) | (18.8) |
Recovery of amounts previously written off | 3.9 | 6 |
Balance at end of period | 53.7 | 51.8 |
Change in allowance for credit losses | 4 | |
Uncollectible expense | ||
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | ||
Provision for credit losses deferred for future recovery or refund | $ 13.8 | $ 7.1 |
REGULATORY ASSETS AND LIABILI_3
REGULATORY ASSETS AND LIABILITIES - REGULATORY ASSETS (Details) - USD ($) $ in Millions | Mar. 31, 2023 | Dec. 31, 2022 |
Regulatory assets | ||
Total regulatory assets | $ 2,854.4 | $ 2,817.5 |
Finance leases | ||
Regulatory assets | ||
Total regulatory assets | 1,083.7 | 1,072 |
Plant retirement related items | ||
Regulatory assets | ||
Total regulatory assets | 623.4 | 632.7 |
Income tax related items | ||
Regulatory assets | ||
Total regulatory assets | 379 | 382.1 |
Pension and OPEB costs | ||
Regulatory assets | ||
Total regulatory assets | 334.2 | 337.2 |
System support resource | ||
Regulatory assets | ||
Total regulatory assets | 120.9 | 123.5 |
Securitization | ||
Regulatory assets | ||
Total regulatory assets | 90.9 | 92.4 |
Derivatives | ||
Regulatory assets | ||
Total regulatory assets | 80.3 | 40.3 |
Asset retirement obligations | ||
Regulatory assets | ||
Total regulatory assets | 41.2 | 41.1 |
Uncollectible expense | ||
Regulatory assets | ||
Total regulatory assets | 30.2 | 16.4 |
Energy efficiency programs | ||
Regulatory assets | ||
Total regulatory assets | 16.5 | 17.7 |
We Power generation | ||
Regulatory assets | ||
Total regulatory assets | 12.1 | 21.6 |
Other, net | ||
Regulatory assets | ||
Total regulatory assets | $ 42 | $ 40.5 |
REGULATORY ASSETS AND LIABILI_4
REGULATORY ASSETS AND LIABILITIES - REGULATORY LIABILITIES (Details) - USD ($) $ in Millions | Mar. 31, 2023 | Dec. 31, 2022 |
Regulatory liabilities | ||
Other current liabilities | $ 32.4 | $ 1.4 |
Regulatory liabilities | 1,611.5 | 1,637.4 |
Total regulatory liabilities | 1,643.9 | 1,638.8 |
Removal costs | ||
Regulatory liabilities | ||
Total regulatory liabilities | 729 | 718.1 |
Income tax related items | ||
Regulatory liabilities | ||
Total regulatory liabilities | 708.1 | 716.1 |
Pension and OPEB benefits | ||
Regulatory liabilities | ||
Total regulatory liabilities | 143.4 | 144.4 |
Energy costs refundable through rate adjustments | ||
Regulatory liabilities | ||
Total regulatory liabilities | 32.8 | 1.8 |
Electric transmission costs | ||
Regulatory liabilities | ||
Total regulatory liabilities | 8.3 | 0.2 |
Derivatives | ||
Regulatory liabilities | ||
Total regulatory liabilities | 1.8 | 39.1 |
Other, net | ||
Regulatory liabilities | ||
Total regulatory liabilities | $ 20.5 | $ 19.1 |
PROPERTY, PLANT, AND EQUIPMENT
PROPERTY, PLANT, AND EQUIPMENT (Details) $ in Millions | Mar. 31, 2023 USD ($) |
OCPP | |
Property, plant, and equipment | |
Net book value of plant to be retired | $ 812.9 |
SHORT-TERM DEBT AND LINES OF _3
SHORT-TERM DEBT AND LINES OF CREDIT - SHORT-TERM BORROWINGS (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2023 | Dec. 31, 2022 | |
Short-term borrowings | ||
Commercial paper outstanding | $ 127.5 | $ 460.7 |
Commercial paper | ||
Short-term borrowings | ||
Commercial paper outstanding | $ 127.5 | $ 460.7 |
Weighted-average interest rate on amounts outstanding | 5.01% | 4.59% |
Average amount outstanding during the period | $ 127.6 | |
Weighted-average interest rate during the period | 4.68% |
SHORT-TERM DEBT AND LINES OF _4
SHORT-TERM DEBT AND LINES OF CREDIT - REVOLVING CREDIT FACILITIES (Details) - USD ($) $ in Millions | Mar. 31, 2023 | Dec. 31, 2022 |
Revolving credit facility | ||
Commercial paper outstanding | $ 127.5 | $ 460.7 |
Available capacity under existing credit facility | 371.5 | |
Credit facility maturing September 2026 | ||
Revolving credit facility | ||
Revolving credit facility | 500 | |
Commercial paper | ||
Revolving credit facility | ||
Commercial paper outstanding | 127.5 | $ 460.7 |
Letter of Credit | ||
Revolving credit facility | ||
Letters of credit issued inside credit facility | $ 1 |
MATERIALS, SUPPLIES, AND INVE_3
MATERIALS, SUPPLIES, AND INVENTORIES (Details) - USD ($) $ in Millions | Mar. 31, 2023 | Dec. 31, 2022 |
Inventory Disclosure [Abstract] | ||
Materials and supplies | $ 158.4 | $ 150.6 |
Fossil fuel | 61.1 | 62.7 |
Natural gas in storage | 19.3 | 79.6 |
Total | $ 238.8 | $ 292.9 |
INCOME TAXES (Details)
INCOME TAXES (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2023 | Mar. 31, 2022 | |
Effective Income Tax Rate Reconciliation, Amount | ||
Statutory federal income tax, amount | $ 32.4 | $ 39.1 |
State income taxes net of federal tax benefit, amount | 9.3 | 11.6 |
Federal excess deferred tax amortization, amount | (5.3) | (7.5) |
PTCs, amount | (5.1) | (0.5) |
AFUDC-Equity, amount | (2.2) | (1.3) |
Domestic production activities deferral, amount | 1.6 | 2 |
Other, net, amount | 2 | 4.1 |
Total income tax expense, amount | $ 32.7 | $ 47.5 |
Effective Income Tax Rate Reconciliation, Percent | ||
Statutory federal income tax, percent | 21% | 21% |
State income taxes net of federal tax benefit, percent | 6% | 6.20% |
Federal excess deferred tax amortization, percent | (3.50%) | (4.00%) |
PTCs, percent | (3.30%) | (0.30%) |
AFUDC-Equity, percent | (1.40%) | (0.70%) |
Domestic production activities deferral, percent | 1% | 1.10% |
Other, net, percent | 1.30% | 2.20% |
Total income tax expense, percent | 21.10% | 25.50% |
FAIR VALUE MEASUREMENTS - ASSET
FAIR VALUE MEASUREMENTS - ASSETS AND LIABILITIES MEASURED ON A RECURRING BASIS (Details) - USD ($) $ in Millions | Mar. 31, 2023 | Dec. 31, 2022 |
Assets | ||
Derivative assets | $ 1.9 | $ 38.8 |
Liabilities | ||
Derivative liabilities | 72.5 | 30 |
Fair value measurements on a recurring basis | ||
Assets | ||
Derivative assets | 1.9 | 38.8 |
Liabilities | ||
Derivative liabilities | 72.5 | |
Fair value measurements on a recurring basis | Level 1 | ||
Assets | ||
Derivative assets | 0.1 | 1.6 |
Liabilities | ||
Derivative liabilities | 58 | |
Fair value measurements on a recurring basis | Level 2 | ||
Assets | ||
Derivative assets | 1 | 35.2 |
Liabilities | ||
Derivative liabilities | 14.5 | |
Fair value measurements on a recurring basis | Level 3 | ||
Assets | ||
Derivative assets | 0.8 | 2 |
Liabilities | ||
Derivative liabilities | 0 | |
Fair value measurements on a recurring basis | Natural gas contracts | ||
Assets | ||
Derivative assets | 0.8 | 4.1 |
Liabilities | ||
Derivative liabilities | 58.4 | 30 |
Fair value measurements on a recurring basis | Natural gas contracts | Level 1 | ||
Assets | ||
Derivative assets | 0.1 | 1.6 |
Liabilities | ||
Derivative liabilities | 58 | 29.3 |
Fair value measurements on a recurring basis | Natural gas contracts | Level 2 | ||
Assets | ||
Derivative assets | 0.7 | 2.5 |
Liabilities | ||
Derivative liabilities | 0.4 | 0.7 |
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 | 0.8 | 2 |
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 | 0.8 | 2 |
Fair value measurements on a recurring basis | Coal contracts | ||
Assets | ||
Derivative assets | 0.3 | 32.7 |
Liabilities | ||
Derivative liabilities | 14.1 | |
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 | 32.7 |
Liabilities | ||
Derivative liabilities | 14.1 | |
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 | 3 Months Ended | |
Mar. 31, 2023 | Mar. 31, 2022 | |
Level 3 rollforward | ||
Balance at the beginning of the period | $ 2 | $ 1 |
Settlements | (1.2) | (0.6) |
Balance at the end of the period | $ 0.8 | $ 0.4 |
FAIR VALUE MEASUREMENTS - FINAN
FAIR VALUE MEASUREMENTS - FINANCIAL INSTRUMENTS (Details) - USD ($) $ in Millions | Mar. 31, 2023 | Dec. 31, 2022 |
Financial instruments | ||
Preferred stock | $ 30.4 | $ 30.4 |
Carrying amount | ||
Financial instruments | ||
Preferred stock | 30.4 | 30.4 |
Long-term debt, including current portion | 3,361.1 | 3,360.4 |
Fair value | ||
Financial instruments | ||
Preferred stock | 23.1 | 22.7 |
Long-term debt, including current portion | $ 3,237 | $ 3,143.2 |
DERIVATIVE INSTRUMENTS - DERIVA
DERIVATIVE INSTRUMENTS - DERIVATIVE ASSETS AND LIABILITIES (Details) $ in Millions | Mar. 31, 2023 USD ($) Instruments | Dec. 31, 2022 USD ($) Instruments |
Derivative assets | ||
Current derivative assets | $ 1.8 | $ 23.7 |
Long-term derivative assets | 0.1 | 15.1 |
Total derivative assets | $ 1.9 | $ 38.8 |
Current derivative assets balance sheet location | Other | Other |
Long-term derivative assets balance sheet location | Other | Other |
Derivative liabilities | ||
Current derivative liabilities | $ 66.7 | $ 28.8 |
Long-term derivative liabilities | 5.8 | 1.2 |
Total derivative liabilities | $ 72.5 | $ 30 |
Long-term derivative liabilities balance sheet location | Other | Other |
Natural gas contracts | ||
Derivative assets | ||
Current derivative assets | $ 0.8 | $ 4.1 |
Long-term derivative assets | 0 | 0 |
Derivative liabilities | ||
Current derivative liabilities | 57.6 | 28.8 |
Long-term derivative liabilities | 0.8 | 1.2 |
FTRs | ||
Derivative assets | ||
Current derivative assets | 0.8 | 2 |
Derivative liabilities | ||
Current derivative liabilities | 0 | 0 |
Coal contracts | ||
Derivative assets | ||
Current derivative assets | 0.2 | 17.6 |
Long-term derivative assets | 0.1 | 15.1 |
Derivative liabilities | ||
Current derivative liabilities | 9.1 | 0 |
Long-term derivative liabilities | $ 5 | $ 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 | 3 Months Ended | |
Mar. 31, 2023 USD ($) MWh MMBTU | Mar. 31, 2022 USD ($) MWh MMBTU | |
Realized gains and losses | ||
Realized gains and losses on derivatives income statement location | Cost of sales | Cost of sales |
Gains (losses) | $ (29.1) | $ 8.4 |
Natural gas contracts | ||
Realized gains and losses | ||
Gains (losses) | $ (29.2) | $ 8.2 |
Notional sales volumes | ||
Notional sales volumes | MMBTU | 18.9 | 18.7 |
FTRs | ||
Realized gains and losses | ||
Gains (losses) | $ 0.1 | $ 0.2 |
Notional sales volumes | ||
Notional sales volumes | MWh | 4.9 | 5 |
DERIVATIVE INSTRUMENTS - BALANC
DERIVATIVE INSTRUMENTS - BALANCE SHEET OFFSETTING (Details) - USD ($) $ in Millions | Mar. 31, 2023 | Dec. 31, 2022 |
Cash collateral | ||
Collateral on deposit | $ 80.8 | $ 46.7 |
Offsetting derivative assets | ||
Gross amount recognized on the balance sheet | 1.9 | 38.8 |
Gross amount not offset on the balance sheet | (0.2) | (1.8) |
Net amount | 1.7 | 37 |
Offsetting derivative liabilities | ||
Gross amount recognized on the balance sheet | 72.5 | 30 |
Gross amount not offset on the balance sheet | (58.1) | (29.5) |
Net amount | 14.4 | 0.5 |
Cash collateral posted | $ 57.9 | $ 27.7 |
GUARANTEES (Details)
GUARANTEES (Details) $ in Millions | Mar. 31, 2023 USD ($) |
Standby letters of credit | |
Guarantees | |
Guarantees with expiration over 3 years | $ 26 |
EMPLOYEE BENEFITS-COSTS AND CON
EMPLOYEE BENEFITS-COSTS AND CONTRIBUTIONS (Details) - USD ($) $ in Millions | 3 Months Ended | ||
Mar. 31, 2023 | Mar. 31, 2022 | Dec. 31, 2022 | |
Components of net periodic benefit cost (credit) | |||
Regulatory assets | $ 2,854.4 | $ 2,817.5 | |
Pension Benefits | |||
Components of net periodic benefit cost (credit) | |||
Service cost | 2.8 | $ 3.6 | |
Interest cost | 11.9 | 8.2 | |
Expected return on plan assets | (16.4) | (17.9) | |
Amortization of net actuarial (gain) loss | 1.9 | 7.3 | |
Net periodic benefit (credit) cost | 0.2 | 1.2 | |
Contributions and payments related to pension and OPEB plans | 3.2 | ||
Pension Benefits | Pension and Other Postretirement Plans Cost | |||
Components of net periodic benefit cost (credit) | |||
Regulatory assets | 0.2 | ||
Other Postretirement Benefits | |||
Components of net periodic benefit cost (credit) | |||
Service cost | 0.7 | 1 | |
Interest cost | 1.9 | 1.4 | |
Expected return on plan assets | (3.4) | (4.4) | |
Amortization of prior service credit | (0.2) | (0.3) | |
Amortization of net actuarial (gain) loss | (2.2) | (3) | |
Net periodic benefit (credit) cost | (3.2) | $ (5.3) | |
Estimated future employer contributions for the remainder of the year | 0.2 | ||
Other Postretirement Benefits | Pension and Other Postretirement Plans Cost | |||
Components of net periodic benefit cost (credit) | |||
Regulatory assets | $ 1.3 |
SEGMENT INFORMATION (Details)
SEGMENT INFORMATION (Details) $ in Millions | 3 Months Ended | |
Mar. 31, 2023 USD ($) segment | Mar. 31, 2022 USD ($) | |
Segment Reporting [Abstract] | ||
Number of reportable segments | segment | 2 | |
Significant items reported in the other segment | $ | $ 0 | $ 0 |
VARIABLE INTEREST ENTITIES - WE
VARIABLE INTEREST ENTITIES - WEPCO ENVIRONMENTAL TRUST (Details) - USD ($) $ in Millions | 1 Months Ended | ||
Nov. 30, 2020 | Mar. 31, 2023 | Dec. 31, 2022 | |
Assets | |||
Other current assets (restricted cash) | $ 5.1 | $ 3 | |
Regulatory assets | 2,854.4 | 2,817.5 | |
Other long-term assets (restricted cash) | 0.6 | 38.6 | |
Liabilities | |||
Current portion of long-term debt | 8.9 | 8.9 | |
Long-term debt | 3,352.2 | 3,351.5 | |
WEPCo Environmental Trust | |||
Variable interest entities | |||
Securitization of environmental control costs related to Pleasant Prairie power plant | $ 100 | ||
Assets | |||
Other current assets (restricted cash) | 5.1 | 3 | |
Regulatory assets | 90.9 | 92.4 | |
Other long-term assets (restricted cash) | 0.6 | 0.6 | |
Liabilities | |||
Current portion of long-term debt | 8.9 | 8.9 | |
Accounts payable | 0.1 | 0 | |
Other current liabilities (accrued interest) | 0.5 | 0.1 | |
Long-term debt | $ 94.1 | $ 94.1 |
VARIABLE INTEREST ENTITIES - PO
VARIABLE INTEREST ENTITIES - POWER PURCHASE COMMITMENT (Details) $ in Millions | Jan. 01, 2023 USD ($) | May 31, 2022 MW |
Whitewater cogeneration facility | ||
Variable interest entities | ||
Ownership interest (as a percentage) | 50% | |
Power purchase commitment | ||
Variable interest entities | ||
Firm capacity from power purchase commitment (in megawatts) | MW | 236.5 | |
Residual guarantee associated with power purchase comitment | $ | $ 0 | |
Power purchase commitment | Whitewater cogeneration facility | ||
Variable interest entities | ||
Ownership interest (as a percentage) | 50% |
COMMITMENTS AND CONTINGENCIES -
COMMITMENTS AND CONTINGENCIES - UNCONDITIONAL PURCHASE OBLIGATIONS (Details) $ in Billions | Mar. 31, 2023 USD ($) |
Minimum future commitments for purchase obligations | |
Purchase obligations | $ 7.9 |
COMMITMENTS AND CONTINGENCIES_2
COMMITMENTS AND CONTINGENCIES - ENVIRONMENTAL MATTERS (Details) $ in Millions | 1 Months Ended | 3 Months Ended | 15 Months Ended | ||||
Apr. 30, 2023 MMBTU | Jan. 31, 2023 micrograms | Dec. 31, 2020 performance_obligations micrograms | Mar. 31, 2023 USD ($) micrograms MW performance_obligations generating_units numberOfRevisions | Mar. 31, 2019 MW | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | |
Manufactured gas plant remediation | |||||||
Regulatory assets | $ | $ 2,854.4 | $ 2,817.5 | |||||
Cross State Air Pollution Rule - Good Neighbor Plan | Electric | Maximum | |||||||
Air quality | |||||||
RICE unit megawatts | MW | 25 | ||||||
Mercury and Air Toxics Standards | Electric | Subsequent event | |||||||
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 opinions on | MMBTU | 0.006 | ||||||
National Ambient Air Quality Standards | Electric | |||||||
Air quality | |||||||
The EPA issued a draft policy assessment in support of revisiting the decision to make no changes to the 2015 Ozone standards | numberOfRevisions | 0 | ||||||
Number of revisions necessary to meet the 2012 standard for particulate matter | performance_obligations | 0 | ||||||
Current number of micrograms per cubic meter that particulate matter needs to be below | 12 | ||||||
Current number of micrograms per cubic under 24-hour standard that fine particulate matter needs to be below | 35 | ||||||
Lowest limit that will cause nonattainment | 10 | ||||||
National Ambient Air Quality Standards | Electric | Maximum | |||||||
Air quality | |||||||
Proposed primary (health-based) annual standard | 10 | ||||||
The EPA is taking comments on this full range of micrograms per cubic meter | 11 | ||||||
New possible number of micrograms per cubic meter that particulate matter may be lowered to | 11 | ||||||
National Ambient Air Quality Standards | Electric | Minimum | |||||||
Air quality | |||||||
Proposed primary (health-based) annual standard | 9 | ||||||
The EPA is taking comments on this full range of micrograms per cubic meter | 8 | ||||||
New possible number of micrograms per cubic meter that particulate matter may be lowered to | 10 | ||||||
Climate Change | Electric | |||||||
Air quality | |||||||
Capacity of coal-fired generation retired, in megawatts | MW | 1,500 | ||||||
Capacity of fossil-fueled generation to be retired by the end of 2026, in megawatts | MW | 1,500 | ||||||
Company goal for percent carbon emission reduction below 2005 levels by the end of 2025 | 60% | ||||||
Company goal for percentage of carbon emission reduction below 2005 levels by the end of 2030 | 80% | ||||||
Clean Water Act Cooling Water Intake Structure Rule | Electric | |||||||
Water quality | |||||||
Number of generating units that may be retired | generating_units | 4 | ||||||
Steam Electric Effluent Limitation Guidelines | Electric | |||||||
Water quality | |||||||
Number of new ELG rule requirements that affect our electric utilities | performance_obligations | 2 | ||||||
Capital investment to achieve required discharge limits | $ | $ 100 | ||||||
Steam Electric Effluent Limitation Guidelines | Electric | OCPP Units 7 and 8 | |||||||
Water quality | |||||||
Capital investment to achieve required discharge limits | $ | $ 10 | ||||||
Steam Electric Effluent Limitation Guidelines | Electric | Elm Road Generating Station | |||||||
Water quality | |||||||
Capital investment to achieve required discharge limits | $ | 90 | ||||||
Manufactured Gas Plant Remediation | Natural gas | |||||||
Manufactured gas plant remediation | |||||||
Reserves for future environmental remediation (1) | $ | 10.3 | 10.3 | |||||
Manufactured Gas Plant Remediation | Natural gas | Environmental remediation costs | |||||||
Manufactured gas plant remediation | |||||||
Regulatory assets | $ | $ 14.1 | $ 14.6 |
SUPPLEMENTAL CASH FLOW INFORM_3
SUPPLEMENTAL CASH FLOW INFORMATION (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2023 | Mar. 31, 2022 | |
Supplemental Cash Flow Information [Abstract] | ||
Cash paid for interest, net of amount capitalized | $ 94.2 | $ 83.6 |
Significant non-cash investing and financing transactions: | ||
Accounts payable related to construction costs | $ 46.2 | $ 51.4 |
SUPPLEMENTAL CASH FLOW INFORM_4
SUPPLEMENTAL CASH FLOW INFORMATION - RECONCILIATION OF CASH AND CASH EQUIVALENTS AND RESTRICTED CASH (Details) - USD ($) $ in Millions | Mar. 31, 2023 | Dec. 31, 2022 | Mar. 31, 2022 | Dec. 31, 2021 |
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract] | ||||
Cash and cash equivalents | $ 11.4 | $ 6.1 | ||
Restricted cash included in other current assets | 5.1 | 3 | ||
Restricted cash included in other long-term assets | 0.6 | 38.6 | ||
Cash, cash equivalents, and restricted cash | $ 17.1 | $ 47.7 | $ 12.2 | $ 3 |