Cover Page
Cover Page - USD ($) $ in Billions | 12 Months Ended | ||
Dec. 31, 2022 | Jan. 31, 2023 | Jun. 30, 2022 | |
Cover [Abstract] | |||
Document Type | 10-K | ||
Document Annual Report | true | ||
Document Period End Date | Dec. 31, 2022 | ||
Document Transition Report | false | ||
Entity File Number | 001-09057 | ||
Entity Registrant Name | WEC ENERGY GROUP, INC. | ||
Entity Tax Identification Number | 39-1391525 | ||
Entity Incorporation, State or Country Code | WI | ||
Entity Address, Address Line One | 231 West Michigan Street | ||
Entity Address, Address Line Two | P.O. Box 1331 | ||
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 | ||
Title of 12(b) Security | Common Stock, $.01 Par Value | ||
Trading Symbol | WEC | ||
Security Exchange Name | NYSE | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Interactive Data Current | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false | ||
ICFR Auditor Attestation Flag | true | ||
Entity Shell Company | false | ||
Entity Public Float | $ 31.7 | ||
Entity Common Stock, Shares Outstanding | 315,434,531 | ||
Documents Incorporated by Reference | Portions of WEC Energy Group, Inc.'s Definitive Proxy Statement on Schedule 14A for its Annual Meeting of Shareholders, to be held on May 4, 2023, are incorporated by reference into Part III hereof. | ||
Entity Central Index Key | 0000783325 | ||
Current Fiscal Year End Date | --12-31 | ||
Document Fiscal Year Focus | 2022 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false |
Audit Information
Audit Information | 12 Months Ended |
Dec. 31, 2022 | |
Audit Information [Abstract] | |
Auditor Name | DELOITTE & TOUCHE LLP |
Auditor Location | Milwaukee, Wisconsin |
Auditor Firm ID | 34 |
Consolidated Income Statements
Consolidated Income Statements - USD ($) shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Income Statement [Abstract] | |||
Operating revenues | $ 9,597.4 | $ 8,316 | $ 7,241.7 |
Operating expenses | |||
Cost of sales | 4,358.9 | 3,311 | 2,319.5 |
Other operation and maintenance | 1,938 | 2,005.5 | 2,032.2 |
Depreciation and amortization | 1,122.6 | 1,074.3 | 975.9 |
Property and revenue taxes | 253.7 | 210.3 | 208 |
Total operating expenses | 7,673.2 | 6,601.1 | 5,535.6 |
Operating income | 1,924.2 | 1,714.9 | 1,706.1 |
Equity in earnings of transmission affiliates | 194.7 | 158.1 | 175.8 |
Other income, net | 128.8 | 133.2 | 79.5 |
Interest expense | 515.1 | 471.1 | 493.7 |
Loss on debt extinguishment | 0 | 36.3 | 38.4 |
Other expense | (191.6) | (216.1) | (276.8) |
Income before income taxes | 1,732.6 | 1,498.8 | 1,429.3 |
Income tax expense | 322.9 | 200.3 | 227.9 |
Net income | 1,409.7 | 1,298.5 | 1,201.4 |
Preferred stock dividends of subsidiary | 1.2 | 1.2 | 1.2 |
Net (income) loss attributed to noncontrolling interests | (0.4) | 3 | (0.3) |
Net income attributed to common shareholders | $ 1,408.1 | $ 1,300.3 | $ 1,199.9 |
Earnings per share | |||
Basic (in dollars per share) | $ 4.46 | $ 4.12 | $ 3.80 |
Diluted (in dollars per share) | $ 4.45 | $ 4.11 | $ 3.79 |
Weighted average common shares outstanding | |||
Basic (in shares) | 315.4 | 315.4 | 315.4 |
Diluted (in shares) | 316.1 | 316.3 | 316.5 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Statement of Other Comprehensive Income [Abstract] | |||
Net income | $ 1,409.7 | $ 1,298.5 | $ 1,201.4 |
Derivatives accounted for as cash flow hedges | |||
Net derivative gain (loss), net of tax expense (benefit) of $—, $0.2, and $(1.6), respectively | 0 | 0.6 | (4.3) |
Reclassification of realized net derivative (gain) loss to net income, net of tax | (0.3) | 0.9 | 1.5 |
Cash flow hedges, net | (0.3) | 1.5 | (2.8) |
Defined benefit plans | |||
Pension and OPEB adjustments arising during the period, net of tax expense (benefit) of $(1.3), $0.7, and $(0.2), respectively | (3.5) | 1.7 | (0.5) |
Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax | 0.2 | 0.4 | 0.6 |
Defined benefit plans, net | (3.3) | 2.1 | 0.1 |
Other comprehensive income (loss), net of tax | (3.6) | 3.6 | (2.7) |
Comprehensive income | 1,406.1 | 1,302.1 | 1,198.7 |
Preferred stock dividends of subsidiary | 1.2 | 1.2 | 1.2 |
Comprehensive (income) loss attributed to noncontrolling interests | (0.4) | 3 | (0.3) |
Comprehensive income attributed to common shareholders | $ 1,404.5 | $ 1,303.9 | $ 1,197.2 |
Consolidated Statements of Co_2
Consolidated Statements of Comprehensive Income (Parentheticals) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Statement of Other Comprehensive Income [Abstract] | |||
Tax expense (benefit) on derivative gain (loss) | $ 0 | $ 0.2 | $ (1.6) |
Tax expense (benefit) on pension and OPEB adjustments arising during the period | $ (1.3) | $ 0.7 | $ (0.2) |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Current assets | ||
Cash and cash equivalents | $ 28.9 | $ 16.3 |
Accounts receivable and unbilled revenues, net of reserves of $199.3 and $198.3, respectively | 1,818.4 | 1,505.7 |
Materials, supplies, and inventories | 807.1 | 635.8 |
Prepaid Taxes | 201.8 | 182.1 |
Other prepayments | 69.8 | 63.4 |
Other | 261.7 | 253.4 |
Current assets | 3,187.7 | 2,656.7 |
Long-term assets | ||
Property, plant, and equipment, net of accumulated depreciation and amortization of $10,383.8 and $9,889.3, respectively | 29,113.8 | 26,982.4 |
Regulatory assets (December 31, 2022 and December 31, 2021 include $92.4 and $100.7, respectively, related to WEPCo Environmental Trust) | 3,264.6 | 3,264.8 |
Equity investment in transmission affiliates | 1,909.2 | 1,789.4 |
Goodwill | 3,052.8 | 3,052.8 |
Pension and OPEB assets | 916.7 | 881.3 |
Other | 427.3 | 361.1 |
Long-term assets | 38,684.4 | 36,331.8 |
Total assets | 41,872.1 | 38,988.5 |
Current liabilities | ||
Short-term debt | 1,647.1 | 1,897 |
Current portion of long-term debt (December 31, 2022 and December 31, 2021 include $8.9 and $8.8, respectively, related to WEPCo Environmental Trust) | 881.2 | 169.4 |
Accounts payable | 1,198.1 | 1,005.7 |
Other | 884.6 | 680.9 |
Current liabilities | 4,611 | 3,753 |
Long-term liabilities | ||
Long-term debt (December 31, 2022 and December 31, 2021 include $94.1 and $102.7, respectively, related to WEPCo Environmental Trust) | 14,766.2 | 13,523.7 |
Deferred income taxes | 4,625.6 | 4,308.5 |
Deferred revenue, net | 370.7 | 389.2 |
Regulatory liabilities | 3,735.5 | 3,946 |
Environmental remediation liabilities | 499.6 | 532.6 |
Pension and OPEB obligations | 171.6 | 219 |
Other | 1,475.3 | 1,203.2 |
Long-term liabilities | 25,644.5 | 24,122.2 |
Commitments and contingencies (Note 24) | ||
Common shareholders' equity | ||
Common stock – $0.01 par value; 325,000,000 shares authorized; 315,434,531 shares outstanding | 3.2 | 3.2 |
Additional paid in capital | 4,115.2 | 4,138.1 |
Retained earnings | 7,265.3 | 6,775.1 |
Accumulated other comprehensive loss | (6.8) | (3.2) |
Common shareholders' equity | 11,376.9 | 10,913.2 |
Preferred stock of subsidiary | 30.4 | 30.4 |
Noncontrolling interests | 209.3 | 169.7 |
Total liabilities and equity | $ 41,872.1 | $ 38,988.5 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Statement of Financial Position [Abstract] | ||
Accounts receivable and unbilled revenues, reserves | $ 199.3 | $ 198.3 |
Property, plant, and equipment, accumulated depreciation and amortization, | $ 10,383.8 | $ 9,889.3 |
Common stock, par value | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 325,000,000 | 325,000,000 |
Common stock, shares outstanding | 315,434,531 | 315,434,531 |
Balance sheets | ||
Regulatory assets (December 31, 2022 and December 31, 2021 include $92.4 and $100.7, respectively, related to WEPCo Environmental Trust) | $ 3,264.6 | $ 3,264.8 |
Current portion of long-term debt (December 31, 2022 and December 31, 2021 include $8.9 and $8.8, respectively, related to WEPCo Environmental Trust) | 808.5 | 91 |
Long-term debt (December 31, 2022 and December 31, 2021 include $94.1 and $102.7, respectively, related to WEPCo Environmental Trust) | 14,655.7 | 13,472.4 |
WEPCo Environmental Trust | ||
Balance sheets | ||
Regulatory assets (December 31, 2022 and December 31, 2021 include $92.4 and $100.7, respectively, related to WEPCo Environmental Trust) | 92.4 | 100.7 |
Current portion of long-term debt (December 31, 2022 and December 31, 2021 include $8.9 and $8.8, respectively, related to WEPCo Environmental Trust) | 8.9 | 8.8 |
Long-term debt (December 31, 2022 and December 31, 2021 include $94.1 and $102.7, respectively, related to WEPCo Environmental Trust) | $ 94.1 | $ 102.7 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Operating activities | |||
Net income | $ 1,409.7 | $ 1,298.5 | $ 1,201.4 |
Reconciliation to cash provided by operating activities | |||
Depreciation and amortization | 1,122.6 | 1,074.3 | 975.9 |
Deferred income taxes and ITCs, net | 280.1 | 151.1 | 209.4 |
Contributions and payments related to pension and OPEB plans | (15.1) | (66.3) | (113.2) |
Equity income in transmission affiliates, net of distributions | (74.3) | (25.1) | (29.1) |
Net change in transmission regulatory assets and liabilities | (85.8) | 5.7 | 36.2 |
Net gain on disposition of assets | (66.2) | (6.2) | (3.5) |
Change in - | |||
Accounts receivable and unbilled revenues, net | (342.1) | (249.2) | 16.1 |
Materials, supplies, and inventories | (171.3) | (107.2) | 21.2 |
Amounts recoverable from customers | 60 | (82.3) | 0.9 |
Collateral on deposit | (108.1) | 4.6 | 15.6 |
Other current assets | (27.7) | 17.6 | (3.1) |
Accounts payable | 121.5 | 126.9 | (61.3) |
Other current liabilities | 126.9 | (17.2) | (41.2) |
Other, net | (169.5) | (92.5) | (29.3) |
Net cash provided by operating activities | 2,060.7 | 2,032.7 | 2,196 |
Investing Activities | |||
Capital expenditures | (2,314.9) | (2,252.8) | (2,238.8) |
Acquisition of Thunderhead, net of cash acquired of $0.5 | (382) | 0 | 0 |
Acquisition of Jayhawk | 0 | (119.9) | 0 |
Acquisition of Blooming Grove, net of restricted cash acquired of $24.1 | 0 | 0 | (364.6) |
Acquisition of Tatanka Ridge | 0 | 0 | (239.9) |
Acquisition of intangible assets | (19.2) | 0 | 0 |
Capital contributions to transmission affiliates | (45.5) | 0 | (21.2) |
Proceeds from the sale of assets | 69 | 21.9 | 20.3 |
Proceeds from the sale of investments held in rabbi trust | 15.4 | 18.7 | 56.2 |
Purchase of investments held in rabbi trust | 0 | 0 | (37.8) |
Payments for ATC's construction costs that will be reimbursed | (24.8) | (7) | (3.5) |
Reimbursement for ATC's construction costs | 10.2 | 0 | 1.1 |
Insurance proceeds received for property damage | 41.6 | 0 | 23.2 |
Other, net | 7.8 | 27.3 | (1.8) |
Net cash used in investing activities | (2,642.4) | (2,311.8) | (2,806.8) |
Financing Activities | |||
Exercise of stock options | 33.6 | 15.7 | 43.8 |
Purchase of common stock | (69.2) | (33.1) | (99.2) |
Dividends paid on common stock | (917.9) | (854.8) | (798) |
Issuance of long-term debt | 1,999.3 | 2,383.8 | 2,373.6 |
Retirement of long-term debt | (92.1) | (1,260.4) | (1,767) |
Issuance of short-term loan | 2.7 | 0.9 | 340 |
Repayment of short-term loan | 0 | (340) | 0 |
Change in commercial paper | (252.6) | 459.2 | 606.1 |
Payments for debt extinguishment and issuance costs | (15.6) | (67.2) | (55.8) |
Purchase of additional ownership interest in Upstream from noncontrolling interest | 0 | 0 | (31) |
Other, net | (11.8) | (10.1) | (11.4) |
Net cash provided by financing activities | 676.4 | 294 | 601.1 |
Net change in cash, cash equivalents, and restricted cash | 94.7 | 14.9 | (9.7) |
Cash, cash equivalents, and restricted cash at beginning of year | 87.5 | 72.6 | 82.3 |
Cash, cash equivalents, and restricted cash at end of year | $ 182.2 | $ 87.5 | $ 72.6 |
Consolidated Statement of Cash
Consolidated Statement of Cash Flows (Parenthetical) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended |
Dec. 31, 2020 | Dec. 31, 2022 | |
Blooming Grove | ||
Statement of Cash Flows | ||
Cash and restricted cash acquired | $ 24.1 | |
Thunderhead | ||
Statement of Cash Flows | ||
Cash and restricted cash acquired | $ 0.5 |
Consolidated Statements of Equi
Consolidated Statements of Equity - USD ($) $ in Millions | Total | Total common shareholders' equity | Common stock | Additional paid-in capital | Retained earnings | Accumulated other comprehensive income (loss) | Preferred stock of subsidiary | Noncontrolling interests |
Balance at Dec. 31, 2019 | $ 10,254.6 | $ 10,113.4 | $ 3.2 | $ 4,186.6 | $ 5,927.7 | $ (4.1) | $ 30.4 | $ 110.8 |
Equity | ||||||||
Net income attributed to common shareholders | 1,199.9 | 1,199.9 | 0 | 0 | 1,199.9 | 0 | 0 | 0 |
Net income (loss) attributed to noncontrolling interests | 0.3 | 0 | 0 | 0 | 0 | 0 | 0 | 0.3 |
Other comprehensive income (loss) | (2.7) | (2.7) | 0 | 0 | 0 | (2.7) | 0 | 0 |
Common stock dividends | (798) | (798) | 0 | 0 | (798) | 0 | 0 | 0 |
Exercise of stock options | 43.8 | 43.8 | 0 | 43.8 | 0 | 0 | 0 | 0 |
Purchase of common stock | (99.2) | (99.2) | 0 | (99.2) | 0 | 0 | 0 | 0 |
Purchase of additional ownership interest in Upstream from noncontrolling interest | (31) | 0 | 0 | 0 | 0 | 0 | 0 | (31) |
Acquisition of noncontrolling interests | 85 | 0 | 0 | 0 | 0 | 0 | 0 | 85 |
Distributions to noncontrolling interests | (2.7) | 0 | 0 | 0 | 0 | 0 | 0 | (2.7) |
Stock-based compensation and other | 12.5 | 12.5 | 0 | 12.5 | 0 | 0 | 0 | 0 |
Balance at Dec. 31, 2020 | 10,662.5 | 10,469.7 | 3.2 | 4,143.7 | 6,329.6 | (6.8) | 30.4 | 162.4 |
Equity | ||||||||
Net income attributed to common shareholders | 1,300.3 | 1,300.3 | 0 | 0 | 1,300.3 | 0 | 0 | 0 |
Net income (loss) attributed to noncontrolling interests | (3) | 0 | 0 | 0 | 0 | 0 | 0 | (3) |
Other comprehensive income (loss) | 3.6 | 3.6 | 0 | 0 | 0 | 3.6 | 0 | 0 |
Common stock dividends | (854.8) | (854.8) | 0 | 0 | (854.8) | 0 | 0 | 0 |
Exercise of stock options | 15.7 | 15.7 | 0 | 15.7 | 0 | 0 | 0 | 0 |
Purchase of common stock | (33.1) | (33.1) | 0 | (33.1) | 0 | 0 | 0 | 0 |
Acquisition of noncontrolling interests | 6.3 | 0 | 0 | 0 | 0 | 0 | 0 | 6.3 |
Capital contributions from noncontrolling interest | 7.6 | 0 | 0 | 0 | 0 | 0 | 0 | 7.6 |
Distributions to noncontrolling interests | (4.1) | 0 | 0 | 0 | 0 | 0 | 0 | (4.1) |
Stock-based compensation and other | 12.3 | 11.8 | 0 | 11.8 | 0 | 0 | 0 | 0.5 |
Balance at Dec. 31, 2021 | 11,113.3 | 10,913.2 | 3.2 | 4,138.1 | 6,775.1 | (3.2) | 30.4 | 169.7 |
Equity | ||||||||
Net income attributed to common shareholders | 1,408.1 | 1,408.1 | 0 | 0 | 1,408.1 | 0 | 0 | 0 |
Net income (loss) attributed to noncontrolling interests | 0.4 | 0 | 0 | 0 | 0 | 0 | 0 | 0.4 |
Other comprehensive income (loss) | (3.6) | (3.6) | 0 | 0 | 0 | (3.6) | 0 | 0 |
Common stock dividends | (917.9) | (917.9) | 0 | 0 | (917.9) | 0 | 0 | 0 |
Exercise of stock options | 33.6 | 33.6 | 0 | 33.6 | 0 | 0 | 0 | 0 |
Purchase of common stock | (69.2) | (69.2) | 0 | (69.2) | 0 | 0 | 0 | 0 |
Acquisition of noncontrolling interests | 42.5 | 0 | 0 | 0 | 0 | 0 | 0 | 42.5 |
Capital contributions from noncontrolling interest | 1.1 | 0 | 0 | 0 | 0 | 0 | 0 | 1.1 |
Distributions to noncontrolling interests | (4.3) | 0 | 0 | 0 | 0 | 0 | 0 | (4.3) |
Stock-based compensation and other | 12.6 | 12.7 | 0 | 12.7 | 0 | 0 | 0 | (0.1) |
Balance at Dec. 31, 2022 | $ 11,616.6 | $ 11,376.9 | $ 3.2 | $ 4,115.2 | $ 7,265.3 | $ (6.8) | $ 30.4 | $ 209.3 |
Consolidated Statements of Eq_2
Consolidated Statements of Equity (Parenthetical) - $ / shares | 3 Months Ended | 12 Months Ended | |||||
Dec. 31, 2022 | Sep. 30, 2022 | Jun. 30, 2022 | Mar. 31, 2022 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Statement of Stockholders' Equity [Abstract] | |||||||
Dividends per share (in dollars per share) | $ 0.7275 | $ 0.7275 | $ 0.7275 | $ 0.7275 | $ 2.91 | $ 2.71 | $ 2.53 |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2022 | |
Accounting Policies [Abstract] | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (a) Nature of Operations —WEC Energy Group serves approximately 1.6 million electric customers and 3.0 million natural gas customers, owns approximately 60% of ATC, and owns majority interests in multiple wind generating facilities as part of its non-utility energy infrastructure segment. As used in these notes, the term "financial statements" refers to the consolidated financial statements. This includes the income statements, statements of comprehensive income, balance sheets, statements of cash flows, and statements of equity, unless otherwise noted. On our financial statements, we consolidate our majority-owned subsidiaries which we control, and VIEs of which we are the primary beneficiary. We reflect noncontrolling interests for the portion of entities that we do not own as a component of consolidated equity separate from the equity attributable to our shareholders. The noncontrolling interests that we reported as equity on our balance sheet as of December 31, 2022 related to the minority interests held by third parties in the wind generating facilities that are included in our non-utility energy infrastructure segment. Our financial statements include the accounts of WEC Energy Group, a diversified energy holding company, and the accounts of our subsidiaries in the following reportable segments: • Wisconsin segment – Consists of WE, WPS, and WG, which are engaged primarily in the generation of electricity and the distribution of electricity and natural gas in Wisconsin; and UMERC, which generates electricity and distributes electricity and natural gas to customers located in the Upper Peninsula of Michigan. • Illinois segment – Consists of PGL and NSG, which are engaged primarily in the distribution of natural gas in Illinois. • Other states segment – Consists of MERC and MGU, which are engaged primarily in the distribution of natural gas in Minnesota and Michigan, respectively. • Electric transmission segment – Consists of our approximate 60% ownership interest in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions, and our approximate 75% ownership interest in ATC Holdco, which invests in transmission-related projects outside of ATC's traditional footprint. • Non-utility energy infrastructure segment – Consists of We Power, which is principally engaged in the ownership of electric power generating facilities for long-term lease to WE, and Bluewater, which owns underground natural gas storage facilities in Michigan. WECI, which holds our ownership interests in several wind generating facilities, is also included in this segment. See Note 2, Acquisitions, for more information on the recently acquired WECI renewable generating facilities. • Corporate and other segment – Consists of the WEC Energy Group holding company, the Integrys holding company, the PELLC holding company, Wispark, Wisvest, WECC, WBS, and also included the operations of PDL prior to the sale of its remaining solar facilities in the fourth quarter of 2020. See Note 3, Dispositions, for more information on the sale of these solar facilities. Investments in companies not controlled by us, but over which we have significant influence regarding the operating and financial policies of the investee, are accounted for using the equity method. We use the cumulative earnings approach for classifying distributions received in the statements of cash flows. Under the cumulative earnings approach, we compare the distributions received to cumulative equity method earnings since inception. Any distributions received up to the amount of cumulative equity earnings are considered a return on investment and classified in operating activities. Any excess distributions are considered a return of investment and classified in investing activities. (b) Basis of Presentation —We prepare our financial statements in conformity with GAAP. We make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates. (c) Cash and Cash Equivalents —Cash and cash equivalents include marketable debt securities with an original maturity of three months or less. (d) Operating Revenues —The following discussion includes our significant accounting policies related to operating revenues. For additional required disclosures on disaggregation of operating revenues, see Note 4, Operating Revenues. Revenues from Contracts with Customers Electric Utility Operating Revenues Electricity sales to residential and commercial and industrial customers are generally accomplished through requirements contracts, which provide for the delivery of as much electricity as the customer needs. These contracts represent discrete deliveries of electricity and consist of one distinct performance obligation satisfied over time, as the electricity is delivered and consumed by the customer simultaneously. For our Wisconsin residential and commercial and industrial customers and the majority of our Michigan residential and commercial and industrial customers, our performance obligation is bundled to consist of both the sale and the delivery of the electric commodity. In our Michigan service territory, a limited number of residential and commercial and industrial customers can purchase the commodity from a third party. In this case, the delivery of the electricity represents our sole performance obligation. The transaction price of the performance obligations for residential and commercial and industrial customers is valued using the rates, charges, terms, and conditions of service included in the tariffs of our regulated electric utilities, which have been approved by state regulators. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on the quantity of electricity delivered each month. Our retail electric rates in Wisconsin include base amounts for fuel and purchased power costs, which also impact our revenues. The electric fuel rules set by the PSCW allow us to defer, for subsequent rate recovery or refund, under- or over-collections of actual fuel and purchased power costs beyond a 2% price variance from the costs included in the rates charged to customers. Our electric utilities monitor the deferral of under-collected costs to ensure that it does not cause them to earn a greater ROE than authorized by the PSCW. In contrast, the rates of our Michigan retail electric customers include recovery of fuel and purchased power costs on a one-for-one basis. In addition, the Wisconsin residential tariffs of WE and WPS include a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. Wholesale customers who resell power can choose to either bundle capacity and electricity services together under one contract with a supplier or purchase capacity and electricity separately from multiple suppliers. Furthermore, wholesale customers can choose to have our utilities provide generation to match the customer's load, similar to requirements contracts, or they can purchase specified quantities of electricity and capacity. Contracts with wholesale customers that include capacity bundled with the delivery of electricity contain two performance obligations, as capacity and electricity are often transacted separately in the marketplace at the wholesale level. When recognizing revenue associated with these contracts, the transaction price is allocated to each performance obligation based on its relative standalone selling price. Revenue is recognized as control of each individual component is transferred to the customer. Electricity is the primary product sold by our electric utilities and represents a single performance obligation satisfied over time through discrete deliveries to a customer. Revenue from electricity sales is generally recognized as units are produced and delivered to the customer within the production month. Capacity represents the reservation of an electric generating facility and conveys the ability to call on a plant to produce electricity when needed by the customer. The nature of our performance obligation as it relates to capacity is to stand ready to deliver power. This represents a single performance obligation transferred over time, which generally represents a monthly obligation. Accordingly, capacity revenue is recognized on a monthly basis. The transaction price of the performance obligations for wholesale customers is valued using the rates, charges, terms, and conditions of service, which have been approved by the FERC. These wholesale rates include recovery of fuel and purchased power costs from customers on a one-for-one basis. For the majority of our wholesale customers, the price billed for energy and capacity is a formula-based rate. Formula-based rates initially set a customer's current year rates based on the previous year’s expenses. This is a predetermined formula derived from the utility's costs and a reasonable rate of return. Because these rates are eventually trued up to reflect actual, current-year costs, they represent a form of variable consideration in certain circumstances. The variable consideration is estimated and recognized over time as wholesale customers receive and consume the capacity and electricity services. We are an active participant in the MISO Energy Markets, where we bid our generation into the Day Ahead and Real Time markets and procure electricity for our retail and wholesale customers at prices determined by the MISO Energy Markets. Purchase and sale transactions are recorded using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded as purchased power in cost of sales, and net sales in a single hour are recorded as resale revenues on our income statements. For resale revenues, our performance obligation is created only when electricity is sold into the MISO Energy Markets. For all of our customers, consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days. Natural Gas Utility Operating Revenues We recognize natural gas utility operating revenues under requirements contracts with residential, commercial and industrial, and transportation customers served under the tariffs of our regulated utilities. Tariffs provide our customers with the standard terms and conditions, including rates, related to the services offered. Requirements contracts provide for the delivery of as much natural gas as the customer needs. These requirements contracts represent discrete deliveries of natural gas and constitute a single performance obligation satisfied over time. Our performance obligation is both created and satisfied with the transfer of control of natural gas upon delivery to the customer. For most of our customers, natural gas is delivered and consumed by the customer simultaneously. A performance obligation can be bundled to consist of both the sale and the delivery of the natural gas commodity. In certain of our service territories, customers can purchase the commodity from a third party. In this case, the performance obligation only includes the delivery of the natural gas to the customer. The transaction price of the performance obligations for our natural gas customers is valued using the rates, charges, terms, and conditions of service included in the tariffs of our regulated utilities, which have been approved by state regulators. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on natural gas delivered each month. The tariffs of our natural gas utilities include various rate mechanisms that allow them to recover or refund changes in prudently incurred costs from rate case-approved amounts. The rates for all of our natural gas utilities include one-for-one recovery mechanisms for natural gas commodity costs. Under normal circumstances, we defer any difference between actual natural gas costs incurred and costs recovered through rates as a current asset or liability. The deferred balance is returned to or recovered from customers at intervals throughout the year. However, as a result of the extreme weather in the Midwest in February 2021, the cost of gas purchased for our natural gas customers was temporarily driven significantly higher than our normal winter weather expectations. See Note 26, Regulatory Environment, for more information on the recovery of these high natural gas costs. In addition, the rates of PGL and NSG, and the residential tariffs of WE, WPS, and WG, include riders or other mechanisms for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. The rates of PGL and NSG include riders for cost recovery of both environmental cleanup costs and energy conservation and management program costs. Finally, PGL's rates include a rider for pass through of income tax expense changes resulting from the Tax Legislation and a cost recovery mechanism for SMP costs, and similarly, the rates of MERC and MGU include riders to recover costs incurred to replace or modify natural gas facilities. Consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days. Other Natural Gas Operating Revenues We have other natural gas operating revenues from Bluewater, which is in our non-utility energy infrastructure segment. Bluewater has entered into long-term service agreements for natural gas storage services with WE, WPS, and WG, and also provides limited service to unaffiliated customers. All amounts associated with the service agreements with WE, WPS, and WG have been eliminated at the consolidated level. Other Non-Utility Operating Revenues Wind generation revenues from WECI's ownership interests in wind generation facilities continued to grow in 2022. See Note 2, Acquisitions, for more information on recent acquisitions. Most of these wind generation facilities have offtake agreements with unaffiliated third parties for all of the energy to be produced by the facility, some of which are bundled with capacity and RECs. We consider bundled energy, capacity and RECs within these offtake agreements to be distinct performance obligations as each are often transacted separately in the marketplace. When recognizing revenue associated with these contracts, the transaction price is allocated to each performance obligation based on its relative standalone selling price. Revenue is recognized as control of each individual component is transferred to the customer. Revenue from the sale of this renewable energy is generally recognized as units are produced and delivered to the customer within the production month. Capacity represents the reservation of the renewable generation facility and conveys the ability to call on the wind facility to produce electricity when needed by the customer. The nature of our performance obligation as it relates to capacity is to stand ready to deliver power. This represents a single performance obligation transferred over time, which generally represents a monthly obligation. Accordingly, capacity revenue is recognized on a monthly basis. The performance obligation for RECs is recognized at a point-in-time; however, the timing of revenue recognition is the same, as the generation of renewable energy and the recognition of REC revenues generally occur concurrently. Non-utility operating revenues are also derived from servicing appliances for customers at MERC. These contracts customarily have a duration of one year or less and consist of a single performance obligation satisfied over time. We use a time-based output method to recognize revenues monthly for the service fee. Consistent with the timing of when we recognize revenue, customer billings for the wind generation and servicing revenues generally occur on a monthly basis, with payments typically due in full within 30 days. As part of the construction of the We Power electric generating units, we capitalized interest during construction, which is included in property, plant, and equipment. As allowed by the PSCW, we collected these carrying costs from WE's utility customers during construction. The equity portion of these carrying costs was recorded as a contract liability, which is presented as deferred revenue, net on our balance sheets. We continually amortize the deferred carrying costs to revenues over the related lease term that We Power has with WE. During 2022, 2021, and 2020, we recorded $23.4 million, $23.3 million, and $22.9 million, respectively, of revenues related to these deferred carrying costs. Other Operating Revenues Alternative Revenues Alternative revenues are created from programs authorized by regulators that allow our utilities to record additional revenues by adjusting rates in the future, usually as a surcharge applied to future billings, in response to past activities or completed events. Alternative revenue programs allow compensation for the effects of weather abnormalities, other external factors, or demand side management initiatives. Alternative revenue programs can also provide incentive awards if the utility achieves certain objectives and in other limited circumstances. We record alternative revenues when the regulator-specified conditions for recognition have been met. We reverse these alternative revenues as the customer is billed, at which time this revenue is presented as revenues from contracts with customers. Below is a summary of the alternative revenue programs at our utilities: • The rates of PGL, NSG, and MERC include decoupling mechanisms. These mechanisms differ by state and allow the utilities to recover or refund the differences between actual and authorized margins for certain customer classes. See Note 26, Regulatory Environment, for more information. • PGL and NSG were authorized to implement a SPC rider for the recovery of incremental direct costs resulting from the COVID-19 pandemic, foregone late fees and reconnection charges, and the costs associated with their bill payment assistance programs. See Note 26, Regulatory Environment, for more information. • MERC’s rates include a CIP rider, which includes a financial incentive for meeting energy savings goals. • WE and WPS provide wholesale electric service to customers under market-based rates and FERC formula rates. The customer is charged a base rate each year based upon a formula using prior year actual costs and customer demand. A true-up is calculated based on the difference between the amount billed to customers for the demand component of their rates and what the actual (e) Credit Losses —The following discussion includes our significant accounting policies related to credit losses. For additional required disclosures on credit losses, see Note 5, Credit Losses. Effective January 1, 2020, we adopted FASB ASU 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, using the modified retrospective transition method. This ASU amends the impairment model to utilize an expected loss methodology in place of the incurred loss methodology for financial instruments, including trade receivables. The amendment requires entities to consider a broader range of information to estimate expected credit losses, which may result in earlier recognition of loss. The cumulative effect of adopting this standard was not significant to our financial statements. Our exposure to credit losses is related to our accounts receivable and unbilled revenue balances, which are primarily generated from the sale of electricity and natural gas by our regulated utility operations. Credit losses associated with our utility operations are analyzed at the reportable segment level as we believe contract terms, political and economic risks, and the regulatory environment are similar at this level as our reportable segments are generally based on the geographic location of the underlying utility operations. We have an accounts receivable and unbilled revenue balance associated with our non-utility energy infrastructure segment, related to the sale of electricity from our majority-owned wind generating facilities through agreements with several large high credit quality counterparties. 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 our regulators, if necessary, and employ collection agencies and legal counsel to pursue recovery of defaulted receivables. For our larger customers, detailed credit review procedures may be performed in advance of any sales being made. We sometimes require letters of credit, parental guarantees, prepayments or other forms of credit assurance from our larger customers to mitigate credit risk. (f) Materials, Supplies, and Inventories —Our inventory as of December 31 consisted of: (in millions) 2022 2021 Natural gas in storage $ 446.3 $ 326.0 Materials and supplies 257.0 225.3 Fossil fuel 103.8 84.5 Total $ 807.1 $ 635.8 PGL and NSG price natural gas storage injections at the calendar year average of the costs of natural gas supply purchased. Withdrawals from storage are priced on the LIFO cost method. Inventories stated on a LIFO basis represented approximately 13% and 19% of total inventories at December 31, 2022 and 2021, respectively. The estimated replacement cost of natural gas in inventory at December 31, 2022 and 2021, exceeded the LIFO cost by $98.3 million and $114.2 million, respectively. In calculating these replacement amounts, PGL and NSG used a Chicago city-gate natural gas price per Dth of $3.41 at December 31, 2022, and $3.67 at December 31, 2021. Substantially all other natural gas in storage, materials and supplies, and fossil fuel inventories are recorded using the weighted-average cost method of accounting. (g) Regulatory Assets and Liabilities —The economic effects of regulation can result in regulated companies recording costs and revenues that are allowed in the ratemaking process in a period different from the period they would have been recognized by a nonregulated company. When this occurs, regulatory assets and regulatory liabilities are recorded on the balance sheet. Regulatory assets represent deferred costs probable of recovery from customers that would have otherwise been charged to expense. Regulatory liabilities represent amounts that are expected to be refunded to customers in future rates or future costs already collected from customers in rates. The recovery or refund of regulatory assets and liabilities is based on specific periods determined by our regulators or occurs over the normal operating period of the related assets and liabilities. If a previously recorded regulatory asset is no longer probable of recovery, the regulatory asset is reduced to the amount considered probable of recovery, and the reduction is charged to expense in the current period. See Note 6, Regulatory Assets and Liabilities, for more information. (h) Property, Plant, and Equipment —We record property, plant, and equipment at cost. Cost includes material, labor, overhead, and both debt and equity components of AFUDC. Additions to and significant replacements of property are charged to property, plant, and equipment at cost; minor items are charged to other operation and maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired. We record straight-line depreciation expense over the estimated useful life of utility property using depreciation rates approved by the applicable regulators. Annual utility composite depreciation rates are shown below: Annual Utility Composite Depreciation Rates 2022 2021 2020 WE 3.06% 3.09% 3.19% WPS 2.67% 2.66% 2.63% WG 2.47% 2.44% 2.33% PGL 3.13% 3.12% 3.16% NSG 2.43% 2.52% 2.48% MERC 2.56% 2.58% 2.47% MGU 2.75% 2.70% 2.67% UMERC 3.01% 2.94% 2.97% We depreciate our We Power assets over the estimated useful life of the various property components. The components have useful lives of between 10 to 45 years for PWGS 1 and PWGS 2 and 10 to 55 years for ER 1 and ER 2. We capitalize certain costs related to software developed or obtained for internal use and record these costs to amortization expense over the estimated useful life of the related software, which ranges from 3 to 15 years. If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statement. Third parties reimburse the utilities for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs are recorded as a reduction to property, plant, and equipment. See Note 7, Property, Plant, and Equipment, for more information. (i) Allowance for Funds Used During Construction —AFUDC is included in utility plant accounts and represents the cost of borrowed funds (AFUDC–Debt) used during plant construction, and a return on shareholders' capital (AFUDC–Equity) used for construction purposes. AFUDC–Debt is recorded as a reduction of interest expense, and AFUDC–Equity is recorded in other income, net. The majority of AFUDC is recorded at WE, WPS, WG, UMERC, and WBS. Approximately 50% of WE's, WPS's, WG's, UMERC's, and WBS's retail jurisdictional CWIP expenditures are subject to the AFUDC calculation. The AFUDC calculation for WBS uses the WPS AFUDC retail rate, while our utilities' AFUDC rates are determined by their respective state commissions, each with specific requirements. Average AFUDC rates are shown below: 2022 Average AFUDC Retail Rate Average AFUDC Wholesale Rate WE 8.68% 5.35% WPS 7.55% 5.49% WG 8.32% N/A UMERC 6.28% N/A WBS 7.55% N/A Our regulated utilities and WBS recorded the following AFUDC for the years ended December 31: (in millions) 2022 2021 2020 AFUDC–Debt WE $ 6.9 $ 2.9 $ 2.6 WPS 2.3 3.5 4.6 WG 1.4 0.2 0.6 UMERC 0.1 0.1 — WBS 0.1 0.1 0.1 Other 0.2 — 0.1 Total AFUDC–Debt $ 11.0 $ 6.8 $ 8.0 AFUDC–Equity WE $ 18.8 $ 7.9 $ 7.0 WPS 5.8 9.0 11.8 WG 3.9 0.6 1.6 UMERC 0.1 0.1 0.1 WBS 0.3 0.2 0.2 Other 0.5 0.2 0.2 Total AFUDC–Equity $ 29.4 $ 18.0 $ 20.9 (j) Cloud Computing Hosting Arrangements that are Service Contracts —We have entered into several cloud computing arrangements that are hosted service contracts as part of projects related to the continuous transformation of technology. These projects include, among other things, developing a centralized repository for data to improve analytics and reporting, targeted enterprise resource planning systems, a project management tool, and a power generation employee scheduling system. We present prepaid hosting fees that are service contracts in either prepayments or other long-term assets on our balance sheets and amortize them as the hosting services are received. Amortization expense, as well as the fees associated with the hosting arrangements, is recorded in other operation and maintenance expense on our income statements. At December 31, 2022 and 2021, we had $4.7 million and $3.3 million, respectively, of capitalized implementation costs related to cloud computing arrangements that are hosted service contracts. We amortize the implementation costs on a straight-line basis over the cloud computing service arrangement term once the component of the hosted service is ready for its intended use. Accumulated amortization at December 31, 2022 and 2021, was $1.5 million and $0.6 million, respectively. Amortization expense for the years ended December 31, 2022, 2021, and 2020 was not significant. The presentation of the implementation costs, along with the related accumulated amortization, follows the prepaid hosting fees. (k) Asset Impairment —Goodwill and other intangible assets with indefinite lives are subject to an annual impairment test. Interim impairment tests are performed when impairment indicators are present. During the third quarter of each year, we perform an annual impairment test at all of our reporting units that carry a goodwill balance. The carrying amount of the reporting unit's goodwill is considered not recoverable if the carrying amount of the reporting unit's net assets exceeds the reporting unit's fair value. An impairment loss is recorded as the excess of the carrying amount of the goodwill over its fair value. For our indefinite-lived intangible assets, an impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds the fair value of the asset. An impairment loss is measured as the excess of the carrying amount of the intangible assets over its fair value. No impairment losses were recorded for our indefinite-lived intangible assets during the years ended December 31, 2022 and 2021. See Note 10, Goodwill and Intangibles, for more information. We periodically assess the recoverability of certain long-lived assets when factors indicate the carrying value of such assets may be impaired or such assets are planned to be sold. Long-lived assets that would be subject to an impairment assessment generally include any assets within regulated operations that may not be fully recovered from our customers as a result of regulatory decisions that will be made in the future, as well as assets within nonregulated operations that are proposed to be sold or are currently generating operating losses. An impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds the fair value of the asset. The carrying amount of an asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. An impairment loss is measured as the excess of the carrying amount of the asset over the fair value of the asset. When it becomes probable that a generating unit will be retired before the end of its useful life, we assess whether the generating unit meets the criteria for abandonment accounting. Generating units that are considered probable of abandonment are expected to cease operations in the near term, significantly before the end of their original estimated useful lives. If a generating unit meets the applicable criteria to be considered probable of abandonment, and the unit has been abandoned, we assess the likelihood of recovery of the remaining net book value of that generating unit at the end of each |
Acquisitions
Acquisitions | 12 Months Ended |
Dec. 31, 2022 | |
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 (or disposals) of assets or businesses, and transaction costs are capitalized in asset acquisitions. It was determined that all of the below acquisitions met the criteria of an asset acquisition. The purchase price of certain acquisitions described below includes intangibles recorded as long-term liabilities related to PPAs. See Note 10, Goodwill and Intangibles, for more information. Acquisition of Wind Generation Facilities in Illinois In February 2023, WECI completed the acquisition of a 90% ownership interest in Sapphire Sky, a commercially operational 250 MW wind generating facility in McLean County, Illinois, for a total investment of approximately $442.9 million, which includes transaction costs. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 12 years. Sapphire Sky qualifies for PTCs and is included in the non-utility energy infrastructure segment. In October 2022, WECI signed an agreement to acquire an 80% ownership interest in Maple Flats, a 250 MW solar generating facility under construction in Clay County, Illinois, for approximately $360 million. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 15 years. The transaction is subject to FERC approval and commercial operation is expected to begin during the first half of 2024, at which time the transaction is expected to close. Maple Flats is expected to qualify for PTCs and will be included in the non-utility energy infrastructure segment. In December 2020, WECI completed the acquisition of a 90% ownership interest in Blooming Grove, a commercially operational 250 MW wind generating facility in McLean County, Illinois, for a total investment of $364.6 million, which includes transaction costs and is net of restricted cash acquired of $24.1 million. Blooming Grove has offtake agreements for all the energy produced with affiliates of two investment grade multinational companies for 12 years. Blooming Grove qualifies for PTCs and is included in the non-utility energy infrastructure segment. The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition. (in millions) Accounts receivable $ 0.3 Net property, plant, and equipment 488.3 Other long-term assets 2.9 Accounts payable (13.7) Other current liabilities (1.5) Other long-term liabilities (68.7) Noncontrolling interest (43.0) Total purchase price $ 364.6 Acquisition of a Solar Generation Facility in Texas In January 2023, WECI signed an agreement to acquire an 80% ownership interest in Samson I, a 250 MW solar generating facility in Lamar County, Texas, for approximately $250 million. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 15 years. Commercial operation was achieved in May 2022. Samson I is expected to qualify for PTCs and will be included in the non-utility energy infrastructure segment. Acquisition of Electric Generation Facilities in Wisconsin Effective January 1, 2023, WE and WPS completed the acquisition of Whitewater, a commercially operational 236.5 MW dual fueled (natural gas and low sulfur fuel oil) combined cycle electrical generation facility in Whitewater, Wisconsin, for $72.7 million, which excludes working capital and transaction costs. See Note 15, Leases, for more information. In January 2022, WPS, along with an unaffiliated utility, received PSCW approval to acquire Red Barn, a utility-scale wind-powered electric generating facility. The project will be located in Grant County, Wisconsin and once constructed, WPS will own 82 MW of this project. WPS's share of the cost of this project is estimated to be $160 million, with commercial operation expected to begin in the first half of 2023, at which time the transaction is expected to close. Red Barn is expected to qualify for PTCs. Acquisition of a Wind Generation Facility in Nebraska In September 2022, WECI completed the acquisition of a 90% ownership interest in Thunderhead, a 300 MW wind generating facility in Antelope and Wheeler counties in Nebraska. The purchase price was $382.0 million, which includes transaction costs and is net of cash acquired. Thunderhead achieved commercial operation in November 2022. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 12 years. Thunderhead qualifies for PTCs and is included in the non-utility energy infrastructure segment. The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition. (in millions) Accounts receivable $ 0.2 Other prepayments 0.3 Net property, plant, and equipment 692.3 Other long-term assets 5.1 Other current liabilities (0.2) Other long-term liabilities (273.2) Noncontrolling interest (42.5) Total purchase price $ 382.0 Acquisition of a Wind Generation Facility in Kansas In February 2021, WECI completed the acquisition of a 90% ownership interest in Jayhawk, a 190 MW wind generating facility in Bourbon and Crawford counties, Kansas, for $119.9 million, which included transaction costs. This project became commercially operational in December 2021. Subsequent to the acquisition, WECI incurred an additional $161.3 million of capital expenditures as of December 31, 2022 for the project for a total investment of $281.2 million. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 10 years. Jayhawk qualifies for PTCs. WECI is entitled to 99% of the tax benefits related to this facility for the first 10 years of commercial operation, after which it will be entitled to tax benefits equal to its ownership interest. Jayhawk is included in the non-utility energy infrastructure segment. The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition. (in millions) Net property, plant, and equipment $ 145.3 Other long-term liabilities (11.8) Long-term debt (7.3) Noncontrolling interest (6.3) Total purchase price $ 119.9 Acquisition of a Wind Generation Facility in South Dakota In December 2020, WECI completed the acquisition of an 85% ownership interest in Tatanka Ridge, a 155 MW wind generating facility in Deuel County, South Dakota, that became commercially operational in January 2021. WECI's total investment was $239.9 million, which included transaction costs. Tatanka Ridge has offtake agreements for all the energy produced with an affiliate of an investment grade multinational company for 12 years and a well-established electric cooperative that serves utilities in multiple states for 10 years. Tatanka Ridge qualifies for PTCs. WECI is entitled to 99% of the tax benefits related to this facility for the first 11 years of commercial operation, after which it will be entitled to tax benefits equal to its ownership interest. Tatanka Ridge is included in the non-utility energy infrastructure segment. The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition. (in millions) Other current assets $ 37.3 Net property, plant, and equipment 301.2 Other current liabilities (37.3) Other long-term liabilities (19.3) Noncontrolling interest (42.0) Total purchase price $ 239.9 |
Dispositions
Dispositions | 12 Months Ended |
Dec. 31, 2022 | |
Discontinued Operations and Disposal Groups [Abstract] | |
DISPOSITIONS | DISPOSITIONS Illinois Segment Sale of Certain Real Estate by The Peoples Gas Light and Coke Company In May 2022, we sold approximately 11 acres of real estate owned by PGL that was no longer being utilized in its operations, for $55.1 million. The real estate was located in Chicago, Illinois. As a result of the sale, a pre-tax gain in the amount of $54.5 million was recorded within other operation and maintenance expense on our income statement. The book value of the real estate included in the sale was not material and, therefore, was not presented as held for sale. Corporate and Other Segment Sale of Certain WPS Power Development, LLC Solar Power Generation Facilities In November 2020, we sold a portfolio of residential solar facilities owned by PDL for $10.5 million. These solar facilities were located in California and Hawaii. During the fourth quarter of 2020, we recorded an after-tax gain on the sale of $3.0 million primarily related to the recognition of deferred ITCs, which were included as a reduction of income tax expense on our income statements. The assets included in the sale were not material and, therefore, were not presented as held for sale. The results of operations of these facilities remained in continuing operations through the sale date as the sale did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results. |
Operating Revenues
Operating Revenues | 12 Months Ended |
Dec. 31, 2022 | |
Revenue from Contract with Customer [Abstract] | |
OPERATING REVENUES | OPERATING REVENUES For more information about our significant accounting policies related to operating revenues, see Note 1(d), Operating Revenues. Disaggregation of Operating Revenues The following tables present our operating revenues disaggregated by revenue source. We do not have any revenues associated with our electric transmission segment, which includes investments accounted for using the equity method. We disaggregate revenues into categories that depict how the nature, amount, timing, and uncertainty of revenues and cash flows are affected by economic factors. For our segments, 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. (in millions) Wisconsin Illinois Other States Total Utility Non-Utility Energy Infrastructure Corporate Reconciling WEC Energy Group Consolidated Year ended December 31, 2022 Electric $ 4,956.2 $ — $ — $ 4,956.2 $ — $ — $ — $ 4,956.2 Natural gas 1,980.7 1,883.7 601.8 4,466.2 54.3 — (51.8) 4,468.7 Total regulated revenues 6,936.9 1,883.7 601.8 9,422.4 54.3 — (51.8) 9,424.9 Other non-utility revenues — — 18.7 18.7 133.6 — (9.1) 143.2 Total revenues from contracts with customers 6,936.9 1,883.7 620.5 9,441.1 187.9 — (60.9) 9,568.1 Other operating revenues 23.6 7.2 (2.0) 28.8 402.1 0.5 (402.1) (1) 29.3 Total operating revenues $ 6,960.5 $ 1,890.9 $ 618.5 $ 9,469.9 $ 590.0 $ 0.5 $ (463.0) $ 9,597.4 (in millions) Wisconsin Illinois Other States Total Utility Non-Utility Energy Infrastructure Corporate Reconciling WEC Energy Group Consolidated Year ended December 31, 2021 Electric $ 4,516.6 $ — $ — $ 4,516.6 $ — $ — $ — $ 4,516.6 Natural gas 1,490.3 1,630.3 494.0 3,614.6 46.8 — (43.8) 3,617.6 Total regulated revenues 6,006.9 1,630.3 494.0 8,131.2 46.8 — (43.8) 8,134.2 Other non-utility revenues — — 17.8 17.8 92.8 — (9.1) 101.5 Total revenues from contracts with customers 6,006.9 1,630.3 511.8 8,149.0 139.6 — (52.9) 8,235.7 Other operating revenues 30.1 42.5 7.2 79.8 399.9 0.5 (399.9) (1) 80.3 Total operating revenues $ 6,037.0 $ 1,672.8 $ 519.0 $ 8,228.8 $ 539.5 $ 0.5 $ (452.8) $ 8,316.0 (in millions) Wisconsin Illinois Other States Total Utility Non-Utility Energy Infrastructure Corporate Reconciling WEC Energy Group Consolidated Year Ended December 31, 2020 Electric $ 4,266.1 $ — $ — $ 4,266.1 $ — $ — $ — $ 4,266.1 Natural gas 1,195.6 1,267.9 361.0 2,824.5 44.4 — (42.0) 2,826.9 Total regulated revenues 5,461.7 1,267.9 361.0 7,090.6 44.4 — (42.0) 7,093.0 Other non-utility revenues — — 17.1 17.1 66.6 1.7 (9.1) 76.3 Total revenues from contracts with customers 5,461.7 1,267.9 378.1 7,107.7 111.0 1.7 (51.1) 7,169.3 Other operating revenues 11.8 54.0 6.0 71.8 397.5 0.5 (397.4) (1) 72.4 Total operating revenues $ 5,473.5 $ 1,321.9 $ 384.1 $ 7,179.5 $ 508.5 $ 2.2 $ (448.5) $ 7,241.7 (1) Amounts eliminated represent lease revenues related to certain plants that We Power leases to WE to supply electricity to its customers. Lease payments are billed from We Power to WE and then recovered in WE's rates as authorized by the PSCW and the FERC. WE operates the plants and is authorized by the PSCW and Wisconsin state law to fully recover prudently incurred operating and maintenance costs in electric rates. Revenues from Contracts with Customers Electric Utility Operating Revenues The following table disaggregates electric utility operating revenues into customer class: Year Ended December 31 (in millions) 2022 2021 2020 Residential $ 1,879.1 $ 1,768.0 $ 1,743.9 Small commercial and industrial 1,530.4 1,415.7 1,325.9 Large commercial and industrial 1,042.2 931.9 821.5 Other 29.9 29.3 29.0 Total retail revenues 4,481.6 4,144.9 3,920.3 Wholesale 153.9 157.7 174.0 Resale 256.7 161.9 130.4 Steam 28.4 28.7 21.3 Other utility revenues 35.6 23.4 20.1 Total electric utility operating revenues $ 4,956.2 $ 4,516.6 $ 4,266.1 Natural Gas Utility Operating Revenues The following tables disaggregate natural gas utility operating revenues into customer class: (in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues Year ended December 31, 2022 Residential $ 1,234.0 $ 1,297.4 $ 391.3 $ 2,922.7 Commercial and industrial 672.7 408.8 218.7 1,300.2 Total retail revenues 1,906.7 1,706.2 610.0 4,222.9 Transportation 81.8 259.8 34.5 376.1 Other utility revenues (1) (2) (7.8) (82.3) (42.7) (132.8) Total natural gas utility operating revenues $ 1,980.7 $ 1,883.7 $ 601.8 $ 4,466.2 (in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues Year ended December 31, 2021 Residential $ 928.9 $ 1,017.9 $ 241.2 $ 2,188.0 Commercial and industrial 472.1 302.1 129.9 904.1 Total retail revenues 1,401.0 1,320.0 371.1 3,092.1 Transportation 80.0 231.2 31.8 343.0 Other utility revenues (1) (3) 9.3 79.1 91.1 179.5 Total natural gas utility operating revenues $ 1,490.3 $ 1,630.3 $ 494.0 $ 3,614.6 (in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues Year Ended December 31, 2020 Residential $ 752.6 $ 802.2 $ 220.8 $ 1,775.6 Commercial and industrial 338.1 221.0 115.8 674.9 Total retail revenues 1,090.7 1,023.2 336.6 2,450.5 Transportation 79.1 215.6 31.5 326.2 Other utility revenues (1) 25.8 29.1 (7.1) 47.8 Total natural gas utility operating revenues $ 1,195.6 $ 1,267.9 $ 361.0 $ 2,824.5 (1) Includes the revenues subject to the purchased gas recovery mechanisms of our utilities. (2) During 2022, we continued to recover natural gas costs we under-collected from our customers in 2021 related to the extreme weather experienced in February 2021, as well as higher natural gas costs incurred at the majority of our segments during 2022. As these amounts are billed to customers, they are reflected in retail revenues with an offsetting decrease in other utility revenues. (3) During 2021, in addition to costs related to the extreme weather event experienced in February 2021, we incurred higher natural gas costs as a result of an increase in the price of natural gas. See Note 26, Regulatory Environment, for more information. Other Natural Gas Operating Revenues We have other natural gas operating revenues from Bluewater, which is in our non-utility energy infrastructure segment. Bluewater has entered into long-term service agreements for natural gas storage services with WE, WPS, and WG, and also provides limited service to unaffiliated customers. All amounts associated with the service agreements with WE, WPS, and WG have been eliminated at the consolidated level. Other Non-Utility Operating Revenues Other non-utility operating revenues consist primarily of the following: Year Ended December 31 (in millions) 2022 2021 2020 Wind generation revenues $ 101.0 $ 60.3 $ 34.6 We Power revenues 23.4 23.3 22.9 Appliance service revenues 18.7 17.8 17.1 Other 0.1 0.1 1.7 Total other non-utility operating revenues $ 143.2 $ 101.5 $ 76.3 Other Operating Revenues Other operating revenues consist primarily of the following: Year Ended December 31 (in millions) 2022 2021 2020 Late payment charges (1) $ 55.6 $ 54.9 $ 29.4 Alternative revenues (2) (30.3) 21.2 38.8 Other 4.0 4.2 4.2 Total other operating revenues $ 29.3 $ 80.3 $ 72.4 (1) The increase in late payment charges during 2021, compared with 2020, was a result of the expiration of various regulatory orders from our utility commissions in response to the COVID-19 pandemic, which included the suspension of late payment charges during a designated time period. See Note 26, Regulatory Environment, for more information. (2) Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. Negative amounts can also result from revenues to be refunded to customers subject to decoupling mechanisms, wholesale true-ups, conservation improvement rider true-ups, and certain late payment charges. |
Credit Losses
Credit Losses | 12 Months Ended |
Dec. 31, 2022 | |
Credit Loss [Abstract] | |
CREDIT LOSSES | CREDIT LOSSES We have included tables below that show our gross third-party receivable balances and the related allowance for credit losses at December 31, 2022 and 2021, by reportable segment. (in millions) Wisconsin Illinois Other States Total Utility Non-Utility Energy Infrastructure Corporate WEC Energy Group Consolidated December 31, 2022 Accounts receivable and unbilled revenues $ 1,199.4 $ 624.2 $ 164.4 $ 1,988.0 $ 25.4 $ 4.3 $ 2,017.7 Allowance for credit losses 82.0 111.0 6.3 199.3 — — 199.3 Accounts receivable and unbilled revenues, net (1) $ 1,117.4 $ 513.2 $ 158.1 $ 1,788.7 $ 25.4 $ 4.3 $ 1,818.4 Total accounts receivable, net – past due greater than 90 days (1) $ 51.9 $ 52.9 $ 1.9 $ 106.7 $ — $ — $ 106.7 Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1) 97.0 % 100.0 % — % 96.8 % — % — % 96.8 % (in millions) Wisconsin Illinois Other States Total Utility Non-Utility Energy Infrastructure Corporate WEC Energy Group Consolidated December 31, 2021 Accounts receivable and unbilled revenues $ 1,053.1 $ 523.1 $ 105.7 $ 1,681.9 $ 17.0 $ 5.1 $ 1,704.0 Allowance for credit losses 84.0 105.5 8.8 198.3 — — 198.3 Accounts receivable and unbilled revenues, net (1) $ 969.1 $ 417.6 $ 96.9 $ 1,483.6 $ 17.0 $ 5.1 $ 1,505.7 Total accounts receivable, net – past due greater than 90 days (1) $ 46.5 $ 36.6 $ 3.4 $ 86.5 $ — $ — $ 86.5 Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1) 97.6 % 100.0 % — % 94.8 % — % — % 94.8 % (1) Our exposure to credit losses for certain regulated utility customers is mitigated by regulatory mechanisms we have in place. Specifically, rates related to all of the customers in our Illinois segment, as well as the residential rates of WE, WPS, and WG in our Wisconsin segment, include riders or other mechanisms for cost recovery or refund of uncollectible expense based on the difference between the actual provision for credit losses and the amounts recovered in rates. As a result, at December 31, 2022, $1,079.1 million, or 59.3%, 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 by reportable segment for the years ended December 31, 2022, 2021, and 2020, is included below: (in millions) Wisconsin Illinois Other States Total Utility Corporate WEC Energy Group Consolidated Balance at January 1, 2022 $ 84.0 $ 105.5 $ 8.8 $ 198.3 $ — $ 198.3 Provision for credit losses 50.5 33.0 2.6 86.1 — 86.1 Provision for credit losses deferred for future recovery or refund 29.7 33.2 — 62.9 — 62.9 Write-offs charged against the allowance (117.0) (82.6) (6.4) (206.0) — (206.0) Recoveries of amounts previously written off 34.8 21.9 1.3 58.0 — 58.0 Balance at December 31, 2022 $ 82.0 $ 111.0 $ 6.3 $ 199.3 $ — $ 199.3 On a consolidated basis, there was a $1.0 million increase in the allowance for credit losses during the year ended December 31, 2022. We believe that the high energy costs that customers are seeing, which have been driven by high natural gas prices, contributed to higher past due accounts receivable balances and a related increase in the allowance for credit losses. The increase was substantially offset by customer write-offs related to collection practices returning to pre-pandemic levels, including the restoration of our ability to disconnect customers. After a customer is disconnected for a period of time without payment on their account, we will write off that customer balance. (in millions) Wisconsin Illinois Other States Total Utility Corporate WEC Energy Group Consolidated Balance at January 1, 2021 $ 102.1 $ 111.6 $ 6.4 $ 220.1 $ — $ 220.1 Provision for credit losses 46.4 25.6 3.7 75.7 — 75.7 Provision for credit losses deferred for future recovery or refund (16.6) 3.5 — (13.1) — (13.1) Write-offs charged against the allowance (74.8) (52.5) (2.5) (129.8) — (129.8) Recoveries of amounts previously written off 26.9 17.3 1.2 45.4 — 45.4 Balance at December 31, 2021 $ 84.0 $ 105.5 $ 8.8 $ 198.3 $ — $ 198.3 The allowance for credit losses decreased during the year ended December 31, 2021, primarily related to normal collection practices resuming in April 2021 for our Wisconsin utilities and in June 2021 for our Illinois utilities. Across all of our reportable segments, higher year-over-year natural gas prices drove an increase in gross accounts receivable balances, partially offsetting the decrease in the allowance for credit losses attributed to collection efforts. (in millions) Wisconsin Illinois Other States Total Utility Corporate WEC Energy Group Consolidated Balance at January 1, 2020 $ 59.9 $ 75.9 $ 4.1 $ 139.9 $ 0.1 $ 140.0 Provision for credit losses 47.5 51.1 4.3 102.9 — 102.9 Provision for credit losses deferred for future recovery or refund 24.6 30.6 — 55.2 — 55.2 Write-offs charged against the allowance (65.9) (63.0) (3.4) (132.3) — (132.3) Recoveries of amounts previously written off 36.0 17.0 1.4 54.4 — 54.4 Sale of PDL residential solar facilities — — — — (0.1) (0.1) Balance at December 31, 2020 $ 102.1 $ 111.6 $ 6.4 $ 220.1 $ — $ 220.1 The allowance for credit losses increased during the year ended December 31, 2020, driven by higher past due accounts receivable balances at our utility segments, primarily related to residential customers. This increase in accounts receivable balances in arrears was driven by economic disruptions caused by the COVID-19 pandemic, including higher unemployment rates. Also, as a result of the COVID-19 pandemic and related regulatory orders we received, we were unable to disconnect any of our Wisconsin and Illinois customers during the year ended December 31, 2020. |
Regulatory Assets and Liabiliti
Regulatory Assets and Liabilities | 12 Months Ended |
Dec. 31, 2022 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
REGULATORY ASSETS AND LIABILITIES | REGULATORY ASSETS AND LIABILITIES The following regulatory assets were reflected on our balance sheets as of December 31: (in millions) 2022 2021 See Note Regulatory assets (1) (2) Pension and OPEB costs (3) $ 714.3 $ 802.3 20 Plant retirement related items 688.6 722.3 Environmental remediation costs (4) 610.7 630.9 24 Income tax related items 461.9 458.8 16 AROs 169.7 194.2 1(l), 9 Derivatives 133.8 33.1 1(s) SSR (5) 123.5 129.5 Securitization 92.4 100.7 23 Uncollectible expense 69.3 42.6 5 MERC extraordinary natural gas costs (6) 35.1 59.7 26 Energy efficiency programs (7) 33.9 22.0 Energy costs recoverable through rate adjustments 26.9 85.4 1(d), 26 Other, net 146.8 85.6 Total regulatory assets $ 3,306.9 $ 3,367.1 Balance sheet presentation Other current assets $ 42.3 $ 102.3 Regulatory assets 3,264.6 3,264.8 Total regulatory assets $ 3,306.9 $ 3,367.1 (1) Based on prior and current rate treatment, we believe it is probable that our utilities will continue to recover from customers the regulatory assets in this table. In accordance with GAAP, our regulatory assets do not include the allowance for ROE that is capitalized for regulatory purposes. This allowance was $27.3 million and $30.9 million at December 31, 2022 and 2021, respectively. (2) As of December 31, 2022, we had $237.9 million of regulatory assets not earning a return, $35.3 million of regulatory assets earning a return based on short-term interest rates, and $123.5 million of regulatory assets earning a return based on long-term interest rates. The regulatory assets not earning a return primarily relate to certain environmental remediation costs, uncollectible expense, MERC's extraordinary natural gas costs, our invested capital tax rider, and unamortized loss on reacquired debt. The other regulatory assets in the table either earn a return at the applicable utility's weighted average cost of capital or the cash has not yet been expended, in which case the regulatory assets are offset by liabilities. (3) Primarily represents the unrecognized future pension and OPEB costs related to our defined benefit pension and OPEB plans. We are authorized recovery of these regulatory assets over the average remaining service life of each plan. (4) As of December 31, 2022, we had made cash expenditures of $111.1 million related to these environmental remediation costs. The remaining $499.6 million represents our estimated future cash expenditures. (5) This regulatory asset relates to WE's 2014 announcement to retire the PIPP. Despite WE's intent to retire the PIPP, MISO designated the PIPP as an SSR, which meant the PIPP's operation was necessary for reliability, and the plant could not be shut down until new generation or transmission facilities were built. In December 2014, the PSCW authorized escrow accounting for WE's SSR revenues because of the fluctuations in the actual revenues WE received under the PIPP SSR agreements. The rate order WE received from the PSCW in December 2019 authorized recovery of this SSR regulatory asset over a 15-year period that began on January 1, 2020. (6) Represents the extraordinary natural gas costs MERC incurred during February 2021 that are being recovered over 27 months, beginning in September 2021. See Note 26, Regulatory Environment, for more information on our recovery efforts associated with these costs. (7) Represents amounts recoverable from customers related to programs at the utilities designed to meet energy efficiency standards. The following regulatory liabilities were reflected on our balance sheets as of December 31: (in millions) 2022 2021 See Note Regulatory liabilities Income tax related items $ 1,956.6 $ 1,998.5 16 Removal costs (1) 1,260.9 1,248.0 Pension and OPEB benefits (2) 340.5 397.3 20 Derivatives 76.7 124.1 1(s) Energy costs refundable through rate adjustments 53.4 13.7 1(d) Uncollectible expense 24.0 37.1 5 Earnings sharing mechanisms 12.9 28.4 26 Electric transmission costs (3) 0.4 84.2 Other, net 66.5 29.0 Total regulatory liabilities $ 3,791.9 $ 3,960.3 Balance sheet presentation Other current liabilities $ 56.4 $ 14.3 Regulatory liabilities 3,735.5 3,946.0 Total regulatory liabilities $ 3,791.9 $ 3,960.3 (1) Represents amounts collected from customers to cover the future cost of property, plant, and equipment removals that are not legally required. Legal obligations related to the removal of property, plant, and equipment are recorded as AROs. See Note 9, Asset Retirement Obligations, for more information on our legal obligations. (2) Primarily represents the unrecognized future pension and OPEB benefits related to our defined benefit pension and OPEB plans. We will amortize these regulatory liabilities into net periodic benefit cost over the average remaining service life of each plan. (3) In accordance with the PSCW's approval of escrow accounting for ATC and MISO network transmission expenses for our Wisconsin electric utilities, WE and WPS defer as a regulatory asset or liability the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During 2022, WE and WPS amortized $81.0 million of their transmission regulatory liabilities to offset certain 2022 revenue deficiencies, as approved by the PSCW in order to forego filing for 2022 base rate increases. See Note 26, Regulatory Environment, for more information. Pleasant Prairie Power Plant The Pleasant Prairie power plant was retired on April 10, 2018. The net book value of this plant was $575.1 million at December 31, 2022, representing book value less cost of removal and accumulated depreciation. In addition, previously deferred unprotected tax benefits from the Tax Legislation related to the unrecovered balance of this plant were $17.5 million as of December 31, 2022. The net amount of $557.6 million was classified as a regulatory asset on our balance sheet at December 31, 2022 due to the retirement of the plant. This regulatory asset does not include certain other previously recorded deferred tax liabilities of $156.7 million related to the retired Pleasant Prairie power plant. Pursuant to its rate order issued by the PSCW in December 2019, WE will continue to amortize this regulatory asset on a straight-line basis through 2039, using the composite depreciation rates approved by the PSCW before this plant was retired. The amortization is included in depreciation and amortization in the income statement. WE also has FERC approval to continue to collect the net book value of the Pleasant Prairie power plant using the approved composite depreciation rates, in addition to a return on the remaining net book value. WE received approval from the PSCW in December 2019 to collect a full return of the net book value of the Pleasant Prairie power plant and a return on all but $100 million of the net book value. During May 2021, WE securitized the remaining $100 million of the Pleasant Prairie power plant's book value, the carrying costs accrued on the $100 million during the securitization process, and the related financing fees, in accordance with a written order issued by the PSCW in November 2020. See Note 23, Variable Interest Entities, for more information on this securitization. Presque Isle Power Plant Pursuant to MISO's April 2018 approval of the retirement of the PIPP, these units were retired on March 31, 2019. The net book value of the PIPP was $163.7 million at December 31, 2022, representing book value less cost of removal and accumulated depreciation. In addition, previously deferred unprotected tax benefits from the Tax Legislation related to the unrecovered balance of these units were $5.2 million as of December 31, 2022. The net amount of $158.5 million was classified as a regulatory asset on our balance sheet at December 31, 2022 as a result of the retirement of the plant. This regulatory asset does not include certain other previously recorded deferred tax liabilities of $44.4 million related to the retired PIPP. After the retirement of the PIPP, a portion of the regulatory asset and related cost of removal reserve was transferred to UMERC for recovery from its retail customers. Effective with its rate order issued by the PSCW in December 2019, WE received approval to collect a return of and on its share of the net book value of the PIPP and, as a result, will continue to amortize the regulatory assets on a straight-line basis through 2037, using the composite depreciation rates approved by the PSCW before the units were retired. UMERC will also continue to amortize the regulatory assets on a straight-line basis using the composite depreciation rates approved by the PSCW before the units were retired. This amortization is included in depreciation and amortization in the income statement. UMERC will address the accounting and regulatory treatment related to the retirement of the PIPP with the MPSC in conjunction with a future rate case. WE also has FERC approval to continue to collect the net book value of the PIPP using the approved composite depreciation rates, in addition to a return on the net book value. Pulliam Power Plant In connection with a MISO ruling, WPS retired Pulliam Units 7 and 8 on October 21, 2018. The net book value of the Pulliam units was $36.6 million at December 31, 2022, representing book value less cost of removal and accumulated depreciation. This amount was classified as a regulatory asset on our balance sheet at December 31, 2022 as a result of the retirement of the plant. Effective with its rate order issued by the PSCW in December 2019, WPS received approval to collect a return of and on the entire net book value of the Pulliam units and, as a result, will continue to amortize this regulatory asset on a straight-line basis through 2031, using the composite depreciation rates approved by the PSCW before these generating units were retired. The amortization is included in depreciation and amortization in the income statement. WPS also has FERC approval to continue to collect the net book value of the Pulliam power plant using the approved composite depreciation rates, in addition to a return on the remaining net book value. Edgewater Unit 4 |
Property, Plant, and Equipment
Property, Plant, and Equipment | 12 Months Ended |
Dec. 31, 2022 | |
Property, Plant and Equipment [Abstract] | |
PROPERTY, PLANT AND EQUIPMENT | PROPERTY, PLANT, AND EQUIPMENT Property, plant, and equipment consisted of the following at December 31: (in millions) 2022 2021 Electric – generation $ 5,480.5 $ 6,981.4 Electric – distribution 8,233.3 7,854.7 Natural gas – distribution, storage, and transmission 14,203.3 13,526.6 Property, plant, and equipment to be retired, net 1,085.6 277.0 Other 2,302.7 2,212.6 Less: Accumulated depreciation 8,416.2 8,894.9 Net 22,889.2 21,957.4 CWIP 972.1 406.0 Net utility and non-utility property, plant, and equipment 23,861.3 22,363.4 We Power generation 3,237.1 3,240.5 Renewable generation 2,537.1 1,837.5 Natural gas storage 292.2 289.9 Net non-utility energy infrastructure 6,066.4 5,367.9 Corporate services 163.0 188.7 Other 23.8 27.0 Less: Accumulated depreciation 1,082.3 994.4 Net 5,170.9 4,589.2 CWIP 81.6 29.8 Net other property, plant, and equipment 5,252.5 4,619.0 Total property, plant, and equipment $ 29,113.8 $ 26,982.4 Severance Liability for Plant Retirements We have severance liabilities related to past and future plant retirements recorded in other current liabilities on our balance sheets. Activity related to these severance liabilities for the years ended December 31 was as follows: (in millions) 2022 2021 2020 Severance liability at January 1 $ 4.9 $ 0.7 $ 2.1 Severance expense 11.3 4.6 — Severance payments — (0.4) (0.1) Other — — (1.3) Total severance liability at December 31 $ 16.2 $ 4.9 $ 0.7 Wisconsin Segment 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. 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 WE's ownership share of units 5 – 8 was $812.5 million at December 31, 2022, 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 continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW. Columbia Units 1 and 2 As a result of a MISO ruling received in June 2021, retirement of the jointly-owned Columbia generating units 1 and 2 became probable. Columbia generating units 1 and 2 are expected to be retired by June 2026. The net book value of WPS's ownership share of unit 1 and unit 2 was $84.0 million and $189.1 million, respectively, at December 31, 2022, 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 WPS continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW. Public Service Building and Steam Tunnel Assets During a significant rain event in May 2020, an underground steam tunnel in downtown Milwaukee flooded and steam vented into WE’s PSB. The damage to the building and adjacent steam tunnel assets from the flooding and steam was extensive and required significant repairs and restorations. As of December 31, 2022, WE had incurred $95.3 million of costs related to these repairs and restorations. In 2020, WE received $20.0 million of insurance proceeds to cover a portion of these costs and wrote off $12.5 million of costs that we do not intend to seek recovery for through other operation and maintenance expense. In the first quarter of 2022, WE received $41.0 million of insurance proceeds as a result of a settlement that was reached in February 2022. The remaining $21.8 million of costs is expected to be recovered through rates. In June 2021, we received approval from the PSCW to restore the PSB and adjacent steam tunnel assets and to defer the project costs, net of insurance proceeds, as a component of rate base. As such, and in light of the agreement with insurers noted above, we do not currently expect a significant impact to our future results of operations. |
Jointly Owned Utility Facilitie
Jointly Owned Utility Facilities | 12 Months Ended |
Dec. 31, 2022 | |
Jointly Owned Utility Plant, Net Ownership Amount [Abstract] | |
JOINTLY OWNED UTILITY FACILITIES | JOINTLY OWNED UTILITY FACILITIES We Power and WPS hold joint ownership interests in certain electric generating facilities. They are entitled to their share of generating capability and output of each facility equal to their respective ownership interest. They pay their ownership share of additional construction costs and have supplied their own financing for all jointly owned projects. We record We Power's and WPS's proportionate share of significant jointly owned electric generating facilities as property, plant, and equipment on the balance sheets. We Power leases its ownership interest in ER 1 and ER 2 to WE, and WE operates these units. WE and WPS record their respective share of fuel inventory purchases and operating expenses, unless specific agreements have been executed to limit their maximum exposure to additional costs. WE's and WPS's proportionate share of direct expenses for the joint operation of these plants is recorded within operating expenses in the income statements. Information related to jointly owned utility facilities at December 31, 2022 was as follows: We Power WPS (in millions, except for percentages and MW) Elm Road Generating Station Units 1 and 2 Weston Unit 4 Columbia Energy Center Units 1 and 2 Forward Wind Two Creeks Badger Hollow I (2) Ownership 83.34 % 70.0 % 27.5 % 44.6 % 66.7 % 66.7 % Share of capacity (MW) (1) 1,060.8 387.3 311.1 61.5 100.0 100.0 In-service date 2010 and 2011 2008 1975 and 1978 2008 2020 2021 Property, plant, and equipment $ 2,425.1 $ 612.1 $ 426.1 $ 119.3 $ 136.8 $ 146.2 Accumulated depreciation $ (505.7) $ (213.0) $ (159.7) $ (53.9) $ (9.7) $ (4.9) CWIP $ 64.1 $ 1.2 $ 6.8 $ 0.2 $ 0.1 $ — (1) Capacity for our jointly-owned electric generation facilities, other than Forward Wind, Two Creeks, and Badger Hollow I, is based on rated capacity, which is the net power output under average operating conditions with equipment in an average state of repair as of a given month in a given year. Values are primarily based on the net dependable expected capacity ratings for summer 2023 established by tests and may change slightly from year to year. The summer period is the most relevant for capacity planning purposes. This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand. Capacity for Forward Wind is based on nameplate capacity, which is the amount of energy a turbine should produce at optimal wind speeds. Capacity for Two Creeks and Badger Hollow I is based on nameplate capacity, which is the maximum output that a generator should produce at continuous full power. (2) Commercial operation was achieved in November 2021 for Badger Hollow I. WE, along with an unaffiliated utility, received PSCW approval to construct Badger Hollow II, a solar project that will be located in Iowa County, Wisconsin. Once constructed, WE will own 66.7%, or 100 MW, of Badger Hollow II. Commercial operation is targeted for 2023. The CWIP balance for Badger Hollow II was $107.5 million as of December 31, 2022. WE and WPS, along with an unaffiliated utility, received PSCW approval to construct Paris, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Kenosha County, Wisconsin and once fully constructed, WE and WPS will collectively own 90%, or 180 MW of solar generation and 99 MW of battery storage, of this project. Commercial operation of the solar facility is targeted for 2023. The CWIP balance for Paris was $207.6 million as of December 31, 2022. WE and WPS, along with an unaffiliated utility, received PSCW approval to construct Darien, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Rock and Walworth counties, Wisconsin and once constructed, WE and WPS will collectively own 90%, or 225 MW of solar generation and 68 MW of battery storage of this project. Commercial operation of the solar facility is targeted for 2024. The CWIP balance for Darien was $9.4 million as of December 31, 2022. |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2022 | |
Asset Retirement Obligation Disclosure [Abstract] | |
ASSET RETIREMENT OBLIGATIONS | ASSET RETIREMENT OBLIGATIONS Our utilities have recorded AROs primarily for the removal of natural gas distribution mains and service pipes (including asbestos and PCBs); asbestos abatement at certain generation and substation facilities, office buildings, and service centers; the removal and dismantlement of a biomass generation facility; the dismantling of wind generation projects; the dismantling of solar generation projects; the disposal of PCB-contaminated transformers; the closure of coal combustion residual landfills at certain generation facilities; and the removal of above ground and underground storage tanks. Regulatory assets and liabilities are established by our utilities to record the differences between ongoing expense recognition under the ARO accounting rules and the ratemaking practices for retirement costs authorized by the applicable regulators. WECI has also recorded AROs for the dismantling of our non-utility wind generation projects. On our balance sheets, AROs are recorded within other long-term liabilities. The following table shows changes to our AROs during the years ended December 31: (in millions) 2022 2021 2020 Balance as of January 1 $ 462.0 $ 513.5 $ 483.5 Accretion 16.1 21.2 20.7 Additions and revisions to estimated cash flows 15.0 (1) (53.9) (2) 39.7 (3) Liabilities settled (13.8) (18.8) (30.4) Balance as of December 31 $ 479.3 $ 462.0 $ 513.5 (1) AROs increased $12.1 million in 2022, as a result of an ARO being recorded for the legal requirement to dismantle, at retirement, the Thunderhead non-utility wind generation project. Also in 2022, AROs increased $1.9 million due to revisions made to estimated cash flows primarily for changes in the cost to retire natural gas distribution mains and service pipes at PGL and NSG. (2) AROs decreased $152.0 million in 2021, due to revisions made to estimated cash flows primarily for changes in the cost to retire natural gas distribution lines at PGL and NSG. Also in 2021, AROs increased $50.7 million due to new natural gas distribution lines being placed into service at PGL and NSG. AROs increased by $26.3 million as a result of AROs being recorded for the legal requirement to dismantle, at retirement, the Badger Hollow I solar generation project and the Tatanka Ridge and Jayhawk non-utility wind generation projects. AROs increased $7.8 million due to revisions made to removal estimates for wind generation projects at WE and WPS. AROs increased $6.8 million due to revisions made to the removal estimates for fly ash landfills and ash ponds at WPS. (3) AROs increased $39.3 million in 2020, primarily due to new natural gas distribution lines being placed into service at PGL. Also in 2020, AROs increased by $8.5 million as a result of AROs being recorded for the legal requirement to dismantle, at retirement, the Two Creeks solar generation project. AROs decreased $9.2 million due to revisions made to estimated cash flows for the abatement of asbestos at WE. |
Goodwill and Intangibles
Goodwill and Intangibles | 12 Months Ended |
Dec. 31, 2022 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
GOODWILL AND INTANGIBLES | GOODWILL AND INTANGIBLES Goodwill Goodwill represents the excess of the cost of an acquisition over the fair value of the identifiable net assets acquired. The table below shows our goodwill balances by segment at December 31, 2022. We had no changes to the carrying amount of goodwill during the years ended December 31, 2022 and 2021. (in millions) Wisconsin Illinois Other States Non-Utility Energy Infrastructure Total Goodwill balance (1) $ 2,104.3 $ 758.7 $ 183.2 $ 6.6 $ 3,052.8 (1) We had no accumulated impairment losses related to our goodwill as of December 31, 2022. During the third quarter of 2022, annual impairment tests were completed at all of our reporting units that carried a goodwill balance as of July 1, 2022. No impairments resulted from these tests. Intangible Assets At December 31, 2022 and 2021, we had $24.9 million and $5.7 million, respectively, of indefinite-lived intangible assets. During 2022, we purchased additional spectrum frequencies for $19.2 million. The spectrum frequencies enable the utilities to transmit data and voice communications over a wavelength dedicated to us throughout our service territories. We also have $5.7 million of other indefinite-lived intangible assets, primarily related to a MGU trade name from a previous acquisition. These indefinite-lived intangible assets are included in other long-term assets on our balance sheets. Intangible Liabilities The intangible liabilities below were all obtained through acquisitions by WECI and are classified as other long-term liabilities on our balance sheets. December 31, 2022 December 31, 2021 (in millions) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Gross Carrying Amount Accumulated Amortization Net Carrying Amount PPAs (1) $ 343.9 $ (16.9) $ 327.0 $ 87.9 $ (6.5) $ 81.4 Proxy revenue swap (2) 7.2 (2.8) 4.4 7.2 (2.1) 5.1 Interconnection agreements (3) 4.7 (0.7) 4.0 4.7 (0.5) 4.2 Total intangible liabilities $ 355.8 $ (20.4) $ 335.4 $ 99.8 $ (9.1) $ 90.7 (1) Represents PPAs related to the acquisition of Blooming Grove, Tatanka Ridge, Jayhawk, and Thunderhead expiring between 2030 and 2034. The weighted-average remaining useful life of the PPAs is 11 years. (2) Represents an agreement with a counterparty to swap the market revenue of Upstream's wind generation for fixed quarterly payments over 10 years, which expires in 2029. The remaining useful life of the proxy revenue swap is six years. (3) Represents interconnection agreements related to the acquisitions of Tatanka Ridge and Bishop Hill III, expiring in 2040 and 2041, respectively. These agreements relate to payments for connecting our facilities to the infrastructure of another utility to facilitate the movement of power onto the electric grid. The weighted-average remaining useful life of the interconnection agreements is 18 years. Amortization related to these intangible liabilities for the years ended December 31, 2022, 2021, and 2020 was $11.3 million, $7.5 million, and $0.8 million, respectively. Amortization for the next five years is estimated to be: For the Years Ending December 31 (in millions) 2023 2024 2025 2026 2027 Amortization to be recorded as an increase to operating revenues $ 29.8 $ 29.8 $ 29.8 $ 29.8 $ 29.8 Amortization to be recorded as a decrease to other operation and maintenance 0.2 0.2 0.2 0.2 0.2 |
Common Equity
Common Equity | 12 Months Ended |
Dec. 31, 2022 | |
Stockholders' Equity Note [Abstract] | |
COMMON EQUITY | COMMON EQUITY Stock-Based Compensation The following table summarizes our pre-tax stock-based compensation expense and the related tax benefit recognized in income for the years ended December 31: (in millions) 2022 2021 2020 Stock options $ 6.5 $ 6.5 $ 6.0 Restricted stock 7.0 6.1 7.4 Performance units 21.3 3.1 22.3 Stock-based compensation expense $ 34.8 $ 15.7 $ 35.7 Related tax benefit $ 9.6 $ 4.3 $ 9.8 Stock-based compensation costs capitalized during 2022, 2021, and 2020 were not significant. Stock Options The following is a summary of our stock option activity during 2022: Stock Options Number of Options Weighted-Average Exercise Price Weighted-Average Remaining Contractual Life (in years) Aggregate Intrinsic Value (in millions) Outstanding as of January 1, 2022 3,111,907 $ 69.84 Granted 437,269 $ 96.04 Exercised (622,459) $ 54.05 Forfeited (16,778) $ 92.16 Outstanding as of December 31, 2022 2,909,939 $ 77.03 6.2 $ 49.7 Exercisable as of December 31, 2022 1,807,644 $ 67.40 5.0 $ 47.8 The aggregate intrinsic value of outstanding and exercisable options in the above table represents the total pre-tax intrinsic value that would have been received by the option holders had they exercised all of their options on December 31, 2022. This is calculated as the difference between our closing stock price on December 31, 2022, and the option exercise price, multiplied by the number of in-the-money stock options. The intrinsic value of options exercised during the years ended December 31, 2022, 2021, and 2020 was $29.2 million, $12.9 million, and $47.1 million, respectively. The actual tax benefit from option exercises for the same periods was approximately $8.0 million, $3.5 million, and $12.9 million, respectively. As of December 31, 2022, approximately $2.3 million of unrecognized compensation cost related to unvested and outstanding stock options was expected to be recognized over the next 1.5 years on a weighted-average basis. During the first quarter of 2023, the Compensation Committee awarded 257,780 non-qualified stock options with a weighted-average exercise price of $93.69 and a weighted-average grant date fair value of $19.58 per option to certain of our officers and other key employees under its normal schedule of awarding long-term incentive compensation. Restricted Shares The following restricted stock activity occurred during 2022: Restricted Shares Number of Shares Weighted-Average Grant Date Fair Value Outstanding and unvested as of January 1, 2022 99,061 $ 88.89 Granted 72,211 $ 96.04 Released (76,109) $ 88.51 Forfeited (5,278) $ 92.80 Outstanding and unvested as of December 31, 2022 89,885 $ 94.73 The intrinsic value of restricted stock released was $7.5 million, $6.5 million, and $11.1 million for the years ended December 31, 2022, 2021, and 2020, respectively. The actual tax benefit from released restricted shares for the same years was $2.1 million, $1.8 million, and $3.1 million, respectively. As of December 31, 2022, approximately $2.8 million of unrecognized compensation cost related to unvested and outstanding restricted stock was expected to be recognized over the next 1.7 years on a weighted-average basis. During the first quarter of 2023, the Compensation Committee awarded 75,453 restricted shares to certain of our directors, officers, and other key employees under its normal schedule of awarding long-term incentive compensation. The grant date fair value of these awards was $93.69 per share. Performance Units During 2022, 2021, and 2020, the Compensation Committee awarded 171,492; 152,382; and 153,465 performance units, respectively, to officers and other key employees under the WEC Energy Group Performance Unit Plan. Performance units with an intrinsic value of $20.2 million, $27.7 million, and $34.5 million were settled during 2022, 2021, and 2020, respectively. The actual tax benefit from the distribution of performance units for the same years was $5.1 million, $6.8 million, and $8.4 million, respectively. At December 31, 2022, we had 375,834 performance units outstanding, including dividend equivalents. A liability of $22.4 million was recorded on our balance sheet at December 31, 2022 related to these outstanding units. As of December 31, 2022, approximately $13.5 million of unrecognized compensation cost related to unvested and outstanding performance units was expected to be recognized over the next 1.7 years on a weighted-average basis. During the first quarter of 2023, we settled performance units with an intrinsic value of $9.7 million. The actual tax benefit from the distribution of these awards was $2.4 million. In January 2023, the Compensation Committee also awarded 157,035 performance units to certain of our officers and other key employees under its normal schedule of awarding long-term incentive compensation. Restrictions Our ability as a holding company to pay common stock dividends primarily depends on the availability of funds received from our utility subsidiaries, We Power, Bluewater, ATC Holding, and WECI. Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans, or advances. All of our utility subsidiaries, with the exception of UMERC and MGU, are prohibited from loaning funds to us, either directly or indirectly. In accordance with their most recent rate orders, WE, WPS, and WG may not pay common dividends above the test year forecasted amounts reflected in their respective rate cases, if it would cause their average common equity ratio, on a financial basis, to fall below their authorized level of 53.0%. A return of capital in excess of the test year amount can be paid by each company at the end of the year provided that their respective average common equity ratios do not fall below the authorized level. WE may not pay common dividends to us under WE's Restated Articles of Incorporation if any dividends on its outstanding preferred stock have not been paid. In addition, pursuant to the terms of WE's 3.60% Serial Preferred Stock, WE's ability to declare common dividends would be limited to 75% or 50% of net income during a 12-month period if its common stock equity to total capitalization, as defined in the preferred stock designation, is less than 25% and 20%, respectively. NSG's long-term debt obligations contain provisions and covenants restricting the payment of cash dividends and the purchase or redemption of its capital stock. The long-term debt obligations of UMERC, Bluewater Gas Storage, and ATC Holding contain a provision requiring them to maintain a total funded debt to capitalization ratio of 65% or less. WECI Wind Holding I's and WECI Wind Holding II's long-term debt obligations contain various conditions that must be met prior to them making any cash distributions. Included in these provisions is a requirement to maintain a debt service coverage ratio of 1.2 or greater for the 12-month period prior to the distribution. WEC Energy Group and Integrys have the option to defer interest payments on their junior subordinated notes, from time to time, for one or more periods of up to 10 consecutive years per period. During any period in which they defer interest payments, they may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire, their respective common stock. See Note 13, Short-Term Debt and Lines of Credit, for discussion of certain financial covenants related to short-term debt obligations. As of December 31, 2022, restricted net assets of our consolidated subsidiaries totaled approximately $9.8 billion. Our equity in undistributed earnings of investees accounted for by the equity method was approximately $487 million. We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future. Share Purchases We have instructed our independent agents to purchase shares on the open market to fulfill obligations under various stock-based employee benefit and compensations plans and to provide shares to participants in our dividend reinvestment and stock purchase plan. As a result, no new shares of common stock were issued in 2022, 2021, or 2020. The following is a summary of shares purchased to fulfill exercised stock options and restricted stock awards during the years ended December 31: (in millions) 2022 2021 2020 Shares purchased 0.7 0.4 1.0 Cost of shares purchased $ 69.2 $ 33.1 $ 99.2 Common Stock Dividends During the year ended December 31, 2022, our Board of Directors declared common stock dividends which are summarized below: Date Declared Date Payable Per Share Period January 20, 2022 March 1, 2022 $0.7275 First quarter April 21, 2022 June 1, 2022 $0.7275 Second quarter July 21, 2022 September 1, 2022 $0.7275 Third quarter October 20, 2022 December 1, 2022 $0.7275 Fourth quarter On January 19, 2023, our Board of Directors declared a quarterly cash dividend of $0.78 per share, which equates to an annual dividend of $3.12 per share. The dividend is payable on March 1, 2023, to shareholders of record on February 14, 2023. In addition, the Board of Directors affirmed our dividend policy that continues to target a dividend payout ratio of 65-70% of earnings. |
Preferred Stock
Preferred Stock | 12 Months Ended |
Dec. 31, 2022 | |
Class of Stock Disclosures [Abstract] | |
PREFERRED STOCK | PREFERRED STOCK The following table shows preferred stock authorized and outstanding at December 31, 2022 and 2021: (in millions, except share and per share amounts) Shares Authorized Shares Outstanding Redemption Price Per Share Total WEC Energy Group $0.01 par value Preferred Stock 15,000,000 — — $ — WE $100 par value, Six Per Cent. Preferred Stock 45,000 44,498 — 4.4 $100 par value, Serial Preferred Stock 3.60% Series 2,286,500 260,000 $ 101 26.0 $25 par value, Serial Preferred Stock 5,000,000 — — — WPS $100 par value, Preferred Stock 1,000,000 — — — PGL $100 par value, Cumulative Preferred Stock 430,000 — — — NSG $100 par value, Cumulative Preferred Stock 160,000 — — — Total $ 30.4 |
Short-Term Debt and Lines of Cr
Short-Term Debt and Lines of Credit | 12 Months Ended |
Dec. 31, 2022 | |
Short-Term Debt [Abstract] | |
SHORT-TERM DEBT AND LINES OF CREDIT | SHORT-TERM DEBT AND LINES OF CREDIT The following table shows our short-term borrowings and their corresponding weighted-average interest rates as of December 31: (in millions, except percentages) 2022 2021 Commercial paper Amount outstanding at December 31 $ 1,643.5 $ 1,896.1 Average interest rate on amounts outstanding at December 31 4.64 % 0.26 % Operating expense loans Amount outstanding at December 31 (1) $ 3.6 $ 0.9 (1) Coyote Ridge, Tatanka Ridge, and Jayhawk entered into operating expense loans. In accordance with their limited liability company operating agreements, they r eceived loans from the holders of their noncontrolling interests in proportion to their ownership interests. Our average amount of commercial paper borrowings based on daily outstanding balances during 2022, was $1,487.2 million with a weighted-average interest rate during the period of 1.98%. In order to enhance our liquidity position in response to the COVID-19 pandemic, in March 2020, WEC Energy Group entered into a $340.0 million 364-day term loan. In March 2021, we repaid the term loan using the net proceeds from the issuance of our $600.0 million aggregate principal amount of 0.80% Senior Notes due March 15, 2024. WEC Energy Group, WE, WPS, WG, and PGL have entered into bank back-up credit facilities to maintain short-term credit liquidity which, among other terms, require them to maintain, subject to certain exclusions, a total funded debt to capitalization ratio of 70.0%, 65.0%, 65.0%, 65.0%, and 65.0% or less, respectively. As of December 31, 2022, all companies were in compliance with their respective ratio. The information in the table below relates to our revolving credit facilities used to support our commercial paper borrowing programs, including remaining available capacity under these facilities as of December 31: (in millions) Maturity 2022 Revolving credit facility (WEC Energy Group) September 2026 $ 1,500.0 Revolving credit facility (WE) September 2026 500.0 Revolving credit facility (WPS) September 2026 400.0 Revolving credit facility (WG) September 2026 350.0 Revolving credit facility (PGL) September 2026 350.0 Total short-term credit capacity $ 3,100.0 Less: Letters of credit issued inside credit facilities $ 2.3 Commercial paper outstanding 1,643.5 Available capacity under existing facilities $ 1,454.2 Each of the revolving credit facilities has a renewal provision for two extensions, subject to lender approval. Each extension is for a period of one year. The bank back-up credit facilities contain customary covenants, including certain limitations on the respective companies' ability to sell assets. The credit facilities also contain customary events of default, including payment defaults, material inaccuracy of representations and warranties, covenant defaults, bankruptcy proceedings, certain judgments, Employee Retirement Income Security Act of 1974 defaults, and change of control. In addition, pursuant to the terms of WEC Energy Group's credit agreement, we must ensure that certain of our subsidiaries comply with several of the covenants contained therein. |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2022 | |
Debt Disclosure [Abstract] | |
LONG-TERM DEBT | LONG-TERM DEBT The following table is a summary of our long-term debt outstanding (excluding finance leases) as of December 31: 2022 2021 (in millions) Maturity Date Weighted Average Interest Rate Balance Weighted Average Interest Rate Balance WEC Energy Group Senior Notes (unsecured) (1) 2023-2033 2.44 % $ 3,970.0 1.67 % $ 3,070.0 WEC Energy Group Junior Notes (unsecured) (1) (2) 2067 6.72 % 500.0 2.27 % 500.0 WE Debentures (unsecured) 2024-2095 4.22 % 3,285.0 4.13 % 2,785.0 WEPCo Environmental Trust (secured, nonrecourse) (6) (10) 2023-2035 1.58 % 105.9 1.58 % 114.7 WPS Senior Notes (unsecured) 2025-2051 4.11 % 1,975.0 3.89 % 1,675.0 WG Debentures (unsecured) 2024-2046 3.35 % 790.0 3.35 % 790.0 Integrys Junior Notes (unsecured) (3) 2073 6.00 % 221.4 6.00 % 221.4 PGL First and Refunding Mortgage Bonds (secured) (4) 2024-2047 3.41 % 1,970.0 3.31 % 1,870.0 NSG First Mortgage Bonds (secured) (5) 2027-2043 3.56 % 157.0 3.56 % 157.0 MERC Senior Notes (unsecured) 2025-2047 3.04 % 210.0 3.04 % 210.0 MGU Senior Notes (unsecured) 2025-2047 3.18 % 150.0 3.18 % 150.0 UMERC Senior Notes (unsecured) 2029 3.26 % 160.0 3.26 % 160.0 Bluewater Gas Storage Senior Notes (unsecured) (6) 2023-2047 3.76 % 112.6 3.76 % 115.2 ATC Holding Senior Notes (unsecured) 2025-2030 4.05 % 475.0 4.05 % 475.0 We Power Subsidiaries Notes (secured, nonrecourse) (6) (7) 2023-2041 5.62 % 896.5 5.60 % 934.7 WECC Notes (unsecured) 2028 6.94 % 50.0 6.94 % 50.0 WECI Wind Holding I Senior Notes (secured, nonrecourse) (6) (8) 2023-2032 2.75 % 332.1 2.75 % 374.6 WECI Wind Holding II Senior Notes (secured, nonrecourse) (6) (9) 2023 - 2031 6.38 % 199.3 — % — Total 15,559.8 13,652.6 Integrys acquisition fair value adjustment 1.2 2.9 Jayhawk acquisition 7.3 7.3 Unamortized debt issuance costs (81.8) (77.7) Unamortized discount, net and other (22.3) (21.7) Total long-term debt, including current portion (11) 15,464.2 13,563.4 Current portion of long-term debt (808.5) (91.0) Total long-term debt $ 14,655.7 $ 13,472.4 (1) In connection with our outstanding 2007 Junior Notes, we executed an RCC, which we amended on June 29, 2015, for the benefit of persons that buy, hold, or sell a specified series of our long-term indebtedness (covered debt). Our 6.20% Senior Notes due April 1, 2033 have been designated as the covered debt under the RCC. The RCC provides that we may not redeem, defease, or purchase, and that our subsidiaries may not purchase, any 2007 Junior Notes on or before May 15, 2037, unless, subject to certain limitations described in the RCC, we have received a specified amount of proceeds from the sale of qualifying securities. (2) Variable interest rate reset quarterly. The rates were 6.72% and 2.27% as of December 31, 2022 and 2021, respectively. Until their expiration on November 15, 2021, we had two interest rate swaps with a combined notional value of $250.0 million. The swaps provided a fixed interest rate of 4.9765% on $250.0 million of the outstanding notes. See Note 18, Derivative Instruments, for more information on the two interest rate swaps. (3) The terms of Integrys's 2013 6.00% Junior Notes, due August 1, 2073, provide that, effective August 2023, they will bear interest at a variable rate, which we expect to based off of SOFR, and will reset quarterly. (4) PGL's First Mortgage Bonds are subject to the terms and conditions of PGL's First Mortgage Indenture dated January 2, 1926, as supplemented. Under the terms of the Indenture, substantially all property owned by PGL is pledged as collateral for these outstanding debt securities. PGL has used certain First Mortgage Bonds to secure tax exempt interest rates. The Illinois Finance Authority has issued Tax Exempt Bonds, and the proceeds from the sale of these bonds were loaned to PGL. In return, PGL issued $100 million of collateralized First Mortgage Bonds. (5) NSG's First Mortgage Bonds are subject to the terms and conditions of NSG's First Mortgage Indenture dated April 1, 1955, as supplemented. Under the terms of the Indenture, substantially all property owned by NSG is pledged as collateral for these outstanding debt securities. (6) The long-term debt of Bluewater, WECI Wind Holding I, WECI Wind Holding II, WEPCo Environmental Trust, and We Power's subsidiaries requires periodic principal payments. (7) We Power's subsidiaries' senior notes are secured by a collateral assignment of the leases between We Power's subsidiaries and WE related to PWGS and ERGS, as applicable. (8) WECI Wind Holding I's Senior Notes are secured by a first priority security interest in the ownership interest of its subsidiaries as well as a pledge of equity in WECI Wind Holding I. (9) WECI Wind Holding II's Senior Notes are secured by a first priority security interest in the ownership interest of its subsidiaries as well as a pledge of equity in WECI Wind Holding II. (10) WEPCo Environmental Trust’s ETBs are secured by a pledge of and lien on environmental control property, which includes the right to impose, collect and receive a non-bypassable environmental control charge paid by all of WE's retail electric distribution customers, the right to obtain true-up adjustments of the environmental control charges, and all revenues or other proceeds arising from those rights and interests. See Note 23, Variable Interest Entities, for more information. (11) The amount of long-term debt on our balance sheets includes finance lease obligations of $183.2 million and $129.7 million at December 31, 2022 and 2021, respectively. We amortize debt premiums, discounts, and debt issuance costs over the life of the debt and we include the costs in interest expense. WEC Energy Group, Inc. In September 2022, we issued $500.0 million of 5.00% Senior Notes due September 27, 2025, and $400.0 million of 5.15% Senior Notes due October 1, 2027, and used the net proceeds to repay short-term debt and for other corporate purposes. In January 2023, we issued $650.0 million of 4.75% Senior Notes due January 9, 2026, and $450.0 million of 4.75% Senior Notes due January 15, 2028, and used the net proceeds to repay short-term debt and for other corporate purposes. Wisconsin Electric Power Company In September 2022, WE issued $500.0 million of 4.75% Debentures due September 30, 2032, and intends to allocate an amount equal to the net proceeds for the construction and development of eligible green expenditures, which include existing and new expenditures for the acquisition, construction and development of wind and solar electric generating facilities and related energy storage assets. Wisconsin Public Service Corporation In November 2022, WPS issued $300.0 million of 5.35% Senior Notes due November 10, 2025, and used the net proceeds to repay short-term debt and for other corporate purposes. The Peoples Gas Light and Coke Company In December 2022, PGL issued $100.0 million of 5.23% Bonds, Series MMM due December 1, 2027, and used the net proceeds for general corporate purposes, including capital expenditures and the refinancing of short-term debt. WEC Infrastructure Wind Holding II LLC In December 2022, WECI Wind Holding II issued $199.3 million of 6.38% Senior Notes due December 31, 2031, and used the net proceeds to return a portion of WECI's previously invested capital in the subsidiaries of WECI Wind Holding II. Maturities of Long-Term Debt Outstanding The following table shows the long-term debt securities (excluding finance leases) maturing within one year of December 31, 2022: (in millions) Interest Rate Maturity Date (1) Principal Amount WEC Energy Group Senior Notes (unsecured) 0.55% September $ 700.0 WEPCo Environmental Trust (secured, nonrecourse) 1.58% Semi-annually 8.9 Bluewater Gas Storage Senior Notes (unsecured) 3.76% Semi-annually 2.8 We Power Subsidiaries Notes – PWGS (secured, nonrecourse) 4.91% Monthly 7.6 We Power Subsidiaries Notes – ERGS (secured, nonrecourse) 5.209% Semi-annually 14.7 We Power Subsidiaries Notes – ERGS (secured, nonrecourse) 4.673% Semi-annually 11.1 We Power Subsidiaries Notes – PWGS (secured, nonrecourse) 6.00% Monthly 6.6 WECI Wind Holding I Senior Notes (secured, nonrecourse) 2.75% Semi-annually 42.0 WECI Wind Holding II Senior Notes (secured, nonrecourse) 6.38% Semi-annually 14.8 Total $ 808.5 (1) Maturity dates listed as semi-annually and monthly are associated with debt that requires periodic principal payments. The following table shows the future maturities of our long-term debt outstanding (excluding obligations under finance leases) as of December 31, 2022: (in millions) Payments 2023 $ 808.5 2024 1,239.6 2025 1,685.5 2026 126.8 2027 1,230.7 Thereafter 10,468.7 Total $ 15,559.8 Certain long-term debt obligations contain financial and other covenants related to payment of principal and interest when due, maintaining certain total funded debt to capitalization ratios, and various other obligations. Failure to comply with these covenants could result in an event of default, which could result in the acceleration of outstanding debt obligations. |
Leases
Leases | 12 Months Ended |
Dec. 31, 2022 | |
Leases [Abstract] | |
LEASES | LEASES Obligations Under Operating Leases We have recorded right of use assets and lease liabilities associated with the following operating leases. • Leases of office space, primarily related to several floors we are leasing in the Aon Center office building in Chicago, Illinois, though April 2029. • Land we are leasing related to our Rothschild biomass plant through June 2051. • Land we are leasing related to our Solar Now projects. The operating leases generally require us to pay property taxes, insurance premiums, and operating and maintenance costs associated with the leased property. Certain of our leases contain options for early termination or to renew past the initial term, as set forth in the lease agreements. These options are not included in our calculation of the lease obligations, as it is not reasonably certain that they will be exercised. Obligations Under Finance Leases In accordance with ASC Subtopic 980-842, Regulated Operations – Leases, the expense recognition pattern of our finance leases at our regulated entities resembles that of an operating lease. The difference between the minimum lease payments and the sum of imputed interest and unadjusted amortization costs calculated under Topic 842 is deferred as a regulatory asset on our balance sheets in accordance with Subtopic 980-842. Power Purchase Commitment In 1997, WE entered into a 25-year PPA with LSP-Whitewater Limited Partnership. The contract, for 236.5 MW of firm capacity from a natural gas-fired cogeneration facility, included zero minimum energy requirements. The PPA expired on May 31, 2022; however, in November 2021, WE entered into a tolling agreement with LSP-Whitewater Limited Partnership that commenced on June 1, 2022. Concurrent with the execution of the tolling agreement, WE and WPS entered into an asset purchase agreement to acquire the natural gas-fired cogeneration facility for $72.7 million, which excludes working capital and transaction costs. This asset purchase agreement was approved by the PSCW in December 2022, and the acquisition closed effective January 1, 2023. Land Leases – Utility Solar Generation WE and WPS, along with an unaffiliated utility, have entered into various land leases related to their investment in utility-scale solar generation. Each lease has an initial term and one or more optional extensions. We expect the optional extensions to be exercised, and, as a result, all of the land leases are being amortized over an extended term of approximately 50 years. Once a solar project achieves commercial operation, the lease liability is remeasured to reflect the final total acres being leased. Our payments related to these leases are being recovered through rates. Amounts Recognized in the Financial Statements and Other Information The components of lease expense and supplemental cash flow information related to our leases for the years ended December 31 are as follows: (in millions) 2022 2021 2020 Finance lease expense Amortization of right of use assets (1) $ 6.0 $ 8.1 $ 6.3 Interest on lease liabilities (2) 0.9 1.6 2.5 Operating lease expense (3) 6.1 3.4 5.4 Short-term lease expense (3) 0.9 0.2 0.3 Total lease expense $ 13.9 $ 13.3 $ 14.5 Other information Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from finance leases $ 0.9 $ 1.6 $ 2.5 Operating cash flows from operating leases $ 5.7 $ 5.3 $ 6.7 Financing cash flows from finance leases $ 6.0 $ 8.1 $ 6.3 Non-cash activities: Right of use assets obtained in exchange for finance lease liabilities $ 57.6 $ 73.6 $ 22.8 Right of use assets obtained in exchange for operating lease liabilities $ — $ 0.5 $ — Weighted-average remaining lease term – finance leases 30.0 years 20.5 years 41.5 years Weighted-average remaining lease term – operating leases 12.0 years 12.5 years 13.0 years Weighted-average discount rate – finance lease (4) 3.9 % 2.4 % 4.9 % Weighted average discount rate – operating leases (4) 3.4 % 3.4 % 3.4 % (1) Amortization of right of use assets was included as a component of depreciation and amortization expense. (2) Interest on lease liabilities was included as a component of interest expense. (3) Operating and short-term lease expense were included as a component of operation and maintenance expense. (4) Because our leases do not provide an implicit rate of return, we used the fully collateralized incremental borrowing rates based upon information available for similarly rated companies in determining the present value of lease payments. The following table summarizes our finance and operating lease right of use assets and obligations at December 31: (in millions) 2022 2021 Balance Sheet Location Right of use assets Operating lease right of use assets, net $ 15.7 $ 19.5 Other long-term assets Finance lease right of use assets, net Power purchase commitment $ 71.8 $ 76.7 Land leases – utility solar generation $ 102.4 $ 47.0 Other $ 1.1 $ 0.3 Total finance lease right of use assets, net (1) $ 175.3 $ 124.0 Property, plant, and equipment, net Lease obligations Current operating lease liabilities $ 4.0 $ 3.7 Other current liabilities Long-term operating lease liabilities $ 25.4 $ 29.1 Other long-term liabilities Current finance lease liabilities Power purchase commitment $ 72.7 $ 78.4 Current portion of long-term debt Long-term finance lease liabilities Land leases – utility solar generation $ 109.3 $ 51.0 Other $ 1.2 $ 0.3 Total long-term finance lease liabilities $ 110.5 $ 51.3 Long-term debt (1) Amounts are net of accumulated amortization of $146.3 million and $139.7 million at December 31, 2022 and 2021, respectively. Future minimum lease payments under our operating and finance leases and the present value of our net minimum lease payments as of December 31, 2022, were as follows: (in millions) Total Operating Leases Power Purchase Commitment Land Leases - Utility Solar Generation Other Total Finance Leases 2023 $ 4.9 $ 72.7 $ 3.6 $ — $ 76.3 2024 4.3 — 3.9 0.1 4.0 2025 3.8 — 4.0 0.1 4.1 2026 3.9 — 4.0 0.1 4.1 2027 4.0 — 4.1 0.1 4.2 Thereafter 16.6 — 304.1 2.7 306.8 Total minimum lease payments 37.5 72.7 323.7 3.1 399.5 Less: Interest (8.1) — (214.4) (1.9) (216.3) Present value of minimum lease payments 29.4 72.7 109.3 1.2 183.2 Less: Short-term lease liabilities (4.0) (72.7) — — (72.7) Long-term lease liabilities $ 25.4 $ — $ 109.3 $ 1.2 $ 110.5 As of February 23, 2023, we have not entered into any material leases that have not yet commenced. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2022 | |
Income Tax Disclosure [Abstract] | |
Income Tax Disclosure | INCOME TAXES Income Tax Expense The following table is a summary of income tax expense for the years ended December 31: (in millions) 2022 2021 2020 Current tax expense $ 50.2 $ 93.9 $ 49.2 Deferred income taxes, net 278.5 111.0 182.2 ITCs (5.8) (4.6) (3.5) Total income tax expense $ 322.9 $ 200.3 $ 227.9 Statutory Rate Reconciliation The provision for income taxes for each of the years ended December 31 differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes as a result of the following: 2022 2021 2020 Effective Effective Effective (in millions) Amount Tax Rate Amount Tax Rate Amount Tax Rate Statutory federal income tax $ 363.5 21.0 % $ 315.1 21.0 % $ 299.9 21.0 % State income taxes net of federal tax benefit 109.7 6.3 % 96.1 6.4 % 90.5 6.3 % Wind PTCs (107.6) (6.2) % (81.3) (5.4) % (51.5) (3.6) % Federal excess deferred tax amortization (1) (36.9) (2.1) % (37.3) (2.5) % (36.7) (2.6) % AFUDC – Equity (6.2) (0.4) % (3.8) (0.3) % (4.4) (0.3) % ITC restored (5.8) (0.3) % (4.6) (0.3) % (3.5) (0.2) % Federal excess deferred tax amortization – Wisconsin unprotected (2) (0.8) — % (77.9) (5.2) % (57.6) (4.0) % Other, net 7.0 0.3 % (6.0) (0.3) % (8.8) (0.7) % Total income tax expense $ 322.9 18.6 % $ 200.3 13.4 % $ 227.9 15.9 % (1) The Tax Legislation required our regulated utilities to remeasure their deferred income taxes and we began to amortize the resulting excess protected deferred income taxes beginning in 2018 in accordance with normalization requirements. The decrease in income tax expense related to the amortization of the deferred tax benefits is offset by a decrease in revenue as the benefits are returned to customers, resulting in no impact on net income. (2) In accordance with the rate order received from the PSCW in December 2019, our Wisconsin utilities are amortizing these unprotected deferred tax benefits over periods ranging from two years to four years, to reduce near-term rate impacts to their customers. The decrease in income tax expense related to the amortization of the deferred tax benefits is offset by a decrease in revenue as the benefits are returned to customers, resulting in no impact on net income. See Note 26, Regulatory Environment, for more information about the impact of the Tax Legislation and the Wisconsin rate orders. Deferred Income Tax Assets and Liabilities The components of deferred income taxes as of December 31 were as follows: (in millions) 2022 2021 Deferred tax assets Tax gross up – regulatory items $ 459.0 $ 469.5 Future tax benefits 187.7 104.6 Deferred revenues 86.8 97.8 Other 190.2 205.9 Total deferred tax assets 923.7 877.8 Valuation allowance (1.2) (1.2) Net deferred tax assets $ 922.5 $ 876.6 Deferred tax liabilities Property-related $ 4,072.5 $ 3,909.0 Investment in affiliates 839.7 648.6 Employee benefits and compensation 219.5 170.6 Deferred costs – plant retirements 212.8 223.9 Other 203.6 233.0 Total deferred tax liabilities 5,548.1 5,185.1 Deferred tax liability, net $ 4,625.6 $ 4,308.5 Consistent with ratemaking treatment, deferred taxes related to our regulated utilities in the table above are offset for temporary differences that have related regulatory assets and liabilities. The components of net deferred tax assets associated with federal and state tax benefit carryforwards as of December 31, 2022 and 2021 are summarized in the tables below: 2022 (in millions) Gross Value Deferred Tax Effect Valuation Allowance Earliest Year of Expiration Future tax benefits as of December 31, 2022 Federal tax credit $ — $ 176.4 $ — 2041 State net operating loss 72.6 4.5 (1.2) 2032 Other state benefits — 6.8 — 2023 Balance as of December 31, 2022 $ 72.6 $ 187.7 $ (1.2) 2021 (in millions) Gross Value Deferred Tax Effect Valuation Allowance Earliest Year of Expiration Future tax benefits as of December 31, 2021 Federal tax credit $ — $ 91.5 $ — 2041 State net operating loss 72.0 4.4 (1.2) 2031 Other state benefits — 8.7 — 2023 Balance as of December 31, 2021 $ 72.0 $ 104.6 $ (1.2) Unrecognized Tax Benefits A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows: (in millions) 2022 2021 2020 Balance as of January 1 $ 6.8 $ 11.9 $ 17.9 Additions for tax positions of prior years 0.3 — 1.6 Additions based on tax positions related to the current year 0.4 1.6 0.1 Reductions for tax positions of prior years (1.2) (6.7) (7.7) Balance as of December 31 $ 6.3 $ 6.8 $ 11.9 The amount of unrecognized tax benefits as of December 31, 2022 and 2021, excludes deferred tax assets related to uncertainty in income taxes of $1.3 million and $1.2 million, respectively. As of December 31, 2022 and 2021, the net amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate for continuing operations was $5.1 million and $5.7 million, respectively. Interest accrued related to unrecognized tax benefits is as follows: (in millions) 2022 2021 2020 Balance as of January 1 $ 0.1 $ 0.5 $ 0.8 Interest expense (income) related to unrecognized tax benefits 0.4 (0.4) (0.3) Balance as of December 31 $ 0.5 $ 0.1 $ 0.5 For the years ended December 31, 2022, 2021, and 2020, we recognized no penalties related to unrecognized tax benefits in our consolidated income statements. At December 31, 2022 and 2021, we had no amounts accrued for penalties related to unrecognized tax benefits. Although analysis of our unrecognized tax benefits is ongoing, the potential estimated decrease in the total amounts of unrecognized tax benefits within the next 12 months is approximately $2.3 million associated with statutes of limitations on certain tax years. We do not anticipate any significant increases in the total amounts of unrecognized tax benefits within the next 12 months. We file income tax returns in the United States federal jurisdiction and state tax returns based on income in our major state operating jurisdictions of Wisconsin, Illinois, Michigan, and Minnesota. We also file tax returns in other state and local jurisdictions with varying statutes of limitations. As of December 31, 2022, with a few exceptions, we were subject to examination by federal and state or local tax authorities for the 2017 through 2022 tax years in our major operating jurisdictions as follows: Jurisdiction Years Federal 2019–2022 Illinois 2017–2022 Michigan 2018–2022 Minnesota 2018–2022 Wisconsin 2018–2022 |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2022 | |
Fair Value Disclosures [Abstract] | |
FAIR VALUE MEASUREMENTS | FAIR VALUE MEASUREMENTS The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy: December 31, 2022 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 16.3 $ 16.2 $ — $ 32.5 FTRs — — 7.8 7.8 Coal contracts — 34.5 — 34.5 Total derivative assets $ 16.3 $ 50.7 $ 7.8 $ 74.8 Investments held in rabbi trust $ 50.9 $ — $ — $ 50.9 Derivative liabilities Natural gas contracts $ 81.4 $ 15.2 $ — $ 96.6 December 31, 2021 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 46.4 $ 18.2 $ — $ 64.6 FTRs — — 2.4 2.4 Coal contracts — 53.0 — 53.0 Total derivative assets $ 46.4 $ 71.2 $ 2.4 $ 120.0 Investments held in rabbi trust $ 79.6 $ — $ — $ 79.6 Derivative liabilities Natural gas contracts $ 8.4 $ 6.7 $ — $ 15.1 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 at our electric utilities and certain of our non-utility wind parks to manage electric transmission congestion costs in the MISO Energy Markets. During 2022, we also held TCRs, which were used at certain of our non-utility wind parks to manage electric transmission congestion costs in the SPP Integrated Marketplace, but these TCRs settled prior to December 31, 2022. We hold investments in the Integrys rabbi trust. These investments are restricted as they can only be withdrawn from the trust to fund participants' benefits under the Integrys deferred compensation plan and certain Integrys non-qualified pension plans. These investments are included in other long-term assets on our balance sheets. We recorded $12.7 million of net unrealized losses in earnings related to the investments held at the end of the period during the year ended December 31, 2022. For the years ended December 31, 2021 and 2020, the net unrealized gains included in earnings related to the investments held at the end of the period were $16.0 million and $6.3 million, respectively. The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy at December 31: (in millions) 2022 2021 2020 Balance at the beginning of the period $ 2.4 $ 2.4 $ 3.1 Purchases 23.7 6.1 7.6 Realized and unrealized gains included in earnings (1) 0.5 — — Settlements (18.8) (6.1) (8.3) Balance at the end of the period $ 7.8 $ 2.4 $ 2.4 Losses included in earnings attributable to the change in unrealized losses of Level 3 derivatives held at the end of the reporting period (1) $ (0.4) $ — $ — (1) Amounts relate to FTRs and TCRs acquired by certain wind generating facilities included in our non-utility energy infrastructure segment. These realized and unrealized gains and losses are recorded in operating revenues on our income statements. Fair Value of Financial Instruments The following table shows the financial instruments included on our balance sheets that are not recorded at fair value at December 31: 2022 2021 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock of subsidiary $ 30.4 $ 22.7 $ 30.4 $ 30.3 Long-term debt, including current portion (1) 15,464.2 13,921.3 13,563.4 14,819.4 (1) The carrying amount of long-term debt excludes finance lease obligations of $183.2 million and $129.7 million at December 31, 2022 and 2021, respectively. The fair values of our long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy. |
Derivative Instruments
Derivative Instruments | 12 Months Ended |
Dec. 31, 2022 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
DERIVATIVE INSTRUMENTS | DERIVATIVE INSTRUMENTS 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 were designated as hedging instruments. December 31, 2022 December 31, 2021 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Current Natural gas contracts $ 32.5 $ 88.2 $ 60.6 $ 14.0 FTRs 7.8 — 2.4 — Coal contracts 18.9 — 44.0 — Total current 59.2 88.2 107.0 14.0 Long-term Natural gas contracts — 8.4 4.0 1.1 Coal contracts 15.6 — 9.0 — Total long-term 15.6 8.4 13.0 1.1 Total $ 74.8 $ 96.6 $ 120.0 $ 15.1 Realized gains and losses on derivatives used in our regulatory utility operations are recorded in cost of sales operating revenues December 31, 2022 December 31, 2021 December 31, 2020 (in millions) Volumes Gains Volumes Gains Volumes Gains (Losses) Natural gas contracts 183.3 Dth $ 299.5 197.6 Dth $ 136.5 188.6 Dth $ (54.1) FTRs and TCRs 27.2 MWh 11.8 28.2 MWh 17.7 29.8 MWh 4.1 Total $ 311.3 $ 154.2 $ (50.0) At December 31, 2022 and 2021, we had posted cash collateral of $122.4 million and $13.9 million, respectively. We had also received cash collateral of $13.2 million at December 31, 2021. The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets: December 31, 2022 December 31, 2021 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 74.8 $ 96.6 $ 120.0 $ 15.1 Gross amount not offset on the balance sheet (17.5) (82.5) (1) (15.2) (2) (9.2) (3) Net amount $ 57.3 $ 14.1 $ 104.8 $ 5.9 (1) Includes cash collateral posted of $65.0 million. (2) Includes cash collateral received of $6.4 million. (3) Includes cash collateral posted of $0.4 million. Cash Flow Hedges Until their expiration on November 15, 2021, we had two interest rate swaps with a combined notional value of $250.0 million to hedge the variable interest rate risk associated with our 2007 Junior Notes. The swaps provided a fixed interest rate of 4.9765% on $250.0 million of the $500.0 million of outstanding 2007 Junior Notes. As these swaps qualified for cash flow hedge accounting treatment, the related gains and losses were deferred in accumulated other comprehensive loss and were amortized to interest expense as interest was accrued on the 2007 Junior Notes. We previously entered into forward interest rate swap agreements to mitigate the interest rate exposure associated with the issuance of long-term debt related to the acquisition of Integrys. These swap agreements were settled in 2015, and we continue to amortize amounts out of accumulated other comprehensive loss into interest expense over the periods in which the interest costs are recognized in earnings. The table below shows the amounts related to these cash flow hedges recorded in other comprehensive income (loss) and in earnings, along with our total interest expense on the income statements, for the years ended December 31: (in millions) 2022 2021 2020 Derivative gain (loss) recognized in other comprehensive income / loss $ — $ 0.8 $ (5.9) Net derivative gain (loss) reclassified from accumulated other comprehensive loss to interest expense 0.4 (1.3) (2.1) Total interest expense line item on the income statements 515.1 471.1 493.7 We estimate that during the next twelve months $0.4 million will be reclassified from accumulated other comprehensive loss as a reduction to interest expense. |
Guarantees
Guarantees | 12 Months Ended |
Dec. 31, 2022 | |
Guarantees [Abstract] | |
GUARANTEES | GUARANTEES The following table shows our outstanding guarantees: Total Amounts Committed at December 31, 2022 Expiration (in millions) Less Than 1 Year 1 to 3 Years Over 3 Years Standby letters of credit (1) $ 115.7 $ 8.0 $ 0.2 $ 107.5 Surety bonds (2) 34.0 33.9 0.1 — Other guarantees (3) 9.4 — — 9.4 Total guarantees $ 159.1 $ 41.9 $ 0.3 $ 116.9 (1) At our request or the request of our subsidiaries, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to our subsidiaries. These amounts are not reflected on our balance sheets. (2) Primarily for environmental remediation, workers compensation self-insurance programs, and obtaining various licenses, permits, and rights-of-way. These amounts are not reflected on our balance sheets. (3) Related to workers compensation coverage for which a liability was recorded on our balance sheets. |
Employee Benefits
Employee Benefits | 12 Months Ended |
Dec. 31, 2022 | |
Retirement Benefits [Abstract] | |
EMPLOYEE BENEFITS | EMPLOYEE BENEFITS Pension and Other Postretirement Employee Benefits We and our subsidiaries have defined benefit pension plans that cover substantially all of our employees, as well as several unfunded non-qualified retirement plans. In addition, we and our subsidiaries offer multiple OPEB plans to employees. The benefits for a portion of these plans are funded through irrevocable trusts, as allowed for income tax purposes. We also offer medical, dental, and life insurance benefits to active employees and their dependents. We expense the costs of these benefits as incurred. Generally, former Wisconsin Energy Corporation employees who started with the company after 1995 receive a benefit based on a percentage of their annual salary plus an interest credit, while employees who started before 1996 receive a benefit based upon years of service and final average salary. Wisconsin Energy Corporation management employees hired after December 31, 2014, and certain new represented employees hired after May 1, 2017, receive an annual company contribution to their 401(k) savings plan instead of being enrolled in the defined benefit plans. For former Integrys employees, the defined benefit pension plans are closed to all new hires. In addition, the service accruals for the defined benefit pension plans were frozen for non-union employees as of January 1, 2013. These employees receive an annual company contribution to their 401(k) savings plan, which is calculated based on age, wages, and full years of vesting service as of December 31 each year. We use a year-end measurement date to measure the funded status of all of our pension and OPEB plans. Due to the regulated nature of our business, we have concluded that substantially all of the unrecognized costs resulting from the recognition of the funded status of our pension and OPEB plans qualify as a regulatory asset. The following tables provide a reconciliation of the changes in our plans' benefit obligations and fair value of assets: Pension Benefits OPEB Benefits (in millions) 2022 2021 2022 2021 Change in benefit obligation Obligation at January 1 $ 3,136.6 $ 3,346.4 $ 530.2 $ 556.1 Service cost 50.8 54.3 14.3 15.7 Interest cost 91.8 87.5 15.4 14.5 Participant contributions — — 12.5 12.5 Plan amendments — — 0.2 (3.9) Actuarial gain (682.3) (101.3) (127.9) (20.3) Benefit payments (281.0) (250.3) (45.7) (47.5) Federal subsidy on benefits paid N/A N/A 1.4 1.2 Transfer — — 1.9 1.9 Obligation at December 31 $ 2,315.9 $ 3,136.6 $ 402.3 $ 530.2 Change in fair value of plan assets Fair value at January 1 $ 3,328.9 $ 3,225.0 $ 1,000.2 $ 951.4 Actual return on plan assets (431.3) 291.8 (135.4) 79.9 Employer contributions 11.4 62.4 3.7 3.9 Participant contributions — — 12.5 12.5 Benefit payments (281.0) (250.3) (45.7) (47.5) Fair value at December 31 $ 2,628.0 $ 3,328.9 $ 835.3 $ 1,000.2 Funded status at December 31 $ 312.1 $ 192.3 $ 433.0 $ 470.0 In 2022 and 2021, we had actuarial gains related to our pension benefit obligations of $682.3 million and $101.3 million, respectively, both of which were primarily driven by changes in our discount rates. The discount rate for our pension benefits was 5.49%, 2.96%, and 2.67%, in 2022, 2021, and 2020, respectively. In 2022, we had an actuarial gain related to our OPEB benefit obligation of $127.9 million, which was primarily driven by an increase in our discount rate. The discount rate for our OPEB benefits was 5.50% and 2.92%, in 2022 and 2021, respectively. The 2021 actuarial gain related to our OPEB benefit obligations was not significant. The amounts recognized on our balance sheets at December 31 related to the funded status of the benefit plans were as follows: Pension Benefits OPEB Benefits (in millions) 2022 2021 2022 2021 Pension and OPEB assets $ 470.6 $ 389.0 $ 446.1 $ 492.3 Pension and OPEB obligations 158.5 196.7 13.1 22.3 Total net assets $ 312.1 $ 192.3 $ 433.0 $ 470.0 The accumulated benefit obligation for all defined benefit pension plans was $2,250.6 million and $3,010.5 million as of December 31, 2022 and 2021, respectively. The following table shows information for pension plans with an accumulated benefit obligation in excess of plan assets. Amounts presented are as of December 31: (in millions) 2022 2021 Accumulated benefit obligation $ 185.7 $ 372.4 Fair value of plan assets 32.8 186.3 The following table shows information for pension plans with a projected benefit obligation in excess of plan assets. Amounts presented are as of December 31: (in millions) 2022 2021 Projected benefit obligation $ 191.3 $ 383.0 Fair value of plan assets 32.8 186.3 The following table shows information for OPEB plans with an accumulated benefit obligation in excess of plan assets. Amounts presented are as of December 31: (in millions) 2022 2021 Accumulated benefit obligation $ 20.6 $ 25.1 Fair value of plan assets 7.4 2.8 The following table shows the amounts that had not yet been recognized in our net periodic benefit cost (credit) as of December 31: Pension Benefits OPEB Benefits (in millions) 2022 2021 2022 2021 Pre-tax accumulated other comprehensive income (loss) (1) Net actuarial loss (gain) $ 12.2 $ 7.5 $ (1.6) $ (1.4) Prior service credits — — — (0.1) Total $ 12.2 $ 7.5 $ (1.6) $ (1.5) Net regulatory assets (liabilities) (2) Net actuarial loss (gain) $ 669.2 $ 798.6 $ (200.8) $ (300.1) Prior service credits (2.1) (0.5) (44.2) (60.3) Total $ 667.1 $ 798.1 $ (245.0) $ (360.4) (1) Amounts related to the nonregulated entities are included in accumulated other comprehensive loss. (2) Amounts related to the utilities and WBS are recorded as net regulatory assets or liabilities. The components of net periodic benefit cost (credit) (including amounts capitalized to our balance sheets) for the years ended December 31 were as follows: Pension Benefits OPEB Benefits (in millions) 2022 2021 2020 2022 2021 2020 Service cost $ 50.8 $ 54.3 $ 50.1 $ 14.3 $ 15.7 $ 15.2 Interest cost 91.8 87.5 102.8 15.4 14.5 18.6 Expected return on plan assets (208.0) (200.9) (190.3) (68.9) (66.0) (60.3) Plan settlement 6.2 3.9 17.9 — — — Plan curtailment — — — — (6.4) — Amortization of prior service cost (credit) 1.6 1.6 1.6 (15.9) (15.9) (15.0) Amortization of net actuarial loss (gain) 75.3 109.4 102.6 (24.7) (24.4) (22.4) Net periodic benefit cost (credit) $ 17.7 $ 55.8 $ 84.7 $ (79.8) $ (82.5) $ (63.9) The weighted-average assumptions used to determine the benefit obligations for the plans were as follows for the years ended December 31: Pension Benefits OPEB Benefits 2022 2021 2022 2021 Discount rate 5.49% 2.96% 5.50% 2.92% Rate of compensation increase 4.00% 4.00% N/A N/A Interest credit rate 4.61% 3.73% N/A N/A Assumed medical cost trend rate (Pre 65) N/A N/A 6.50% 5.70% Ultimate trend rate (Pre 65) N/A N/A 5.00% 5.00% Year ultimate trend rate is reached (Pre 65) N/A N/A 2031 2028 Assumed medical cost trend rate (Post 65) N/A N/A 6.00% 5.67% Ultimate trend rate (Post 65) N/A N/A 5.00% 5.00% Year ultimate trend rate is reached (Post 65) N/A N/A 2031 2028 The weighted-average assumptions used to determine the net periodic benefit cost for the plans were as follows for the years ended December 31: Pension Benefits 2022 2021 2020 Discount rate 3.18% 2.71% 3.34% Expected return on plan assets 6.88% 6.88% 6.87% Rate of compensation increase 4.00% 4.00% 4.00% Interest credit rate 3.78% 3.71% 3.70% OPEB Benefits 2022 2021 2020 Discount rate 2.92% 2.66% 3.39% Expected return on plan assets 7.00% 7.00% 7.00% Assumed medical cost trend rate (Pre 65) 5.70% 5.85% 6.00% Ultimate trend rate (Pre 65) 5.00% 5.00% 5.00% Year ultimate trend rate is reached (Pre 65) 2028 2028 2028 Assumed medical cost trend rate (Post 65) 5.67% 5.80% 5.91% Ultimate trend rate (Post 65) 5.00% 5.00% 5.00% Year ultimate trend rate is reached (Post 65) 2028 2028 2028 We consult with our investment advisors on an annual basis to help us forecast expected long-term returns on plan assets by reviewing historical returns as well as calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the trust. For 2023, the expected return on assets assumption is 6.88% for the pension plans and 7.00% for the OPEB plans. Plan Assets Current pension trust assets and amounts which are expected to be contributed to the trusts in the future are expected to be adequate to meet pension payment obligations to current and future retirees. The Investment Trust Policy Committee oversees investment matters related to all of our funded benefit plans. The Committee works with external actuaries and investment consultants on an on-going basis to establish and monitor investment strategies and target asset allocations. Forecasted cash flows for plan liabilities are regularly updated based on annual valuation results. Target allocations are determined utilizing projected benefit payment cash flows and risk analyses of appropriate investments. They are intended to reduce risk, provide long-term financial stability for the plans and maintain funded levels which meet long-term plan obligations while preserving sufficient liquidity for near-term benefit payments. The legacy Wisconsin Energy Corporation pension trust target asset allocations are 30% equity investments, 55% fixed income investments, and 15% private equity and real estate investments. The legacy Integrys pension trust target asset allocations are 40% equity investments, 45% fixed income investments, and 15% private equity and real estate investments. The legacy Wisconsin Energy Corporation OPEB trust target asset allocations are 50% equity investments, 40% fixed income investments, and 10% real estate investments. The two largest legacy OPEB trusts for Integrys have the same target asset allocations of 45% equity investments, 45% fixed income investments, and 10% real estate investments. Equity securities include investments in large-cap, mid-cap, and small-cap companies. Fixed income securities include corporate bonds of companies from diversified industries, mortgage and other asset backed securities, commercial paper, and United States Treasuries. Pension and OPEB plan investments are recorded at fair value. See Note 1(r), Fair Value Measurements, for more information regarding the fair value hierarchy and the classification of fair value measurements based on the types of inputs used. The following tables provide the fair values of our investments by asset class: December 31, 2022 Pension Plan Assets OPEB Assets (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Asset Class Equity securities: United States equity $ 231.5 $ — $ — $ 231.5 $ 92.5 $ — $ — $ 92.5 International equity 202.2 — — 202.2 83.9 — — 83.9 Fixed income securities: (1) United States bonds — 838.7 — 838.7 129.8 145.3 — 275.1 International bonds — 95.0 — 95.0 — 13.2 — 13.2 433.7 933.7 — 1,367.4 306.2 158.5 — 464.7 Investments measured at net asset value: Equity securities 466.0 186.6 Fixed income securities 101.0 65.5 Other 693.6 118.5 Total $ 2,628.0 $ 835.3 (1) This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries. December 31, 2021 Pension Plan Assets OPEB Assets (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Asset Class Equity securities: United States equity $ 417.1 $ — $ — $ 417.1 $ 135.4 $ — $ — $ 135.4 International equity 313.7 — — 313.7 109.1 — — 109.1 Fixed income securities: (1) United States bonds — 1,068.7 — 1,068.7 165.0 192.3 — 357.3 International bonds — 118.5 — 118.5 — 15.6 — 15.6 730.8 1,187.2 — 1,918.0 409.5 207.9 — 617.4 Investments measured at net asset value: Equity securities 659.2 224.5 Fixed income securities 127.7 112.3 Other 624.0 46.0 Total $ 3,328.9 $ 1,000.2 (1) This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries. Cash Flows We expect to contribute $14.5 million to the pension plans and $2.1 million to the OPEB plans in 2023, dependent upon various factors affecting us, including our liquidity position and possible tax law changes. The following table shows the payments, reflecting expected future service, that we expect to make for pension and OPEB over the next 10 years: (in millions) Pension Benefits OPEB Benefits 2023 $ 209.6 $ 34.5 2024 207.2 34.3 2025 200.1 34.2 2026 202.1 34.3 2027 193.5 34.4 2028-2032 866.5 168.0 Savings Plans We sponsor 401(k) savings plans which allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with plan-specified guidelines. A percentage of employee contributions are matched by us through a contribution into the employee's savings plan account, up to certain limits. The 401(k) savings plans include an Employee Stock Ownership Plan. Certain employees receive an employer retirement contribution, in which amounts are contributed to the employee's savings plan account based on the employee's wages, age, and years of service. Total costs incurred under all of these plans were $54.4 million, $51.8 million, and $49.7 million in 2022, 2021, and 2020, respectively. |
Investment in Transmission Affi
Investment in Transmission Affiliates | 12 Months Ended |
Dec. 31, 2022 | |
Equity Method Investments and Joint Ventures [Abstract] | |
INVESTMENT IN TRANSMISSION AFFILATES | INVESTMENT IN TRANSMISSION AFFILIATES We own approximately 60% of ATC, a for-profit, transmission-only company regulated by the FERC for cost of service and certain state regulatory commissions for routing and siting of transmission projects. We also own approximately 75% of ATC Holdco, a separate entity formed in December 2016 to invest in transmission-related projects outside of ATC's traditional footprint. ATC's corporate manager has an eleven-member board of directors, and ATC Holdco's corporate manager has a four-member board of directors. We have one representative on each board. Each member of the board has only one vote. The following tables provide a reconciliation of the changes in our investments in ATC and ATC Holdco: 2022 (in millions) ATC ATC Holdco Total Balance at January 1 $ 1,766.9 $ 22.5 $ 1,789.4 Add: Earnings from equity method investment 192.6 2.1 194.7 Add: Capital contributions 45.5 — 45.5 Less: Distributions 120.4 — 120.4 Balance at December 31 $ 1,884.6 $ 24.6 $ 1,909.2 2021 (in millions) ATC ATC Holdco Total Balance at January 1 $ 1,733.5 $ 30.8 $ 1,764.3 Add: Earnings (loss) from equity method investment 166.4 (8.3) 158.1 Less: Distributions 133.0 — 133.0 Balance at December 31 $ 1,766.9 $ 22.5 $ 1,789.4 2020 (in millions) ATC ATC Holdco Total Balance at January 1 $ 1,684.7 $ 36.1 $ 1,720.8 Add: Earnings from equity method investment 174.3 1.5 175.8 Add: Capital contributions 21.2 — 21.2 Less: Distributions 146.7 — 146.7 Less: Return of capital — 6.8 6.8 Balance at December 31 $ 1,733.5 $ 30.8 $ 1,764.3 In November 2019 and May 2020, the FERC issued orders that addressed complaints related to ATC's allowed ROE. Due to the various petitions related to the complaint filed in February 2015, our financials at December 31, 2021 and 2020, included a $39.1 million liability for potential future refunds that ATC may have been required to provide. In August 2022, a decision issued by the D.C. Circuit Court of Appeals affirmed the FERC’s previous orders related to the February 2015 complaint. Therefore, during the third quarter of 2022, we reversed the liability that was previously recorded, which increased our equity earnings from ATC. We pay ATC for network transmission and other related services it provides. In addition, we provide a variety of operational, maintenance, and project management work for ATC, which is reimbursed by ATC. We are also required to initially fund the construction of transmission infrastructure upgrades needed for new generation projects. ATC owns these transmission assets and reimburses us for these costs when the new generation is placed in service. The following table summarizes our significant related party transactions with ATC during the years ended December 31: (in millions) 2022 2021 2020 Charges to ATC for services and construction $ 18.9 $ 22.9 $ 27.5 Charges from ATC for network transmission services 363.7 361.0 350.5 Net refund (payment) from (to) ATC related to FERC ROE orders (0.1) 7.3 10.7 As of December 31, 2022 and 2021, our balance sheets included the following receivables and payables for services provided to or received from ATC: (in millions) 2022 2021 Accounts receivable for services provided to ATC $ 1.2 $ 2.0 Accounts payable for services received from ATC 30.4 30.2 Amounts due from ATC for transmission infrastructure upgrades (1) 26.6 13.0 (1) The transmission infrastructure upgrades were primarily related to the construction of WE's and WPS's renewable energy projects. Summarized financial data for ATC is included in the tables below: Year Ended December 31 (in millions) 2022 2021 2020 Income statement data Operating revenues $ 751.2 $ 754.8 $ 758.1 Operating expenses 381.5 376.2 372.5 Other expense, net 123.0 113.9 110.8 Net income $ 246.7 $ 264.7 $ 274.8 (in millions) December 31, 2022 December 31, 2021 Balance sheet data Current assets $ 89.6 $ 89.8 Noncurrent assets 5,997.8 5,628.1 Total assets $ 6,087.4 $ 5,717.9 Current liabilities $ 511.9 $ 436.9 Long-term debt 2,613.0 2,513.0 Other noncurrent liabilities 485.8 422.0 Members' equity 2,476.7 2,346.0 Total liabilities and members' equity $ 6,087.4 $ 5,717.9 |
Segment Information
Segment Information | 12 Months Ended |
Dec. 31, 2022 | |
Segment Reporting [Abstract] | |
SEGMENT INFORMATION | SEGMENT INFORMATION We use net income attributed to common shareholders to measure segment profitability and to allocate resources to our businesses. At December 31, 2022, we reported six segments, which are described below. • The Wisconsin segment includes the electric and natural gas utility operations of WE, WPS, WG, and UMERC. • The Illinois segment includes the natural gas utility operations of PGL and NSG. • The other states segment includes the natural gas utility and non-utility operations of MERC and MGU. • The electric transmission segment includes our approximate 60% ownership interest in ATC, a for-profit, transmission-only company regulated by the FERC for cost of service and certain state regulatory commissions for routing and siting of transmission projects, and our approximate 75% ownership interest in ATC Holdco, which was formed to invest in transmission-related projects outside of ATC's traditional footprint. • The non-utility energy infrastructure segment includes: ◦ We Power, which owns and leases generating facilities to WE, ◦ Bluewater, which owns underground natural gas storage facilities in Michigan that provide approximately one-third of the current storage needs for our Wisconsin natural gas utilities, and ◦ WECI, which owns majority interests in multiple renewable generating facilities. See Note 2, Acquisitions, for more information on recent WECI acquisitions. • The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, the PELLC holding company, Wispark, Wisvest, WECC, WBS, and also included the operations of PDL prior to the sale of its remaining solar facilities in the fourth quarter of 2020. See Note 3, Dispositions, for more information on the sale of these solar facilities. All of our operations and assets are located within the United States. The following tables show summarized financial information related to our reportable segments for the years ended December 31, 2022, 2021, and 2020. Utility Operations 2022 (in millions) Wisconsin Illinois Other States Total Utility Electric Transmission Non-Utility Energy Infrastructure Corporate and Other Reconciling WEC Energy Group Consolidated External revenues $ 6,960.5 $ 1,890.9 $ 618.5 $ 9,469.9 $ — $ 127.0 $ 0.5 $ — $ 9,597.4 Intersegment revenues — — — — — 463.0 — (463.0) — Other operation and maintenance 1,351.3 459.2 98.5 1,909.0 — 51.0 (12.9) (9.1) 1,938.0 Depreciation and amortization 754.7 230.9 40.9 1,026.5 — 139.2 25.0 (68.1) 1,122.6 Equity in earnings of transmission affiliates — — — — 194.7 — — — 194.7 Interest expense 555.9 73.8 13.9 643.6 19.4 68.9 119.4 (336.2) 515.1 Income tax expense (benefit) 247.5 83.1 13.1 343.7 45.8 (20.9) (45.7) — 322.9 Net income (loss) 759.6 226.9 39.7 1,026.2 129.5 324.8 (70.8) — 1,409.7 Net income (loss) attributed to common shareholders 758.4 226.9 39.7 1,025.0 129.5 324.4 (70.8) — 1,408.1 Capital expenditures and asset acquisitions 1,610.8 484.9 101.1 2,196.8 — 483.8 16.3 — 2,696.9 Total assets (1) 27,384.0 8,101.0 1,639.6 37,124.6 1,909.4 5,320.6 774.0 (3,256.5) 41,872.1 (1) Total assets at December 31, 2022 reflect an elimination of $1,632.9 million for all lease activity between We Power and WE. Utility Operations 2021 (in millions) Wisconsin Illinois Other States Total Utility Electric Transmission Non-Utility Energy Infrastructure Corporate and Other Reconciling WEC Energy Group Consolidated External revenues $ 6,037.0 $ 1,672.8 $ 519.0 $ 8,228.8 $ — $ 86.7 $ 0.5 $ — $ 8,316.0 Intersegment revenues — — — — — 452.8 — (452.8) — Other operation and maintenance 1,455.2 433.5 90.4 1,979.1 — 43.1 (7.5) (9.2) 2,005.5 Depreciation and amortization 726.9 218.1 38.1 983.1 — 125.3 25.9 (60.0) 1,074.3 Equity in earnings of transmission affiliates — — — — 158.1 — — — 158.1 Interest expense 555.6 66.6 6.2 628.4 19.4 71.0 92.8 (340.5) 471.1 Loss on debt extinguishment — — — — — — 36.3 — 36.3 Income tax expense (benefit) 119.9 79.3 11.5 210.7 32.3 3.1 (45.8) — 200.3 Net income (loss) 707.7 223.0 35.8 966.5 106.3 276.2 (50.5) — 1,298.5 Net income (loss) attributed to common shareholders 706.5 223.0 35.8 965.3 106.3 279.2 (50.5) — 1,300.3 Capital expenditures and asset acquisitions 1,389.7 533.7 95.9 2,019.3 — 335.3 18.1 — 2,372.7 Total assets (1) 25,687.9 7,853.4 1,506.1 35,047.4 1,792.7 4,627.7 785.3 (3,264.6) 38,988.5 (1) Total assets at December 31, 2021 reflect an elimination of $1,729.9 million for all lease activity between We Power and WE. Utility Operations 2020 (in millions) Wisconsin Illinois Other States Total Utility Electric Transmission Non-Utility Energy Infrastructure Corporate and Other Reconciling WEC Energy Group Consolidated External revenues $ 5,473.5 $ 1,321.9 $ 384.1 $ 7,179.5 $ — $ 60.0 $ 2.2 $ — $ 7,241.7 Intersegment revenues — — — — — 448.5 — (448.5) — Other operation and maintenance 1,476.7 435.4 87.0 1,999.1 — 24.9 17.4 (9.2) 2,032.2 Depreciation and amortization 674.5 196.7 33.5 904.7 — 98.9 25.1 (52.8) 975.9 Equity in earnings of transmission affiliates — — — — 175.8 — — — 175.8 Interest expense 561.3 63.5 10.2 635.0 19.4 60.8 124.0 (345.5) 493.7 Loss on debt extinguishment — — — — — — 38.4 — 38.4 Income tax expense (benefit) 132.7 66.1 13.1 211.9 43.7 44.7 (72.4) — 227.9 Net income (loss) 691.6 203.5 39.0 934.1 112.6 261.1 (106.4) — 1,201.4 Net income (loss) attributed to common shareholders 690.4 203.5 39.0 932.9 112.6 260.8 (106.4) — 1,199.9 Capital expenditures and asset acquisitions 1,382.4 652.7 144.3 2,179.4 — 661.8 33.1 — 2,874.3 Total assets (1) 24,599.2 7,471.8 1,336.2 33,407.2 1,764.7 4,455.2 762.2 (3,361.2) 37,028.1 (1) Total assets at December 31, 2020 reflect an elimination of $1,824.5 million for all lease activity between We Power and WE. |
Variable Interest Entities
Variable Interest Entities | 12 Months Ended |
Dec. 31, 2022 | |
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 WE's 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 WE 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 a wholly owned subsidiary of WE. In May 2021, WEPCo Environmental Trust issued ETBs and used the proceeds to acquire environmental control property from WE. 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 WE's 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 WE or any of WE's affiliates. WE acts as the servicer of the environmental control property on behalf of WEPCo Environmental Trust and is responsible for metering, calculating, billing, and collecting the environmental control charge. As necessary, WE is 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 remits 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 has the power to direct the activities that most significantly impact WEPCo Environmental Trust's economic performance. Therefore, WE is 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) December 31, 2022 December 31, 2021 Assets Other current assets (restricted cash) $ 3.0 $ 2.4 Regulatory assets 92.4 100.7 Other long-term assets (restricted cash) 0.6 0.6 Liabilities Current portion of long-term debt 8.9 8.8 Other current liabilities (accrued interest) 0.1 0.1 Long-term debt 94.1 102.7 Investment in Transmission Affiliates We own approximately 60% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. We have determined that ATC is a VIE but consolidation is not required since we are not ATC's primary beneficiary. As a result of our limited voting rights, we do not have the power to direct the activities that most significantly impact ATC's economic performance. Therefore, we account for ATC as an equity method investment. At December 31, 2022 and 2021, our equity investment in ATC was $1,884.6 million and $1,766.9 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC. We also own approximately 75% of ATC Holdco, a separate entity formed in December 2016 to invest in transmission-related projects outside of ATC's traditional footprint. We have determined that ATC Holdco is a VIE but consolidation is not required since we are not ATC Holdco's primary beneficiary. As a result of our limited voting rights, we do not have the power to direct the activities that most significantly impact ATC Holdco's economic performance. Therefore, we account for ATC Holdco as an equity method investment. At December 31, 2022 and 2021, our equity investment in ATC Holdco was $24.6 million and $22.5 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC Holdco. See Note 21, Investment in Transmission Affiliates, for more information, including any significant assets and liabilities related to ATC and ATC Holdco recorded on our balance sheets. Power Purchase Commitment On May 31, 2022, WE's 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 | 12 Months Ended |
Dec. 31, 2022 | |
Commitments and Contingencies Disclosure [Abstract] | |
COMMITMENTS AND CONTINGENCIES | COMMITMENTS AND CONTINGENCIES We and our subsidiaries 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 Our electric utilities have obligations to distribute and sell electricity to their customers, and our natural gas utilities have obligations to distribute and sell natural gas to their customers. The utilities expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. The generation facilities that are part of our non-utility energy infrastructure segment have obligations to distribute and sell electricity through long-term offtake agreements with their customers for all of the energy produced. In order to support these sales obligations, these companies enter into easements and other service agreements associated with the generating facilities. The following table shows our minimum future commitments related to these purchase obligations as of December 31, 2022, including those of our subsidiaries: Payments Due By Period (in millions) Date Contracts Extend Through Total Amounts Committed 2023 2024 2025 2026 2027 Later Years Electric utility: Nuclear 2033 $ 6,829.1 $ 548.5 $ 600.3 $ 634.5 $ 681.6 $ 730.4 $ 3,633.8 Coal supply and transportation 2030 936.1 393.3 279.2 207.9 24.7 7.6 23.4 Purchased power 2051 256.2 63.4 54.2 47.8 44.2 19.6 27.0 Natural gas utility: Supply and transportation 2048 1,938.8 382.1 344.2 228.4 173.7 158.8 651.6 Non-utility energy infrastructure: Purchased power 2049 495.0 26.2 26.1 26.7 27.3 27.8 360.9 Natural gas storage and transportation 2048 5.8 4.9 0.1 — — — 0.8 Total $ 10,461.0 $ 1,418.4 $ 1,304.1 $ 1,145.3 $ 951.5 $ 944.2 $ 4,697.5 Environmental Matters Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as SO 2 , NOx, fine particulates, mercury, and GHGs; water intake and discharges; management of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites. We have continued to pursue a proactive strategy to manage our environmental compliance obligations, including: • the development of additional sources of renewable electric energy supply; • the addition of improvements for water quality matters such as treatment technologies to meet regulatory discharge limits and improvements to our cooling water intake systems; • the addition of emission control equipment to existing facilities to comply with ambient air quality standards and federal clean air rules; • the protection of wetlands and waterways, biodiversity including threatened and endangered species, and cultural resources associated with utility construction projects; • the retirement of older coal-fired power plants and conversion to modern, efficient, natural gas generation, super-critical pulverized coal generation, and/or replacement with renewable generation; • the beneficial use of ash and other products from coal-fired and biomass generating units; • the remediation of former manufactured gas plant sites; • the reduction of methane emissions across our natural gas distribution system by upgrading infrastructure; and • the reporting of GHG emissions to comply with federal clean air rules. Air Quality Cross State Air Pollution Rule – Good Neighbor Plan The proposed rule to address the 2015 ozone NAAQS, resulting in more stringent regulation of ozone-season NOx emissions from electric utility generating units in 26 states, is expected to take effect in 2023. Based on a review of our existing units' 2020 and 2021 actual ozone season emissions and projected future emissions versus proposed NOx ozone season allocations, we anticipate that we should be able to comply with the expanded rule requirements without procuring additional allowances on the open market. Our RICE units in the Upper Peninsula of Michigan and planned RICE units in Wisconsin are not subject to this rule as proposed as each unit is less than 25 MW. We note that, 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. In June 2022, we submitted comments on this proposed rule seeking clarification of its applicability, as well as other items, and we will closely monitor the final rule for any changes from the proposed rule. 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 had planned a proposed rule in April 2023, but the CASAC review is expected to slow the process. In June 2021, the EPA published its final action to revise the nonattainment area designations and/or boundaries for 13 counties associated with six nonattainment areas, including several in Illinois and Wisconsin. Under the new designations, all of Milwaukee and Ozaukee counties are now listed as nonattainment and portions of Racine, Waukesha, and Washington counties have been added to the "Milwaukee" nonattainment area. Additionally, the Chicago, IL-IN-WI nonattainment area now includes an expanded portion of Kenosha County, and the partial nonattainment areas of Sheboygan, Door, and Manitowoc counties were also expanded. In February 2022, revisions to the Wisconsin Administrative Code to adopt the 2015 standard were finalized. The amended regulations adopted the standard and 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 in April 2022, which the EPA proposed to approve in August 2022. 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 will 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 must submit a SIP revision to address the moderate nonattainment status. We also expect the moderate nonattainment designation to impact emission offset ratios for major construction permitting in these areas. 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. We anticipate the final rule to be released in late 2023. All counties within our service territories 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 territories 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 a SIP and submit for the EPA's approval. Climate Change The ACE 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 vacating the EPA's ACE rule 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 CAA but cannot rely on generation shifting to lower carbon emitting sources to do so. We expect a new GHG replacement rule for existing sources to be proposed in March 2023. In January 2021, the EPA finalized a rule to revise the NSPS 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. Based on an updated EPA regulatory timeline, we expect a new rule to be proposed in March 2023. We continue to move forward on the ESG Progress Plan, which is heavily focused on reducing GHG emissions. The EPA released proposed regulations for the Greenhouse Gas Reporting Rule, 40 CFR Part 98, in June 2022. The proposed revisions could impact the reporting required of our local natural gas distribution companies and underground natural gas storage facilities with updates to emission factors for equipment counts and increased disclosure for large release events. We expect the final rule in 2023, pending the EPA's review and consideration of public comments. Our 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 more than 1,800 MW of coal-fired generation since the beginning of 2018. Through our ESG Progress Plan, we expect to retire approximately 1,600 MW of additional fossil-fueled generation by the end of 2026, which includes the planned retirements in 2024-2025 of OCPP Units 5-8 and the planned retirement by June 2026 of jointly-owned Columbia Units 1-2. See Note 7, Property, Plant, and Equipment, for more information on the timing of the retirements. In May 2021, we announced goals to achieve reductions in carbon emissions from our electric generation fleet by 60% by the end of 2025 and by 80% by the end of 2030, both from a 2005 baseline. We expect to achieve these goals by making operating refinements, retiring less efficient generating units, and executing our capital plan. Over the longer term, the target for our generation fleet is net-zero CO 2 emissions by 2050. We also continue to reduce methane emissions by improving our natural gas distribution system and have set a target across our natural gas distribution operations to achieve net-zero methane emissions by the end of 2030. We plan to achieve our net-zero goal through an effort that includes both continuous operational improvements and equipment upgrades, as well as the use of RNG throughout our utility systems. We are required to report our CO 2 equivalent emissions from the electric generating facilities we operate under the EPA Greenhouse Gases Reporting Program. Based upon our preliminary analysis of the data, we estimate that we will report CO 2 equivalent emissions of approximately 19.5 million metric tonnes to the EPA for 2022. The level of CO 2 and other GHG emissions varies from year to year and is dependent on the level of electric generation and mix of fuel sources, which is determined primarily by demand, the availability of the generating units, the unit cost of fuel consumed, and how our units are dispatched by MISO. We are also required to report CO 2 equivalent emissions related to the natural gas that our natural gas utilities distribute and sell. Based upon our preliminary analysis of the data, we estimate that we will report CO 2 equivalent emissions of approximately 29.3 million metric tonnes to the EPA for 2022. Water Quality Clean Water Act Cooling Water Intake Structure Rule In August 2014, the EPA issued a final regulation under Section 316(b) of the Clean Water Act that requires the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the BTA for minimizing adverse environmental impacts. The federal rule became effective in October 2014 and applies to all of our existing generating facilities with cooling water intake structures, except for the ERGS units, which were permitted and received a final BTA determination under the rules governing new facilities. In 2016, the WDNR initiated a state rulemaking process to incorporate the federal Section 316(b) requirements into the Wisconsin Administrative Code. This new state rule, NR 111, became effective in June 2020, and the WDNR will apply it when establishing BTA requirements for cooling water intake structures at existing facilities. These BTA requirements are incorporated into WPDES permits for WE and WPS facilities. We have received a final BTA determination for VAPP. We have received interim BTA determinations for PWGS, OCPP Units 5-8 and Weston Units 2, 3, and 4. Existing technology at the PWGS may satisfy the BTA requirements; however, a final determination will not be made until the WPDES permit is renewed for this facility, which is expected in the first half of 2023. 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 may be retired prior to the WDNR making a final BTA decision anticipated in 2025. In addition, we believe that existing technology installed at the Weston facility will result in a final BTA determination during the WPDES permit reissuance in 2023. As a result of past capital investments completed to address Section 316(b) compliance at WE and WPS, we believe our fleet overall is well positioned to continue to meet this regulation and do not expect to incur significant additional compliance costs. Steam Electric Effluent Limitation Guidelines The EPA's final 2015 ELG rule took effect in January 2016 and was modified in 2020 to revise the treatment technology requirements related to BATW and wet FGD wastewaters at existing facilities. This rule created new requirements for several types of power plant wastewaters. The two new requirements that affect WE and WPS relate to discharge limits for BATW and wet FGD wastewater. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. There will, however, need to be facility modifications to meet water permit requirements for the BATW system at Weston Unit 3, which is expected to be completed by December 2023. Modifications to OC 7 and OC 8 BATW systems were completed and placed in-service in mid-2021. Wastewater treatment system modifications also will be required for wet FGD discharges and site wastewater from the ERGS units. Based on existing contracts and engineering cost estimates, we expect that compliance with the ELG rule will require $100 million in capital investment. In December 2021, the PSCW issued a Certificate of Authority approving the 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 July 2021, the EPA announced its intention to initiate a "supplemental rulemaking" to revise the ELG Reconsideration Rule that was finalized in late 2020. The EPA has stated that the 2020 ELG Rule will continue to be implemented and enforced while the agency pursues this rulemaking process. As part of their regulatory agenda, the EPA Office of Water included plans to issue a direct final rule reopening the NOPP deadline to enter the cessation of the coal subcategory (i.e. unit retirements or conversions to natural gas by the end of December 2028 instead of making capital investments to add more treatment technology) established in the 2020 ELG Rule. The new NOPP deadline will be 90 days after publication in the Federal Register , which is anticipated during the first quarter of 2023. The EPA will publish the direct final rule at the same time as the proposed ELG supplemental rulemaking. 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 will be effective 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 January 2022, the Supreme Court granted certiorari 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 in spring 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 our utilities 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. Our natural gas utilities are responsible for the environmental remediation of these sites, some of which are in the EPA Superfund Alternative Approach Program. We are also working with various state jurisdictions in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure. In addition, we are coordinating the investigation and cleanup of some of these sites subject to the jurisdiction of the EPA under what is called a "multisite" program. This program involves prioritizing the work to be done at the sites, preparation and approval of documents common to all of the sites, and use of a consistent approach in selecting remedies. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below. The future costs for detailed site investigation, future remediation, and monitoring are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation. Historically, our regulators have allowed us to recover incurred costs, net of insurance recoveries and recoveries from potentially responsible parties, associated with the remediation of manufactured gas plant sites. Accordingly, we have established regulatory assets for costs associated with these sites. We have established the following regulatory assets and reserves for manufactured gas plant sites as of December 31: (in millions) 2022 2021 Regulatory assets $ 610.7 $ 630.9 Reserves for future environmental remediation 499.6 532.6 Renewables, Efficiency, and Conservation Wisconsin Legislation In 2005, Wisconsin enacted Act 141, which established a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources annually. WE and WPS have achieved their required renewable energy percentages of 8.27% and 9.74%, respectively, by constructing various wind parks, solar parks, a biomass facility, and by also relying on renewable energy purchases. WE and WPS continue to review their renewable energy portfolios and acquire cost-effective renewables as needed to meet their requirements on an ongoing basis. The PSCW administers the renewable program related to Act 141, and each utility funds the program based on 1.2% of its annual retail operating revenues. Michigan Legislation In December 2016, Michigan enacted Act 342, which required 12.5% of the state's electric energy to come from renewables for 2019 and 2020, and energy optimization (efficiency) targets up to 1% annually. The renewable requirement increased to 15.0% for 2021 and beyond. UMERC was in compliance with its requirements under this statute as of December 31, 2022. The legislation continues to allow recovery of costs incurred to meet the standards and provides for ongoing review and revision to assure the measures taken are cost-effective. Enforcement and Litigation Matters We and our subsidiaries are involved in legal and administrative proceedings before various courts and agencies with respect to matters arising in the ordinary course of business. Although we are unable to predict the outcome of these matters, management believes that appropriate reserves have been established and that final settlement of these actions will not have a material impact on our financial condition or results of operations. Consent Decrees Wisconsin Public Service Corporation – Weston and Pulliam Power Plants In November 2009, the EPA issued an NOV to WPS, which alleged violations of the CAA's New Source Review requirements relating to certain projects completed at the Weston and Pulliam power plants from 1994 to 2009. WPS entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Eastern District of Wisconsin in March 2013. With the retirement of Pulliam Units 7 and 8 in October 2018, WPS completed the mitigation projects required by the Consent Decree and received a completeness letter from the EPA in October 2018. See Note 6, Regulatory Assets and Liabilities, for more information about the retirement. We are working with the EPA on a closeout process for the Consent Decree and expect that process to begin in 2023. Joint Ownership Power Plants – Columbia and Edgewater In December 2009, the EPA issued an NOV to Wisconsin Power and Light Company, the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including Madison Gas and Electric Company, WE (former co-owner of an Edgewater unit), and WPS. The NOV alleged violations of the CAA's New Source Review requirements related to certain projects completed at those plants. WPS, along with Wisconsin Power and Light Company, Madison Gas and Electric Company, and WE, |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | 12 Months Ended |
Dec. 31, 2022 | |
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract] | |
SUPPLEMENTAL CASH FLOW INFORMATION | SUPPLEMENTAL CASH FLOW INFORMATION Year Ended December 31 (in millions) 2022 2021 2020 Cash paid for interest, net of amount capitalized $ 485.2 $ 473.8 $ 492.9 Cash paid for income taxes, net 52.4 33.8 27.9 Significant non-cash investing and financing transactions: Accounts payable related to construction costs 197.4 127.8 153.1 Increase in receivable related to insurance proceeds — 41.7 2.7 Liabilities accrued for software licensing agreement 7.4 — — The statements of cash flows include our activity related to cash, cash equivalents, and restricted cash. Our restricted cash consists of the following: • Cash held in the Integrys rabbi trust, which is used to fund participants' benefits under the Integrys deferred compensation plan and certain Integrys non-qualified pension plans. All assets held within the rabbi trust are restricted as they can only be withdrawn from the trust to make qualifying benefit payments. • Cash on deposit in financial institutions that is restricted to satisfy the requirements of certain debt agreements at WECI Wind Holding I and WEPCo Environmental Trust. • Cash we received when WECI acquired ownership interests in certain wind generation projects. This cash is restricted as it can only be used to pay for any remaining costs associated with the construction of the wind generation facilities. • Cash used by WE and WPS for the purchase of 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 on the purchase of this facility. The following table reconciles the cash, cash equivalents, and restricted cash amounts reported within the balance sheets at December 31 to the total of these amounts shown on the statements of cash flows: (in millions) 2022 2021 2020 Cash and cash equivalents $ 28.9 $ 16.3 $ 24.8 Restricted cash included in other current assets 25.6 19.6 — Restricted cash included in other long-term assets 127.7 51.6 47.8 Cash, cash equivalents, and restricted cash $ 182.2 $ 87.5 $ 72.6 |
Regulatory Environment
Regulatory Environment | 12 Months Ended |
Dec. 31, 2022 | |
Regulated Operations [Abstract] | |
REGULATORY ENVIRONMENT | REGULATORY ENVIRONMENT Recovery of Natural Gas Costs Due to the cold temperatures, wind, snow, and ice throughout the central part of the country during February 2021, the cost of gas purchased for our natural gas utility customers was temporarily driven significantly higher than our normal winter weather expectations. All of our utilities have regulatory mechanisms in place for recovering all prudently incurred gas costs. In March 2021, WE and WG received approval from the PSCW to recover approximately $54 million and $24 million, respectively, of natural gas costs in excess of the benchmark set in their GCRMs over a period of three months, beginning in April 2021. In March 2021, WPS also filed its revised natural gas rate sheets with the PSCW reflecting approximately $28 million of natural gas costs in excess of the benchmark set in its GCRM. WPS also recovered these excess costs over a period of three months, beginning in April 2021. PGL and NSG incurred approximately $131 million and $10 million, respectively, of natural gas costs in February 2021 in excess of the amounts included in their rates. These costs were recovered over a period of 12 months, which started on April 1, 2021. PGL's and NSG's natural gas costs were reviewed for prudency by the ICC as part of their annual natural gas cost reconciliation. On January 5, 2023, the ICC issued written orders approving each company's 2021 reconciliation. In February 2021, MERC incurred approximately $75 million of natural gas costs in excess of the benchmark set in its GCRM. In August 2021, the MPUC issued a written order approving a joint proposal filed by MERC and four other Minnesota utilities to recover their respective excess natural gas costs. In accordance with the order, MERC recovered $10 million of these costs through its annual natural gas true-up process over a period of 12 months, and the remaining $65 million was to be recovered over a period of 27 months, both beginning in September 2021. Recovery of these costs and the issue of prudence was referred to a contested-case proceeding. In October 2022, the MPUC issued a written order approving a settlement agreement entered into by MERC and various parties related to the recovery of the extraordinary natural gas costs incurred in February 2021. Under the settlement agreement, MERC agreed to not seek recovery of $3 million of these costs. MERC will continue to recover the remaining $62 million of extraordinary natural gas costs over the previously approved 27-month recovery period. Natural gas costs incurred at MGU and UMERC in excess of the amount included in their respective rates were not significant. Coronavirus Disease – 2019 In response to the COVID-19 pandemic, the PSCW, the ICC, the MPUC, and the MPSC all issued written orders requiring certain actions to ensure that essential utility services were available to customers in their respective jurisdictions. A summary of these orders is included below. Wisconsin In March 2020, the PSCW issued two orders in response to the COVID-19 pandemic. The first order required all public utilities in the state of Wisconsin, including WE, WPS, and WG, to temporarily suspend disconnections, the assessment of late fees, and deposit requirements for all customer classes. In addition, it required utilities to reconnect customers that were previously disconnected, offer deferred payment arrangements to all customers, and streamline the application process for customers applying for utility service. In the second order issued in March 2020, the PSCW authorized Wisconsin utilities to defer expenditures and certain foregone revenues resulting from compliance with the first order, and expenditures as otherwise incurred to ensure safe, reliable, and affordable access to utility services during the declared public health emergency. In December 2021, the PSCW approved a motion to end all COVID-related deferrals as of December 31, 2021. At December 31, 2022, our Wisconsin utilities did not have any amounts deferred related to the COVID-19 pandemic as the rate orders received from the PSCW in December 2022 did not allow recovery of these costs. In June 2020, the PSCW issued a written order providing a timeline for the lifting of the temporary provisions required in the first March 2020 order. Utilities were allowed to disconnect commercial and industrial customers and require deposits for new service as of July 25, 2020 and July 31, 2020, respectively. After August 15, 2020, utilities were no longer required to offer deferred payment arrangements to all customers. Additionally, utilities were authorized to reinstate late fees except for the period between the first order and this supplemental order. Our Wisconsin utilities resumed charging late payment fees in late August 2020. Late payment fees were not charged on outstanding balances that were billed between the first order and late August 2020. Subsequent to the June 2020 order, the PSCW extended the moratorium on disconnections of residential customers until November 1, 2020. In accordance with Wisconsin regulations, utilities are generally not allowed to disconnect residential customers for non-payment during the winter moratorium, which customarily begins on November 1 and ends on April 15 of each year. Utilities were allowed to continue assessing late payment fees during the winter moratorium. On April 5, 2021, the PSCW issued a written order indicating that it would not extend the moratorium on disconnections further; therefore, utilities could begin disconnecting residential customers for non-payment after April 15, 2021. The order also allowed our Wisconsin utilities to resume charging late payment fees on the full balance of all outstanding arrears, regardless of the associated dates the service was provided, after April 15, 2021. We continue to offer flexible payment arrangements to low-income residential customers prior to disconnecting service. Illinois In March 2020, the ICC issued an order to all Illinois utilities, including PGL and NSG, requiring, among other things, a moratorium on disconnections of utility service and a suspension of late fees and penalties during the declared public health emergency. These provisions applied to all utility customer classes. Illinois utilities were also required to temporarily enact more flexible credit and collections procedures. In June 2020, the ICC issued a written order approving a settlement agreement negotiated by Illinois utilities, ICC staff, and certain intervenors. The key terms of the settlement agreement included the following: • The moratorium on disconnections and the suspension of late fees and penalties were extended until July 26, 2020. • Customers disconnected after June 18, 2019 could be reconnected without being assessed a reconnection fee if reconnection was requested prior to August 25, 2020. • Flexible deferred payment arrangements were required to be offered to residential and commercial and industrial customers for an extended period of time and with reduced down payment requirements. • Deposit requirements were waived until August 25, 2020 for all residential customers, and were waived for an additional four months for residential customers that verbally expressed financial hardship. • PGL and NSG were required to establish a bill payment assistance program with approximately $12.0 million and $1.2 million, respectively, available for eligible residential customers to provide relief from high arrearages. In addition to the above, the settlement agreement approved in June 2020 authorized PGL and NSG to implement a SPC rider for certain costs incurred between March 1, 2020 and December 31, 2021. The SPC rider allows for recovery of incremental direct costs resulting from COVID-19, foregone late fees and reconnection charges, and the costs associated with the bill payment assistance programs. PGL and NSG began recovering costs under the SPC rider on October 1, 2020. Amounts deferred under the SPC rider are being recovered over 36 months and will be subject to review and reconciliation by the ICC. As of December 31, 2022, PGL's and NSG's remaining regulatory assets related to the COVID-19 pandemic were $9.5 million, collectively. Subsequent to the approval of the June 2020 settlement agreement, and at the request of the ICC, PGL and NSG agreed to extend the moratorium on disconnections for qualified low-income residential customers and residential customers expressing financial hardship through March 31, 2021. The annual winter moratorium in Illinois that generally prohibits PGL and NSG from disconnecting residential customers for non-payment customarily begins on December 1 and ends on March 31 of each year. In March 2021, the ICC issued a written order approving a second settlement agreement negotiated by Illinois utilities, ICC staff, and certain intervenors. The key terms of this new settlement agreement were as follows: • Utilities could start sending disconnection notices, on a staggered basis, as of April 1, 2021. Disconnections were done on a staggered schedule based on customer arrears and income levels. Utilities were not allowed to disconnect customers for non-payment prior to June 30, 2021 if the customer's household income was below 300% of the federal poverty level and the customer was on a deferred payment plan. • Utilities were required to continue offering flexible deferred payment arrangements with reduced down payment requirements to residential customers through June 30, 2021. • Reconnection fees were waived for eligible low income customers through June 30, 2021. In addition, utilities will continue to exempt eligible low income customers from late payment fees and deposits. • Each utility was required to continue, or renew, its bill payment assistance program through 2021. In addition to the $12.0 million PGL initially funded, PGL was required to fund an additional $6.0 million to its bill payment assistance program. No additional funding was required for NSG due to the amount still available for assistance from its initial funding. PGL's and NSG's bill payment assistance programs ended in April 2021 and August 2021, respectively, as all of their respective funds were exhausted. • Costs related to the provisions in the settlement agreement, including costs related to the bill payment assistance programs, were recoverable through the SPC rider. Minnesota In May 2020, the MPUC issued a written order authorizing Minnesota utilities, including MERC, to track and defer COVID-19 related expenses and certain foregone revenues. Costs incurred at MERC related to the COVID-19 pandemic were not significant, and at December 31, 2022, MERC did not have any amounts deferred. In June 2020, the MPUC verbally ordered Minnesota utilities to temporarily suspend disconnections and waive reconnection fees, service deposits, late fees, interest, and penalties for all residential customers. In addition, utilities were required to immediately reconnect residential customers that were previously disconnected. In August 2020, the MPUC issued a written order affirming these temporary provisions. Prior to the June 2020 verbal order issued by the MPUC, MERC had voluntarily taken actions to ensure its customers continued to receive utility services during the pandemic. These actions included, but were not limited to, temporarily suspending disconnections and waiving late payment fees for residential and small commercial and industrial customers that entered into payment plans. In March 2021, the MPUC issued an order requiring Minnesota utilities to file a transition plan to resume collections and disconnections. MERC filed its transition plan in April 2021, and it was subsequently deemed complete by the Executive Secretary. In accordance with the transition plan, MERC resumed disconnections on August 2, 2021. MERC will not disconnect residential customers with past due balances if the customer has a pending application or has been deemed eligible for a financial assistance program. In addition, MERC continues to offer flexible deferred payment arrangements to residential customers. For customers who enter, or are complying with, a payment arrangement, MERC did not impose any service deposits, down payments, interest, late payment fees, or reconnections fees through April 30, 2022. Michigan In April 2020, the MPSC issued a written order requiring Michigan utilities, including MGU and UMERC, to put certain minimum protections in place during the COVID-19 pandemic. The minimum protections required by the order included the suspension of disconnections, late payment fees, deposits, and reconnection fees for certain vulnerable customers. In addition, utilities were required to extend access to and enhance the flexibility of payment plans to customers financially impacted by COVID-19. As required in the MPSC order, MGU and UMERC filed responses with the MPSC in April 2020 affirming the actions being taken to protect customers. These actions provided protections to more customers than required by the MPSC order, and included suspending disconnections for all residential customers, waiving deposit requirements for new service, suspending the assessment of late fees for customers that entered into payment plans, and enhancing payment plan options for all customers. The April 2020 MPSC order also authorized all Michigan utilities to defer, for potential future recovery, uncollectible expense incurred on or after March 24, 2020 that exceeded the amounts being recovered in rates. MGU and UMERC did not record any deferrals related to the COVID-19 pandemic as they did not experience any significant COVID-19 related expenses. In June 2021, MGU and UMERC worked with MPSC staff to develop a transition plan to resume collections and disconnections, while continuing to assist customers in managing their arrears balances. In accordance with the agreed upon transition plan, MGU and UMERC resumed pre-pandemic collection activities and residential service disconnections on August 2, 2021. Flexible deferred payment arrangements continue to be available to customers. Wisconsin Electric Power Company, Wisconsin Public Service Corporation, and Wisconsin Gas LLC 2023 and 2024 Rates In April 2022, WE, WPS, and WG filed requests with the PSCW to increase their retail electric, natural gas, and steam rates, as applicable. These requests were updated in July 2022 to reflect new developments that impacted the original proposals. The requested increases in electric rates were driven by capital investments in new wind, solar, and battery storage; capital investments in natural gas generation; reliability investments, including grid hardening projects to bury power lines and strengthen WE's distribution system against severe weather; and changes in wholesale business with other utilities. Many of these investments have already been approved by the PSCW. The requested increases in natural gas rates primarily related to capital investments previously approved by the PSCW, including LNG storage for our natural gas distribution system. In September 2022, WE, WPS, and WG entered into settlement agreements with certain intervenors to resolve most of the outstanding issues in each utility's respective rate case; however, the PSCW declined to approve the settlement agreements. In December 2022, the PSCW issued final written orders approving electric, natural gas, and steam base rate increases, effective January 1, 2023. The final orders reflect the following: WE WPS WG 2023 base rate increase Electric $ 283.5 million / 9.1% $ 120.5 million / 9.8% N/A Gas $ 46.1 million / 9.6% $ 26.4 million / 7.1% $ 46.5 million / 6.4% Steam $ 7.6 million / 35.3% N/A N/A ROE 9.8% 9.8% 9.8% Common equity component average on a financial basis 53.0% 53.0% 53.0% In addition to the above, the final orders include the following terms: • The utilities will keep their current earnings sharing mechanisms, under which, if a utility earns above its authorized ROE: (i) the utility will retain 100.0% of earnings for the first 15 basis points above the authorized ROE; (ii) 50.0% of the next 60 basis points will be required to be refunded to ratepayers; and (iii) 100.0% of any remaining excess earnings will be required to be refunded to ratepayers. • WE and WPS are required to complete an analysis of alternative recovery scenarios for generating units that will be retired prior to the end of their useful life. • WE and WPS will not propose any changes to their real time pricing rates for large commercial and industrial electric customers through the end of 2024. • WE and WPS will lower monthly residential and small commercial electric customer fixed charges by $1.00 and $3.33, respectively, from currently authorized rates. • WE and WPS will offer an additional voluntary renewable energy pilot for commercial and industrial customers. • WE and WPS will work with PSCW staff and other interested parties to develop alternative low income assistance programs. WE and WPS will also collectively contribute $4.0 million to the Keep Wisconsin Warm Fund. • WE, WPS, and WG are required to implement escrow accounting treatment for pension and OPEB costs in 2023 and 2024. • WE and WPS are authorized to file a limited electric rate case re-opener for 2024 to address changes to revenue requirements associated with generation projects that are expected to be placed into service in 2023 and 2024 and future plant retirements. WE and WG are also authorized to file a limited natural gas rate case re-opener for 2024 to address additional revenue requirements associated with LNG projects that are expected to be placed into service in 2023 and 2024, respectively. 2022 Rates In March 2021, WE, WPS, and WG filed an application with the PSCW for the approval of certain accounting treatments that allowed them to maintain their electric, natural gas, and steam base rates through 2022 and forego filing a rate case for one year. In connection with the request, the three utilities also entered into an agreement, dated March 23, 2021, with various stakeholders. Pursuant to the terms of the agreement, the stakeholders fully supported the application. In September 2021, the PSCW issued written orders approving the application. The final orders reflected the following: • WE, WPS, and WG amortized, in 2022, certain previously deferred balances to offset approximately half of their forecasted revenue deficiencies. • WG deferred interest and depreciation expense associated with capital investments since its last rate case that otherwise would have been added to rate base in a 2022 test-year rate case. • WE, WPS, and WG were able to defer any increases in tax expense due to changes in tax law that occurred in 2021 and/or 2022. • WE, WPS, and WG maintained their earnings sharing mechanisms for 2022, with modification. The earnings sharing mechanisms were modified to authorize the utility to retain 100.0% of the first 15 basis points of earnings above its currently authorized ROE. The earnings sharing mechanisms otherwise remained as previously authorized. 2020 and 2021 Rates In March 2019, WE, WPS, and WG filed applications with the PSCW to increase their retail electric, natural gas, and steam rates, as applicable, effective January 1, 2020. In August 2019, all three utilities filed applications with the PSCW for approval of settlement agreements entered into with certain intervenors to resolve several outstanding issues in each utility's respective rate case. In December 2019, the PSCW issued written orders that approved the settlement agreements without material modification and addressed the remaining outstanding issues that were not included in the settlement agreements. The new rates were effective January 1, 2020. The final orders reflected the following: WE WPS WG 2020 Effective rate increase (decrease) Electric (1) (2) $ 15.3 million / 0.5% $ 15.8 million / 1.6% N/A Gas (3) $ 10.4 million / 2.8% $ 4.3 million / 1.4% $ (1.5) million / (0.2)% Steam $ 1.9 million / 8.6% N/A N/A ROE 10.0% 10.0% 10.2% Common equity component average on a financial basis 52.5% 52.5% 52.5% (1) Amounts are net of certain deferred tax benefits from the Tax Legislation that were utilized to reduce near-term rate impact. The WE and WPS rate orders reflected the majority of the unprotected deferred tax benefits from the Tax Legislation being amortized over two years. For WE, approximately $65 million of tax benefits were amortized in each of 2020 and 2021. For WPS, approximately $11 million of tax benefits were amortized in 2020 and approximately $39 million were amortized in 2021. The unprotected deferred tax benefits related to the unrecovered balances of certain of WE's retired plants and its SSR regulatory asset were used to reduce the related regulatory asset. Unprotected deferred tax benefits by their nature are eligible to be returned to customers in a manner and timeline determined to be appropriate by our regulators. (2) The WPS rate order was net of $21 million of refunds related to its 2018 earnings sharing mechanism. These refunds were made to customers evenly over two years, with half returned in 2020 and the remainder returned in 2021. (3) The WE amount includes certain deferred tax expense from the Tax Legislation, and the WPS and WG amounts are net of certain deferred tax benefits from the Tax Legislation that were utilized to reduce near-term rate impact. The rate orders for all three gas utilities reflected all of the unprotected deferred tax expense and benefits from the Tax Legislation being amortized evenly over four years. For WE, approximately $5 million of previously deferred tax expense is being amortized each year. For WPS and WG, approximately $5 million and $3 million, respectively, of previously deferred tax benefits are being amortized each year. Unprotected deferred tax expense and benefits by their nature are eligible to be recovered from or returned to customers in a manner and timeline determined to be appropriate by our regulators. In accordance with its rate order, WE filed an application with the PSCW in July 2020 requesting a financing order to securitize $100 million of Pleasant Prairie power plant's book value, plus the carrying costs accrued on the $100 million during the securitization process and the related financing fees. In November 2020, the PSCW issued a written order approving the application. The financing order also authorized WE to form a bankruptcy-remote special purpose entity, WEPCo Environmental Trust, for the sole purpose of issuing ETBs to recover the approved costs. In May 2021, WEPCo Environmental Trust issued $118.8 million of 1.578% ETBs due December 15, 2035. See Note 23, Variable Interest Entities, for more information regarding WEPCo Environmental Trust. The WPS rate order allows WPS to collect the previously deferred revenue requirement for ReACT™ costs above the authorized $275 million level. The total cost of the ReACT™ project was $342 million. This regulatory asset is being collected from customers over eight years. The PSCW approved all three Wisconsin utilities continuing to have an earnings sharing mechanism through 2021. The earnings sharing mechanism was modified from its previous structure to one that was consistent with other Wisconsin investor-owned utilities. Under this earnings sharing mechanism, if the utility earned above its authorized ROE: (i) the utility retained 100.0% of earnings for the first 25 basis points above the authorized ROE; (ii) 50.0% of the next 50 basis points were required to be refunded to customers; and (iii) 100.0% of any remaining excess earnings were required to be refunded to customers. In addition, the rate orders also required WE, WPS, and WG to maintain residential and small commercial electric and natural gas customer fixed charges at previously authorized rates and to maintain the status quo for WE's and WPS's electric market-based rate programs for large industrial customers through 2021. The Peoples Gas Light and Coke Company and North Shore Gas Company 2023 Rate Case On January 6, 2023, PGL and NSG filed requests with the ICC to increase their natural gas base rates. They are requesting incremental rate increases of $194.7 million (13.0%) and $18.7 million (7.8%), respectively. The requested rate increases are primarily driven by capital investments made to strengthen the safety and reliability of each utility’s natural gas distribution system. PGL is also seeking to recover costs incurred to upgrade its natural gas storage field and operations facilities and to continue improving customer service. Both companies are requesting an ROE of 9.90% and a common equity component average of 54.0%. PGL is not seeking an extension of the QIP rider. Instead, PGL will return to the traditional rate making process to recover the costs of necessary infrastructure improvements. See the Qualifying Infrastructure Plant Rider section below for more information on the QIP rider. An ICC decision is anticipated in the fourth quarter of 2023, with any rate adjustments expected to be effective January 1, 2024. Third-Party Transaction Fee Adjustment Rider In accordance with the Climate and Equitable Jobs Act that was signed into law in Illinois, effective September 15, 2021, Illinois utilities are prohibited from charging customers a fee when they elect to pay for service with a credit card. Utilities are now required to incur these expenses and seek recovery through a rate proceeding or by establishing a recovery mechanism. In December 2021, the ICC approved the use of a TPTFA rider for PGL. The TPTFA rider allows PGL to recover the costs incurred for these third-party transaction fees. PGL began recovering costs under the rider on February 1, 2022. Amounts deferred under the rider will be recovered over a period of 12 months and will be subject to an annual reconciliation whereby costs will be reviewed by the ICC for accuracy and prudency. NSG recovers costs related to these third-party transaction fees through its base rates, effective September 15, 2021. North Shore Gas Company 2021 Rate Order In October 2020, NSG filed a request with the ICC to increase its natural gas rates. In September 2021, the ICC issued a written order authorizing a rate increase of $4.1 million (4.5%). The rate increase reflects a 9.67% ROE and a common equity component average of 51.58%. The natural gas rate increase was primarily driven by NSG's ongoing significant investment in its distribution system since its last rate review that resulted in revised base rates effective January 28, 2015. The new rates were effective September 15, 2021. Qualifying Infrastructure Plant Rider In July 2013, Illinois Public Act 98-0057, The Natural Gas Consumer, Safety & Reliability Act, became law. This law provides natural gas utilities with a cost recovery mechanism that allows collection, through a surcharge on customer bills, of prudently incurred costs to upgrade Illinois natural gas infrastructure. In January 2014, the ICC approved a QIP rider for PGL, which is in effect through 2023. PGL will not seek an extension of the rider beyond 2023. PGL's QIP rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. In March 2022, PGL filed its 2021 reconciliation with the ICC, which, along with the 2020, 2019, 2018, 2017, and 2016 reconciliations, are still pending. In addition, costs incurred during 2022 under the QIP rider are also still subject to reconciliation and review. As of December 31, 2022, there can be no assurance that all costs incurred under PGL's QIP rider during the open reconciliation years, which include 2016 through 2022, will be deemed recoverable by the ICC. Minnesota Energy Resources Corporation 2023 Rate Case On November 1, 2022, MERC initiated a rate proceeding with the MPUC to increase its retail natural gas base rates by $40.3 million (9.9%). MERC's request reflects a 10.3% ROE and a common equity component average of 53.0%. The proposed retail natural gas rate increase is primarily driven by increased capital investments as well as inflationary pressure on operating costs. In December 2022, the MPUC approved MERC's request for interim rates totaling $37.0 million, subject to refund. The interim rates went into effect on January 1, 2023. Michigan Gas Utilities Corporation 2021 Rate Order In February 2020, MGU provided notification to the MPSC of its intent to file an application requesting an increase to MGU's natural gas rates to be effective January 1, 2021. However, MGU decided that it would delay its filing of the rate case as a result of the COVID-19 pandemic. In May 2020, MGU filed an application with the MPSC requesting approval to defer $5.0 million of depreciation and interest expense during 2021 related to capital investments made by MGU since its last rate case. In July 2020, the MPSC issued a written order approving MGU's request. The deferral of these costs helped to mitigate the impacts from delaying the filing of the rate case. In March 2021, MGU filed its request with the MPSC to increase its natural gas rates. In July 2021, MGU filed with the MPSC, a settlement agreement it reached with certain intervenors, which the MPSC approved in a written order in September 2021. The order authorizes a rate increase of $9.3 million (6.35%) and reflects a 9.85% ROE and a common equity component average of 51.5%. The natural gas rate increase was primarily driven by MGU's significant investment in capital infrastructure since its last rate review that resulted in revised base rates effective January 1, 2016. The order also allows MGU to implement a rider for its Main Replacement Program that will support recovery of planned capital investment related to pipeline replacements to maintain system safety and reliability between 2023 and 2027, without having to file a rate case. We expect approximately $31.7 million of costs to be recovered through this rider. All costs recovered through the rider are subject to a prudence review by the MPSC. The new rates became effective January 1, 2022. |
Other Income, Net
Other Income, Net | 12 Months Ended |
Dec. 31, 2022 | |
Other Income and Expenses [Abstract] | |
OTHER INCOME, NET | OTHER INCOME, NET Total other income, net was as follows for the years ended December 31: (in millions) 2022 2021 2020 Non-service components of net periodic benefit costs $ 104.4 $ 72.2 $ 41.2 AFUDC–Equity 29.4 18.0 20.9 Earnings from equity method investments (1) 9.3 19.9 2.4 Gains (losses) from investments held in rabbi trust (12.6) 18.6 12.7 Other, net (1.7) 4.5 2.3 Other income, net $ 128.8 $ 133.2 $ 79.5 (1) Amount does not include equity earnings of transmission affiliates as those earnings are shown as a separate line item on the income statements. |
New Accounting Pronouncements
New Accounting Pronouncements | 12 Months Ended |
Dec. 31, 2022 | |
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. Government Assistance In November 2021, the FASB issued ASU No. 2021-10, Government Assistance (Topic 832). The amendments in this update increase the transparency surrounding government assistance by requiring disclosure of: (i) the types of assistance received; (ii) an entity’s accounting for the assistance; and (iii) the effect of the assistance on the entity’s financial statements. The update was effective for annual periods beginning after December 15, 2021. The adoption of ASU No. 2021-10, effective for our fiscal year ending on December 31, 2022, did not have a significant impact on our financial statements and related disclosures. |
Schedule I - Condensed Parent C
Schedule I - Condensed Parent Company Financial Statements | 12 Months Ended |
Dec. 31, 2022 | |
Condensed Financial Information Disclosure [Abstract] | |
SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS | SCHEDULE I – CONDENSED PARENT COMPANY FINANCIAL STATEMENTS WEC ENERGY GROUP, INC. (PARENT COMPANY ONLY) A. INCOME STATEMENTS Year Ended December 31 (in millions) 2022 2021 2020 Operating expenses (income) $ (1.6) $ 12.0 $ 5.3 Equity earnings of subsidiaries 1,473.0 1,367.0 1,283.8 Other income, net 2.4 1.7 1.3 Interest expense 109.6 70.2 96.9 Loss on debt extinguishment — 23.1 38.4 Income before income taxes 1,367.4 1,263.4 1,144.5 Income tax benefit 40.7 36.9 55.4 Net income attributed to common shareholders $ 1,408.1 $ 1,300.3 $ 1,199.9 The accompanying Notes to Condensed Parent Company Financial Statements are an integral part of these financial statements. B. STATEMENTS OF COMPREHENSIVE INCOME Year Ended December 31 (in millions) 2022 2021 2020 Net income attributed to common shareholders $ 1,408.1 $ 1,300.3 $ 1,199.9 Other comprehensive income (loss), net of tax Derivatives accounted for as cash flow hedges Net derivative gain (loss), net of tax expense (benefit) of $—, $0.2, and $(1.6), respectively — 0.6 (4.3) Reclassification of realized net derivative (gain) loss to net income, net of tax (0.3) 0.9 1.5 Cash flow hedges, net (0.3) 1.5 (2.8) Defined benefit plans Pension and OPEB adjustments arising during the period, net of tax (0.8) 0.4 (0.4) Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax 0.2 0.3 0.3 Defined benefit plans, net (0.6) 0.7 (0.1) Other comprehensive income (loss) from subsidiaries, net of tax (2.7) 1.4 0.2 Other comprehensive income (loss), net of tax (3.6) 3.6 (2.7) Comprehensive income attributed to common shareholders $ 1,404.5 $ 1,303.9 $ 1,197.2 The accompanying Notes to Condensed Parent Company Financial Statements are an integral part of these financial statements. C. BALANCE SHEETS At December 31 (in millions) 2022 2021 Assets Current assets Cash and cash equivalents $ — $ 0.5 Accounts receivable from related parties 0.7 0.6 Notes receivable from related parties 30.9 29.0 Prepaid income taxes 35.4 56.5 Other 0.1 0.1 Current assets 67.1 86.7 Long-term assets Investments in subsidiaries 16,533.4 15,365.4 Other 24.2 21.8 Long-term assets 16,557.6 15,387.2 Total assets $ 16,624.7 $ 15,473.9 Liabilities and Equity Current liabilities Short-term debt $ 399.7 $ 736.1 Current portion of long-term debt 700.0 — Accounts payable to related parties 2.0 5.5 Notes payable to related parties 332.5 220.4 Other 31.8 21.5 Current liabilities 1,466.0 983.5 Long-term liabilities Long-term debt 3,747.2 3,549.8 Other 34.6 27.4 Long-term liabilities 3,781.8 3,577.2 Common shareholders' equity 11,376.9 10,913.2 Total liabilities and equity $ 16,624.7 $ 15,473.9 The accompanying notes to Condensed Parent Company Financial Statements are an integral part of these financial statements. D. STATEMENTS OF CASH FLOWS Year Ended December 31 (in millions) 2022 2021 2020 Operating activities Net income attributed to common shareholders $ 1,408.1 $ 1,300.3 $ 1,199.9 Reconciliation to cash provided by operating activities Equity income in subsidiaries, net of distributions (437.4) (571.3) (385.7) Deferred income taxes, net 11.6 (1.9) 12.7 Loss on debt extinguishment — 23.1 38.4 Change in – Accounts receivable from related parties (0.1) 0.1 — Prepaid income taxes 21.1 (2.1) (7.9) Accounts payable to related parties (3.5) (26.2) 29.2 Accrued interest 15.4 0.4 (0.9) Other current liabilities (5.1) 8.2 (1.5) Other, net 5.8 (2.5) 9.6 Net cash provided by operating activities 1,015.9 728.1 893.8 Investing activities Capital contributions to subsidiaries (1,099.7) (734.0) (1,026.1) Return of capital from subsidiaries 372.9 196.1 602.8 Short-term notes receivable from related parties, net (1.9) 81.8 (88.3) Other, net (2.0) (1.1) 3.7 Net cash used in investing activities (730.7) (457.2) (507.9) Financing activities Exercise of stock options 33.6 15.7 43.8 Purchase of common stock (69.2) (33.1) (99.2) Dividends paid on common stock (917.9) (854.8) (798.0) Issuance of long-term debt 900.0 1,100.0 1,650.0 Retirement of long-term debt — (300.0) (1,430.0) Issuance of short-term loan — — 340.0 Repayment of short-term loan — (340.0) — Change in commercial paper (336.4) 255.7 145.7 Short-term notes payable to related parties, net 112.1 (82.6) (186.3) Payments for debt extinguishment and issuance costs (6.7) (33.9) (47.3) Other, net (1.2) (1.4) (1.1) Net cash used in financing activities (285.7) (274.4) (382.4) Net change in cash and cash equivalents (0.5) (3.5) 3.5 Cash and cash equivalents at beginning of year 0.5 4.0 0.5 Cash and cash equivalents at end of year $ — $ 0.5 $ 4.0 The accompanying Notes to Condensed Parent Company Financial Statements are an integral part of these financial statements. SCHEDULE I – CONDENSED PARENT COMPANY FINANCIAL STATEMENTS WEC ENERGY GROUP, INC. (PARENT COMPANY ONLY) E. NOTES TO PARENT COMPANY FINANCIAL STATEMENTS NOTE 1—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES For Parent Company only presentation, investments in subsidiaries are accounted for using the equity method. We use the cumulative earnings approach for classifying distributions received in the statements of cash flows. The condensed Parent Company financial statements and notes should be read in conjunction with the consolidated financial statements and notes of WEC Energy Group, Inc. appearing in this Annual Report on Form 10-K. NOTE 2—CASH DIVIDENDS RECEIVED FROM SUBSIDIARIES Dividends received from our subsidiaries during the years ended December 31 were as follows: (in millions) 2022 2021 2020 WE $ 630.0 $ 360.0 $ 395.0 We Power 158.5 217.9 240.9 WECI (1) 87.7 46.4 33.6 ATC Holding (2) 74.9 106.4 112.6 WG 60.0 30.0 70.0 UMERC 17.0 — 46.0 Wispark (3) 7.5 — — Bluewater — 35.0 — Total $ 1,035.6 $ 795.7 $ 898.1 (1) We also received amounts classified as return of capital of $363.7 million, $164.1 million, and $583.2 million from WECI during the years ended December 31, 2022, 2021, and 2020, respectively. (2) We also received amounts classified as return of capital of $32.0 million and $19.6 million from ATC Holding during the years ended December 31, 2021 and 2020, respectively. (3) We also received amounts classified as return of capital of $9.2 million from Wispark during the year ended December 31, 2022. NOTE 3—LONG-TERM DEBT The following table shows the future maturities of our long-term debt outstanding as of December 31, 2022: (in millions) 2023 $ 700.0 2024 600.0 2025 620.0 2026 — 2027 900.0 Thereafter 1,650.0 Total $ 4,470.0 WECC is our subsidiary and has $50.0 million of long-term notes outstanding. In a Support Agreement between WECC and us, we agreed to make sufficient liquid asset contributions to WECC to permit WECC to service its debt obligations as they become due. NOTE 4—FAIR VALUE MEASUREMENTS The following table shows the financial instruments included on our balance sheets that are not recorded at fair value as of December 31: 2022 2021 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 4,447.2 $ 4,095.6 $ 3,549.8 $ 3,546.9 The fair value of our long-term debt is categorized within Level 2 of the fair value hierarchy. NOTE 5—GUARANTEES The following table shows our outstanding guarantees on behalf of our subsidiaries: Total Amounts Committed at December 31, 2022 Expiration (in millions) Less Than 1 Year 1 to 3 Years Over 3 Years Guarantees supporting business operations (1) $ 548.5 $ 427.8 $ 1.2 $ 119.5 Standby letters of credit (2) 68.4 8.0 — 60.4 Surety bonds (3) 34.0 33.9 0.1 — Other guarantees (4) 9.4 — — 9.4 Total guarantees $ 660.3 $ 469.7 $ 1.3 $ 189.3 (1) Consists of $532.0 million, $11.3 million, and $5.2 million of guarantees to support the business operations of WECI, Bluewater, and UMERC, respectively. (2) At our request, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to our subsidiaries. These amounts are not reflected on our balance sheets. (3) Primarily for environmental remediation, workers compensation self-insurance programs, and obtaining various licenses, permits, and rights-of-way. These amounts are not reflected on our balance sheets. (4) Related to workers compensation coverage for which a liability was recorded on our balance sheets. NOTE 6—SUPPLEMENTAL CASH FLOW INFORMATION (in millions) 2022 2021 2020 Cash paid for interest $ 88.1 $ 70.2 $ 98.5 Cash received for income taxes, net (72.9) (27.9) (61.5) NOTE 7—SHORT-TERM NOTES RECEIVABLE FROM RELATED PARTIES The following table shows our outstanding short-term notes receivable from related parties as of December 31: (in millions) 2022 2021 UMERC $ 27.1 $ 22.0 Bluewater 2.7 7.0 Wispark 1.1 — Total $ 30.9 $ 29.0 NOTE 8—SHORT-TERM NOTES PAYABLE TO RELATED PARTIES The following table shows our outstanding short-term notes payable to related parties as of December 31: (in millions) 2022 2021 Integrys $ 115.0 $ 5.3 WBS 111.0 107.7 WECC 106.5 107.4 Total $ 332.5 $ 220.4 |
Schedule II - Valuation and Qua
Schedule II - Valuation and Qualifying Accounts | 12 Months Ended |
Dec. 31, 2022 | |
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract] | |
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | SCHEDULE II WEC ENERGY GROUP, INC. VALUATION AND QUALIFYING ACCOUNTS Allowance for Doubtful Accounts (in millions) Balance at Beginning of Period Expense (1) Deferral Net Write-offs (2) Sale of Business Balance at End of Period December 31, 2022 $ 198.3 $ 86.1 $ 62.9 $ (148.0) $ — $ 199.3 December 31, 2021 220.1 107.4 (44.8) (84.4) — 198.3 December 31, 2020 140.0 102.8 55.3 (77.9) (0.1) 220.1 (1) Net of recoveries. (2) Represents amounts written off to the reserve, net of adjustments to regulatory assets. |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2022 | |
Accounting Policies [Abstract] | |
Nature Of Operations | WEC Energy Group serves approximately 1.6 million electric customers and 3.0 million natural gas customers, owns approximately 60% of ATC, and owns majority interests in multiple wind generating facilities as part of its non-utility energy infrastructure segment. |
Consolidation | As used in these notes, the term "financial statements" refers to the consolidated financial statements. This includes the income statements, statements of comprehensive income, balance sheets, statements of cash flows, and statements of equity, unless otherwise noted. On our financial statements, we consolidate our majority-owned subsidiaries which we control, and VIEs of which we are the primary beneficiary. We reflect noncontrolling interests for the portion of entities that we do not own as a component of consolidated equity separate from the equity attributable to our shareholders. The noncontrolling interests that we reported as equity on our balance sheet as of December 31, 2022 related to the minority interests held by third parties in the wind generating facilities that are included in our non-utility energy infrastructure segment. |
Segment reporting | Our financial statements include the accounts of WEC Energy Group, a diversified energy holding company, and the accounts of our subsidiaries in the following reportable segments: • Wisconsin segment – Consists of WE, WPS, and WG, which are engaged primarily in the generation of electricity and the distribution of electricity and natural gas in Wisconsin; and UMERC, which generates electricity and distributes electricity and natural gas to customers located in the Upper Peninsula of Michigan. • Illinois segment – Consists of PGL and NSG, which are engaged primarily in the distribution of natural gas in Illinois. • Other states segment – Consists of MERC and MGU, which are engaged primarily in the distribution of natural gas in Minnesota and Michigan, respectively. • Electric transmission segment – Consists of our approximate 60% ownership interest in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions, and our approximate 75% ownership interest in ATC Holdco, which invests in transmission-related projects outside of ATC's traditional footprint. • Non-utility energy infrastructure segment – Consists of We Power, which is principally engaged in the ownership of electric power generating facilities for long-term lease to WE, and Bluewater, which owns underground natural gas storage facilities in Michigan. WECI, which holds our ownership interests in several wind generating facilities, is also included in this segment. See Note 2, Acquisitions, for more information on the recently acquired WECI renewable generating facilities. • Corporate and other segment – Consists of the WEC Energy Group holding company, the Integrys holding company, the PELLC holding company, Wispark, Wisvest, WECC, WBS, and also included the operations of PDL prior to the sale of its remaining solar facilities in the fourth quarter of 2020. See Note 3, Dispositions, for more information on the sale of these solar facilities. |
Equity method investments | Investments in companies not controlled by us, but over which we have significant influence regarding the operating and financial policies of the investee, are accounted for using the equity method. We use the cumulative earnings approach for classifying distributions received in the statements of cash flows. Under the cumulative earnings approach, we compare the distributions received to cumulative equity method earnings since inception. Any distributions received up to the amount of cumulative equity earnings are considered a return on investment and classified in operating activities. Any excess distributions are considered a return of investment and classified in investing activities. |
Jointly owned facilities | Our financial statements also reflect our proportionate interests in certain jointly owned utility facilities. See Note 8, Jointly Owned Utility Facilities, for more information. |
Use of estimates | We prepare our financial statements in conformity with GAAP. We make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates. |
Cash and cash equivalents | Cash and cash equivalents include marketable debt securities with an original maturity of three months or less. |
Operating revenues | The following discussion includes our significant accounting policies related to operating revenues. For additional required disclosures on disaggregation of operating revenues, see Note 4, Operating Revenues. Revenues from Contracts with Customers Electric Utility Operating Revenues Electricity sales to residential and commercial and industrial customers are generally accomplished through requirements contracts, which provide for the delivery of as much electricity as the customer needs. These contracts represent discrete deliveries of electricity and consist of one distinct performance obligation satisfied over time, as the electricity is delivered and consumed by the customer simultaneously. For our Wisconsin residential and commercial and industrial customers and the majority of our Michigan residential and commercial and industrial customers, our performance obligation is bundled to consist of both the sale and the delivery of the electric commodity. In our Michigan service territory, a limited number of residential and commercial and industrial customers can purchase the commodity from a third party. In this case, the delivery of the electricity represents our sole performance obligation. The transaction price of the performance obligations for residential and commercial and industrial customers is valued using the rates, charges, terms, and conditions of service included in the tariffs of our regulated electric utilities, which have been approved by state regulators. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on the quantity of electricity delivered each month. Our retail electric rates in Wisconsin include base amounts for fuel and purchased power costs, which also impact our revenues. The electric fuel rules set by the PSCW allow us to defer, for subsequent rate recovery or refund, under- or over-collections of actual fuel and purchased power costs beyond a 2% price variance from the costs included in the rates charged to customers. Our electric utilities monitor the deferral of under-collected costs to ensure that it does not cause them to earn a greater ROE than authorized by the PSCW. In contrast, the rates of our Michigan retail electric customers include recovery of fuel and purchased power costs on a one-for-one basis. In addition, the Wisconsin residential tariffs of WE and WPS include a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. Wholesale customers who resell power can choose to either bundle capacity and electricity services together under one contract with a supplier or purchase capacity and electricity separately from multiple suppliers. Furthermore, wholesale customers can choose to have our utilities provide generation to match the customer's load, similar to requirements contracts, or they can purchase specified quantities of electricity and capacity. Contracts with wholesale customers that include capacity bundled with the delivery of electricity contain two performance obligations, as capacity and electricity are often transacted separately in the marketplace at the wholesale level. When recognizing revenue associated with these contracts, the transaction price is allocated to each performance obligation based on its relative standalone selling price. Revenue is recognized as control of each individual component is transferred to the customer. Electricity is the primary product sold by our electric utilities and represents a single performance obligation satisfied over time through discrete deliveries to a customer. Revenue from electricity sales is generally recognized as units are produced and delivered to the customer within the production month. Capacity represents the reservation of an electric generating facility and conveys the ability to call on a plant to produce electricity when needed by the customer. The nature of our performance obligation as it relates to capacity is to stand ready to deliver power. This represents a single performance obligation transferred over time, which generally represents a monthly obligation. Accordingly, capacity revenue is recognized on a monthly basis. The transaction price of the performance obligations for wholesale customers is valued using the rates, charges, terms, and conditions of service, which have been approved by the FERC. These wholesale rates include recovery of fuel and purchased power costs from customers on a one-for-one basis. For the majority of our wholesale customers, the price billed for energy and capacity is a formula-based rate. Formula-based rates initially set a customer's current year rates based on the previous year’s expenses. This is a predetermined formula derived from the utility's costs and a reasonable rate of return. Because these rates are eventually trued up to reflect actual, current-year costs, they represent a form of variable consideration in certain circumstances. The variable consideration is estimated and recognized over time as wholesale customers receive and consume the capacity and electricity services. We are an active participant in the MISO Energy Markets, where we bid our generation into the Day Ahead and Real Time markets and procure electricity for our retail and wholesale customers at prices determined by the MISO Energy Markets. Purchase and sale transactions are recorded using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded as purchased power in cost of sales, and net sales in a single hour are recorded as resale revenues on our income statements. For resale revenues, our performance obligation is created only when electricity is sold into the MISO Energy Markets. For all of our customers, consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days. Natural Gas Utility Operating Revenues We recognize natural gas utility operating revenues under requirements contracts with residential, commercial and industrial, and transportation customers served under the tariffs of our regulated utilities. Tariffs provide our customers with the standard terms and conditions, including rates, related to the services offered. Requirements contracts provide for the delivery of as much natural gas as the customer needs. These requirements contracts represent discrete deliveries of natural gas and constitute a single performance obligation satisfied over time. Our performance obligation is both created and satisfied with the transfer of control of natural gas upon delivery to the customer. For most of our customers, natural gas is delivered and consumed by the customer simultaneously. A performance obligation can be bundled to consist of both the sale and the delivery of the natural gas commodity. In certain of our service territories, customers can purchase the commodity from a third party. In this case, the performance obligation only includes the delivery of the natural gas to the customer. The transaction price of the performance obligations for our natural gas customers is valued using the rates, charges, terms, and conditions of service included in the tariffs of our regulated utilities, which have been approved by state regulators. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on natural gas delivered each month. The tariffs of our natural gas utilities include various rate mechanisms that allow them to recover or refund changes in prudently incurred costs from rate case-approved amounts. The rates for all of our natural gas utilities include one-for-one recovery mechanisms for natural gas commodity costs. Under normal circumstances, we defer any difference between actual natural gas costs incurred and costs recovered through rates as a current asset or liability. The deferred balance is returned to or recovered from customers at intervals throughout the year. However, as a result of the extreme weather in the Midwest in February 2021, the cost of gas purchased for our natural gas customers was temporarily driven significantly higher than our normal winter weather expectations. See Note 26, Regulatory Environment, for more information on the recovery of these high natural gas costs. In addition, the rates of PGL and NSG, and the residential tariffs of WE, WPS, and WG, include riders or other mechanisms for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. The rates of PGL and NSG include riders for cost recovery of both environmental cleanup costs and energy conservation and management program costs. Finally, PGL's rates include a rider for pass through of income tax expense changes resulting from the Tax Legislation and a cost recovery mechanism for SMP costs, and similarly, the rates of MERC and MGU include riders to recover costs incurred to replace or modify natural gas facilities. Consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days. Other Natural Gas Operating Revenues We have other natural gas operating revenues from Bluewater, which is in our non-utility energy infrastructure segment. Bluewater has entered into long-term service agreements for natural gas storage services with WE, WPS, and WG, and also provides limited service to unaffiliated customers. All amounts associated with the service agreements with WE, WPS, and WG have been eliminated at the consolidated level. Other Non-Utility Operating Revenues Wind generation revenues from WECI's ownership interests in wind generation facilities continued to grow in 2022. See Note 2, Acquisitions, for more information on recent acquisitions. Most of these wind generation facilities have offtake agreements with unaffiliated third parties for all of the energy to be produced by the facility, some of which are bundled with capacity and RECs. We consider bundled energy, capacity and RECs within these offtake agreements to be distinct performance obligations as each are often transacted separately in the marketplace. When recognizing revenue associated with these contracts, the transaction price is allocated to each performance obligation based on its relative standalone selling price. Revenue is recognized as control of each individual component is transferred to the customer. Revenue from the sale of this renewable energy is generally recognized as units are produced and delivered to the customer within the production month. Capacity represents the reservation of the renewable generation facility and conveys the ability to call on the wind facility to produce electricity when needed by the customer. The nature of our performance obligation as it relates to capacity is to stand ready to deliver power. This represents a single performance obligation transferred over time, which generally represents a monthly obligation. Accordingly, capacity revenue is recognized on a monthly basis. The performance obligation for RECs is recognized at a point-in-time; however, the timing of revenue recognition is the same, as the generation of renewable energy and the recognition of REC revenues generally occur concurrently. Non-utility operating revenues are also derived from servicing appliances for customers at MERC. These contracts customarily have a duration of one year or less and consist of a single performance obligation satisfied over time. We use a time-based output method to recognize revenues monthly for the service fee. Consistent with the timing of when we recognize revenue, customer billings for the wind generation and servicing revenues generally occur on a monthly basis, with payments typically due in full within 30 days. As part of the construction of the We Power electric generating units, we capitalized interest during construction, which is included in property, plant, and equipment. As allowed by the PSCW, we collected these carrying costs from WE's utility customers during construction. The equity portion of these carrying costs was recorded as a contract liability, which is presented as deferred revenue, net on our balance sheets. We continually amortize the deferred carrying costs to revenues over the related lease term that We Power has with WE. During 2022, 2021, and 2020, we recorded $23.4 million, $23.3 million, and $22.9 million, respectively, of revenues related to these deferred carrying costs. Other Operating Revenues Alternative Revenues Alternative revenues are created from programs authorized by regulators that allow our utilities to record additional revenues by adjusting rates in the future, usually as a surcharge applied to future billings, in response to past activities or completed events. Alternative revenue programs allow compensation for the effects of weather abnormalities, other external factors, or demand side management initiatives. Alternative revenue programs can also provide incentive awards if the utility achieves certain objectives and in other limited circumstances. We record alternative revenues when the regulator-specified conditions for recognition have been met. We reverse these alternative revenues as the customer is billed, at which time this revenue is presented as revenues from contracts with customers. Below is a summary of the alternative revenue programs at our utilities: • The rates of PGL, NSG, and MERC include decoupling mechanisms. These mechanisms differ by state and allow the utilities to recover or refund the differences between actual and authorized margins for certain customer classes. See Note 26, Regulatory Environment, for more information. • PGL and NSG were authorized to implement a SPC rider for the recovery of incremental direct costs resulting from the COVID-19 pandemic, foregone late fees and reconnection charges, and the costs associated with their bill payment assistance programs. See Note 26, Regulatory Environment, for more information. • MERC’s rates include a CIP rider, which includes a financial incentive for meeting energy savings goals. • WE and WPS provide wholesale electric service to customers under market-based rates and FERC formula rates. The customer is charged a base rate each year based upon a formula using prior year actual costs and customer demand. A true-up is calculated based on the difference between the amount billed to customers for the demand component of their rates and what the actual |
Credit losses | The following discussion includes our significant accounting policies related to credit losses. For additional required disclosures on credit losses, see Note 5, Credit Losses. Effective January 1, 2020, we adopted FASB ASU 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, using the modified retrospective transition method. This ASU amends the impairment model to utilize an expected loss methodology in place of the incurred loss methodology for financial instruments, including trade receivables. The amendment requires entities to consider a broader range of information to estimate expected credit losses, which may result in earlier recognition of loss. The cumulative effect of adopting this standard was not significant to our financial statements. Our exposure to credit losses is related to our accounts receivable and unbilled revenue balances, which are primarily generated from the sale of electricity and natural gas by our regulated utility operations. Credit losses associated with our utility operations are analyzed at the reportable segment level as we believe contract terms, political and economic risks, and the regulatory environment are similar at this level as our reportable segments are generally based on the geographic location of the underlying utility operations. We have an accounts receivable and unbilled revenue balance associated with our non-utility energy infrastructure segment, related to the sale of electricity from our majority-owned wind generating facilities through agreements with several large high credit quality counterparties. We evaluate the collectability of our accounts receivable and unbilled revenue balances considering a combination of factors. For some of our larger customers and also in circumstances where we become aware of a specific customer's inability to meet its financial obligations to us, we record a specific allowance for credit losses against amounts due in order to reduce the net recognized receivable to the amount we reasonably believe will be collected. For all other customers, we use the accounts receivable aging method to calculate an allowance for credit losses. Using this method, we classify accounts receivable into different aging buckets and calculate a reserve percentage for each aging bucket based upon historical loss rates. The calculated reserve percentages are updated on at least an annual basis, in order to ensure recent macroeconomic, political, and regulatory trends are captured in the calculation, to the extent possible. Risks identified that we do not believe are reflected in the calculated reserve percentages, are assessed on a quarterly basis to determine whether further adjustments are required. |
Materials, supplies and inventories | Our inventory as of December 31 consisted of: (in millions) 2022 2021 Natural gas in storage $ 446.3 $ 326.0 Materials and supplies 257.0 225.3 Fossil fuel 103.8 84.5 Total $ 807.1 $ 635.8 PGL and NSG price natural gas storage injections at the calendar year average of the costs of natural gas supply purchased. Withdrawals from storage are priced on the LIFO cost method. Inventories stated on a LIFO basis represented approximately 13% and 19% of total inventories at December 31, 2022 and 2021, respectively. The estimated replacement cost of natural gas in inventory at December 31, 2022 and 2021, exceeded the LIFO cost by $98.3 million and $114.2 million, respectively. In calculating these replacement amounts, PGL and NSG used a Chicago city-gate natural gas price per Dth of $3.41 at December 31, 2022, and $3.67 at December 31, 2021. Substantially all other natural gas in storage, materials and supplies, and fossil fuel inventories are recorded using the weighted-average cost method of accounting. |
Regulatory assets and liabilities | The economic effects of regulation can result in regulated companies recording costs and revenues that are allowed in the ratemaking process in a period different from the period they would have been recognized by a nonregulated company. When this occurs, regulatory assets and regulatory liabilities are recorded on the balance sheet. Regulatory assets represent deferred costs probable of recovery from customers that would have otherwise been charged to expense. Regulatory liabilities represent amounts that are expected to be refunded to customers in future rates or future costs already collected from customers in rates.The recovery or refund of regulatory assets and liabilities is based on specific periods determined by our regulators or occurs over the normal operating period of the related assets and liabilities. If a previously recorded regulatory asset is no longer probable of recovery, the regulatory asset is reduced to the amount considered probable of recovery, and the reduction is charged to expense in the current period. See Note 6, Regulatory Assets and Liabilities, for more information. |
Property, plant, and equipment | We record property, plant, and equipment at cost. Cost includes material, labor, overhead, and both debt and equity components of AFUDC. Additions to and significant replacements of property are charged to property, plant, and equipment at cost; minor items are charged to other operation and maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired. We record straight-line depreciation expense over the estimated useful life of utility property using depreciation rates approved by the applicable regulators. Annual utility composite depreciation rates are shown below: Annual Utility Composite Depreciation Rates 2022 2021 2020 WE 3.06% 3.09% 3.19% WPS 2.67% 2.66% 2.63% WG 2.47% 2.44% 2.33% PGL 3.13% 3.12% 3.16% NSG 2.43% 2.52% 2.48% MERC 2.56% 2.58% 2.47% MGU 2.75% 2.70% 2.67% UMERC 3.01% 2.94% 2.97% We depreciate our We Power assets over the estimated useful life of the various property components. The components have useful lives of between 10 to 45 years for PWGS 1 and PWGS 2 and 10 to 55 years for ER 1 and ER 2. We capitalize certain costs related to software developed or obtained for internal use and record these costs to amortization expense over the estimated useful life of the related software, which ranges from 3 to 15 years. If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statement. Third parties reimburse the utilities for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs are recorded as a reduction to property, plant, and equipment. See Note 7, Property, Plant, and Equipment, for more information. |
AFUDC | AFUDC is included in utility plant accounts and represents the cost of borrowed funds (AFUDC–Debt) used during plant construction, and a return on shareholders' capital (AFUDC–Equity) used for construction purposes. AFUDC–Debt is recorded as a reduction of interest expense, and AFUDC–Equity is recorded in other income, net. The majority of AFUDC is recorded at WE, WPS, WG, UMERC, and WBS. Approximately 50% of WE's, WPS's, WG's, UMERC's, and WBS's retail jurisdictional CWIP expenditures are subject to the AFUDC calculation. The AFUDC calculation for WBS uses the WPS AFUDC retail rate, while our utilities' AFUDC rates are determined by their respective state commissions, each with specific requirements. Average AFUDC rates are shown below: 2022 Average AFUDC Retail Rate Average AFUDC Wholesale Rate WE 8.68% 5.35% WPS 7.55% 5.49% WG 8.32% N/A UMERC 6.28% N/A WBS 7.55% N/A Our regulated utilities and WBS recorded the following AFUDC for the years ended December 31: (in millions) 2022 2021 2020 AFUDC–Debt WE $ 6.9 $ 2.9 $ 2.6 WPS 2.3 3.5 4.6 WG 1.4 0.2 0.6 UMERC 0.1 0.1 — WBS 0.1 0.1 0.1 Other 0.2 — 0.1 Total AFUDC–Debt $ 11.0 $ 6.8 $ 8.0 AFUDC–Equity WE $ 18.8 $ 7.9 $ 7.0 WPS 5.8 9.0 11.8 WG 3.9 0.6 1.6 UMERC 0.1 0.1 0.1 WBS 0.3 0.2 0.2 Other 0.5 0.2 0.2 Total AFUDC–Equity $ 29.4 $ 18.0 $ 20.9 |
Cloud Computing Hosting Arrangements that are Service Contracts | We have entered into several cloud computing arrangements that are hosted service contracts as part of projects related to the continuous transformation of technology. These projects include, among other things, developing a centralized repository for data to improve analytics and reporting, targeted enterprise resource planning systems, a project management tool, and a power generation employee scheduling system. We present prepaid hosting fees that are service contracts in either prepayments or other long-term assets on our balance sheets and amortize them as the hosting services are received. Amortization expense, as well as the fees associated with the hosting arrangements, is recorded in other operation and maintenance expense on our income statements.At December 31, 2022 and 2021, we had $4.7 million and $3.3 million, respectively, of capitalized implementation costs related to cloud computing arrangements that are hosted service contracts. We amortize the implementation costs on a straight-line basis over the cloud computing service arrangement term once the component of the hosted service is ready for its intended use. Accumulated amortization at December 31, 2022 and 2021, was $1.5 million and $0.6 million, respectively. Amortization expense for the years ended December 31, 2022, 2021, and 2020 was not significant. The presentation of the implementation costs, along with the related accumulated amortization, follows the prepaid hosting fees. |
Impairment of goodwill and other intangible assets | Goodwill and other intangible assets with indefinite lives are subject to an annual impairment test. Interim impairment tests are performed when impairment indicators are present. During the third quarter of each year, we perform an annual impairment test at all of our reporting units that carry a goodwill balance. The carrying amount of the reporting unit's goodwill is considered not recoverable if the carrying amount of the reporting unit's net assets exceeds the reporting unit's fair value. An impairment loss is recorded as the excess of the carrying amount of the goodwill over its fair value. For our indefinite-lived intangible assets, an impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds the fair value of the asset. An impairment loss is measured as the excess of the carrying amount of the intangible assets over its fair value. No impairment losses were recorded for our indefinite-lived intangible assets during the years ended December 31, 2022 and 2021. See Note 10, Goodwill and Intangibles, for more information. |
Impairment of long-lived assets | We periodically assess the recoverability of certain long-lived assets when factors indicate the carrying value of such assets may be impaired or such assets are planned to be sold. Long-lived assets that would be subject to an impairment assessment generally include any assets within regulated operations that may not be fully recovered from our customers as a result of regulatory decisions that will be made in the future, as well as assets within nonregulated operations that are proposed to be sold or are currently generating operating losses. An impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds the fair value of the asset. The carrying amount of an asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. An impairment loss is measured as the excess of the carrying amount of the asset over the fair value of the asset. When it becomes probable that a generating unit will be retired before the end of its useful life, we assess whether the generating unit meets the criteria for abandonment accounting. Generating units that are considered probable of abandonment are expected to cease operations in the near term, significantly before the end of their original estimated useful lives. If a generating unit meets the applicable criteria to be considered probable of abandonment, and the unit has been abandoned, we assess the likelihood of recovery of the remaining net book value of that generating unit at the end of each reporting period. If it becomes probable that regulators will disallow full recovery as well as a return on the remaining net book value of a generating unit that is either abandoned or probable of being abandoned, an impairment loss may be required. An impairment loss would be recorded if the remaining net book value of the generating unit is greater than the present value of the amount expected to be recovered from ratepayers, using an incremental borrowing rate. See Note 6, Regulatory Assets and Liabilities, and Note 7, Property, Plant, and Equipment, for more information. |
Impairment of equity method investments | We periodically assess the recoverability of equity method investments when factors indicate the carrying amount of such assets may be impaired. Equity method investments are assessed for impairment by comparing the fair values of these investments to their carrying amounts if a fair value assessment was completed or by reviewing for the presence of impairment indicators. If an impairment exists, and it is determined to be other-than-temporary, an impairment loss is recognized equal to the amount by which the carrying amount exceeds the investment's fair value. |
Asset retirement obligations | We recognize, at fair value, legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and normal operation of the assets. An ARO liability is recorded, when incurred, for these obligations as long as the fair value can be reasonably estimated, even if the timing or method of settling the obligation is unknown. The associated retirement costs are capitalized as part of the related long-lived asset and are depreciated over the useful life of the asset. The ARO liabilities are accreted each period using the credit-adjusted risk-free interest rates associated with the expected settlement dates of the AROs. These rates are determined when the obligations are incurred. Subsequent changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or a decrease to the carrying amount of the liability and the associated capitalized retirement costs. For our regulated entities, we recognize regulatory assets or liabilities for the timing differences between when we recover an ARO in rates and when we recognize the associated retirement costs. See Note 9, Asset Retirement Obligations, for more information. |
Intangible liabilities | Our finite-lived intangible liabilities include revenue contracts, consisting of PPAs and a proxy revenue swap, in addition to interconnection agreements, which were all obtained through the acquisitions of wind generation facilities by WECI in our non-utility energy infrastructure segment. Intangible liabilities are amortized on a straight-line basis over their estimated useful life. Amortization of revenue contracts is recorded within operating revenues in the income statements. Amortization related to the interconnection agreements is recorded within other operation and maintenance in the income statements. The straight-line method of amortization is used because it best reflects the pattern in which the economic benefits of the intangibles are consumed or otherwise used. The amounts and useful lives assigned to intangible liabilities assumed impact the amount and timing of future amortization. |
Stock-based compensation | In accordance with the Omnibus Stock Incentive Plan, we provide long-term incentives through our equity interests to our non-employee directors, officers, and other key employees. The plan provides for the granting of stock options, restricted stock, performance shares, and other stock-based awards. Awards may be paid in common stock, cash, or a combination thereof. In addition to those shares of common stock that were subject to awards outstanding as of May 6, 2021, 9.0 million shares are reserved for issuance under the plan. We recognize stock-based compensation expense on a straight-line basis over the requisite service period. Awards classified as equity awards are measured based on their grant-date fair value. Awards classified as liability awards are recorded at fair value each reporting period. We account for forfeitures as they occur, rather than estimating potential future forfeitures and recording them over the vesting period. Stock Options We grant non-qualified stock options that generally vest on a cliff-basis after three years. The exercise price of a stock option under the plan cannot be less than 100% of our common stock's fair market value on the grant date. Historically, all stock options have been granted with an exercise price equal to the fair market value of our common stock on the date of the grant. Options vest immediately upon retirement, death, or disability; however, they may not be exercised within six months of the grant date except in connection with certain termination of employment events following a change in control. Options expire no later than 10 years from the date of the grant. Our stock options are classified as equity awards. The fair value of our stock options was calculated using a binomial option-pricing model. The following table shows the estimated weighted-average fair value per stock option granted along with the weighted-average assumptions used in the valuation models: 2022 2021 2020 Stock options granted 437,269 530,612 554,594 Estimated weighted-average fair value per stock option $ 14.71 $ 13.20 $ 10.94 Assumptions used to value the options: Risk-free interest rate 0.2% – 1.6% 0.1% – 0.9% 0.2% – 1.9% Dividend yield 3.2 % 2.9 % 3.0 % Expected volatility 21.0 % 21.0 % 16.3 % Expected life (years) 8.7 8.7 8.6 The risk-free interest rate was based on the United States Treasury interest rate with a term consistent with the expected life of the stock options. The dividend yield was based on our dividend rate at the time of the grant and historical stock prices. Expected volatility and expected life assumptions were based on our historical experience. Restricted Shares Restricted shares granted to employees generally have a vesting period of three years with one-third of the award vesting on each anniversary of the grant date. Restricted shares granted to certain officers and all non-employee directors fully vest after one year. Our restricted shares are classified as equity awards. Performance Units Officers and other key employees are granted performance units under the WEC Energy Group Performance Unit Plan. All grants of performance units are settled in cash and are accounted for as liability awards accordingly. Performance units accrue forfeitable dividend equivalents in the form of additional performance units. The fair value of the performance units reflects our estimate of the final expected value of the awards, which is based on our stock price and performance achievement under the terms of the award. Stock-based compensation costs are generally recorded over the performance period, which is three years. The ultimate number of units that will be awarded is dependent on our total shareholder return (stock price appreciation plus dividends) as compared to the total shareholder return of a peer group of companies over three years, as well as other performance metrics, as may be determined by the Compensation Committee. Under the terms of awards granted prior to 2023, participants may earn between 0% and 175% of the performance unit award based on our total shareholder return. Pursuant to the plan terms governing these awards, these percentages can be adjusted upwards or downwards by up to 10% based on our performance against additional performance measures, if any, adopted by the Compensation Committee. The WEC Energy Group Performance Unit Plan was amended and restated, effective January 1, 2023. In accordance with the amended plan, the Compensation Committee selected multiple performance measures that will be weighted to determine the ultimate payout for the awards granted in 2023. The ultimate number of units awarded will be based on our total shareholder return compared to the total shareholder return of a peer group of companies over three years (55%), and our performance against the weighted average authorized ROE of all of our utility subsidiaries (45%). In addition, the Compensation Committee selected the level of our stock price to earnings ratio compared to our peer companies as a performance measure that can increase the payout by up to 25%. In no event can the performance unit payout be greater than 200% of the target award. See Note 11, Common Equity, for more information on our stock-based compensation plans. |
Stock-based compensation - forfeitures | We account for forfeitures as they occur, rather than estimating potential future forfeitures and recording them over the vesting period. |
Earnings per share | We compute basic earnings per share by dividing our net income attributed to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted earnings per share is computed in a similar manner, but includes the exercise and/or conversion of all potentially dilutive securities. Such dilutive securities include in-the-money stock options. The calculation of diluted earnings per share for the years ended December 31, 2022, 2021, and 2020 excluded 653,323; 769,030; and 207,445 stock options, respectively, that had an anti-dilutive effect. |
Leases | We recognize a right of use asset and lease liability for operating and finance leases with a term of greater than one year. As a policy election, we account for each lease component separately from the nonlease components of a contract. We are currently party to several easement agreements that allow us access to land we do not own for the purpose of constructing and maintaining certain electric power and natural gas equipment. The majority of payments we make related to easements relate to our renewable generating facilities. We have not classified our easements as leases because we view the entire parcel of land specified in our easement agreements to be the identified asset, not just that portion of the parcel that contains our easement. As such, we have concluded that we do not control the use of an identified asset related to our easement agreements, nor do we obtain substantially all of the economic benefits associated with these shared-use assets. See Note 15, Leases, for more information. |
Income taxes | We follow the liability method in accounting for income taxes. Accounting guidance for income taxes requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax balances to reflect tax rate changes. We are required to assess the likelihood that our deferred tax assets would expire before being realized. If we conclude that certain deferred tax assets are likely to expire before being realized, a valuation allowance would be established against those assets. GAAP requires that, if we conclude in a future period that it is more likely than not that some or all of the deferred tax assets would be realized before expiration, we reverse the related valuation allowance in that period. Any change to the allowance, as a result of a change in judgment about the realization of deferred tax assets, is reported in income tax expense. ITCs associated with regulated operations are deferred and amortized over the life of the assets. PTCs are recognized in the period in which such credits are generated. The amount of the credit is based upon power production from our qualifying generation facilities. We file a consolidated federal income tax return. Accordingly, we allocate federal current tax expense, benefits, and credits to our subsidiaries based on their separate tax computations and our ability to monetize all credits on our consolidated federal return. See Note 16, Income Taxes, for more information. We recognize interest and penalties accrued, related to unrecognized tax benefits, in income tax expense in our income statements. |
Fair value measurements | Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods. Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. When possible, we base the valuations of our 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 and TCRs, are categorized in Level 3 due to the significance of unobservable or internally-developed inputs. FTRs and TCRs are valued using auction prices from the applicable RTO. See Note 17, Fair Value Measurements, for more information. |
Derivative instruments | We use derivatives as part of our risk management program to manage the risks associated with the price volatility of interest rates, purchased power, generation, and natural gas costs for the benefit of our customers and shareholders. Our approach is non-speculative and designed to mitigate risk. Regulated hedging programs are approved by our state regulators. We record derivative instruments on our balance sheets as assets or liabilities measured at fair value unless they qualify for the normal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities. We classify derivative assets and liabilities as current or long-term on our balance sheets based on the maturities of the underlying contracts. Cash flows from derivative activities are presented in the same category as the item being hedged within operating activities on our statements of cash flows. Derivative accounting rules provide the option to present certain asset and liability derivative positions net on the balance sheets and to net the related cash collateral against these net derivative positions. We elected not to net these items. On our balance sheets, cash collateral provided to others is reflected in other current assets, and cash collateral received is reflected in other current liabilities. See Note 18, Derivative Instruments, for more information. |
Guarantees | We follow the guidance of the Guarantees Topic of the FASB ASC, which requires, under certain circumstances, that the guarantor recognize a liability for the fair value of the obligation undertaken in issuing the guarantee at its inception. See Note 19, Guarantees, for more information. |
Employee benefits | The costs of pension and OPEB plans are expensed over the periods during which employees render service. These costs are distributed among our subsidiaries based on current employment status and actuarial calculations, as applicable. Our regulators allow recovery in rates for the utilities' net periodic benefit cost calculated under GAAP. See Note 20, Employee Benefits, for more information. |
Customer deposits and credit balances | When utility customers apply for new service, they may be required to provide a deposit for the service. Customer deposits are recorded within other current liabilities on our balance sheets.Utility customers can elect to be on a budget plan. Under this type of plan, a monthly installment amount is calculated based on estimated annual usage. During the year, the monthly installment amount is reviewed by comparing it to actual usage. If necessary, an adjustment is made to the monthly amount. Annually, the budget plan is reconciled to actual annual usage. Payments in excess of actual customer usage are recorded within other current liabilities on our balance sheets. |
Environmental remediation costs | We are subject to federal and state environmental laws and regulations that in the future may require us to pay for environmental remediation at sites where we have been, or may be, identified as a potentially responsible party. Loss contingencies may exist for the remediation of hazardous substances at various potential sites, including coal combustion residual landfills and manufactured gas plant sites. See Note 9, Asset Retirement Obligations, for more information regarding coal combustion residual landfills and Note 24, Commitments and Contingencies, for more information regarding manufactured gas plant sites. We record environmental remediation liabilities when site assessments indicate remediation is probable, and we can reasonably estimate the loss or a range of losses. The estimate includes both our share of the liability and any additional amounts that will not be paid by other potentially responsible parties or the government. When possible, we estimate costs using site-specific information but also consider historical experience for costs incurred at similar sites. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws governing the remediation process may change, as well as site conditions, potentially affecting the cost of remediation. Our utilities have received approval to defer certain environmental remediation costs, as well as estimated future costs, through a regulatory asset. The recovery of deferred costs is subject to the applicable state regulatory commission's approval. We review our estimated costs of remediation annually for our manufactured gas plant sites and coal combustion residual landfills. We adjust the liabilities and related regulatory assets, as appropriate, to reflect the new cost estimates. Any material changes in cost estimates are adjusted throughout the year. |
Customer concentration of credit risk | The geographic concentration of our customers did not contribute significantly to our overall exposure to credit risk. We periodically review customers' credit ratings, financial statements, and historical payment performance and require them to provide collateral or other security as needed. Credit risk exposure at WE, WPS, WG, PGL, and NSG is mitigated by their recovery mechanisms for uncollectible expense discussed in Note 1(d), Operating Revenues. As a result, we did not have any significant concentrations of credit risk at December 31, 2022. In addition, there were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2022 |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Accounting Policies [Abstract] | |
Schedule of inventory | Our inventory as of December 31 consisted of: (in millions) 2022 2021 Natural gas in storage $ 446.3 $ 326.0 Materials and supplies 257.0 225.3 Fossil fuel 103.8 84.5 Total $ 807.1 $ 635.8 |
Schedule of annual utility composite depreciation rates | Annual utility composite depreciation rates are shown below: Annual Utility Composite Depreciation Rates 2022 2021 2020 WE 3.06% 3.09% 3.19% WPS 2.67% 2.66% 2.63% WG 2.47% 2.44% 2.33% PGL 3.13% 3.12% 3.16% NSG 2.43% 2.52% 2.48% MERC 2.56% 2.58% 2.47% MGU 2.75% 2.70% 2.67% UMERC 3.01% 2.94% 2.97% |
Schedule of AFUDC rates and amounts | Average AFUDC rates are shown below: 2022 Average AFUDC Retail Rate Average AFUDC Wholesale Rate WE 8.68% 5.35% WPS 7.55% 5.49% WG 8.32% N/A UMERC 6.28% N/A WBS 7.55% N/A Our regulated utilities and WBS recorded the following AFUDC for the years ended December 31: (in millions) 2022 2021 2020 AFUDC–Debt WE $ 6.9 $ 2.9 $ 2.6 WPS 2.3 3.5 4.6 WG 1.4 0.2 0.6 UMERC 0.1 0.1 — WBS 0.1 0.1 0.1 Other 0.2 — 0.1 Total AFUDC–Debt $ 11.0 $ 6.8 $ 8.0 AFUDC–Equity WE $ 18.8 $ 7.9 $ 7.0 WPS 5.8 9.0 11.8 WG 3.9 0.6 1.6 UMERC 0.1 0.1 0.1 WBS 0.3 0.2 0.2 Other 0.5 0.2 0.2 Total AFUDC–Equity $ 29.4 $ 18.0 $ 20.9 |
Schedule of assumptions used to estimate the fair value of stock options granted | The following table shows the estimated weighted-average fair value per stock option granted along with the weighted-average assumptions used in the valuation models: 2022 2021 2020 Stock options granted 437,269 530,612 554,594 Estimated weighted-average fair value per stock option $ 14.71 $ 13.20 $ 10.94 Assumptions used to value the options: Risk-free interest rate 0.2% – 1.6% 0.1% – 0.9% 0.2% – 1.9% Dividend yield 3.2 % 2.9 % 3.0 % Expected volatility 21.0 % 21.0 % 16.3 % Expected life (years) 8.7 8.7 8.6 |
Acquisitions (Tables)
Acquisitions (Tables) - WECI | 12 Months Ended |
Dec. 31, 2022 | |
Blooming Grove | |
Asset Acquisition | |
Allocation of purchase price | The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition. (in millions) Accounts receivable $ 0.3 Net property, plant, and equipment 488.3 Other long-term assets 2.9 Accounts payable (13.7) Other current liabilities (1.5) Other long-term liabilities (68.7) Noncontrolling interest (43.0) Total purchase price $ 364.6 |
Thunderhead | |
Asset Acquisition | |
Allocation of purchase price | The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition. (in millions) Accounts receivable $ 0.2 Other prepayments 0.3 Net property, plant, and equipment 692.3 Other long-term assets 5.1 Other current liabilities (0.2) Other long-term liabilities (273.2) Noncontrolling interest (42.5) Total purchase price $ 382.0 |
Jayhawk | |
Asset Acquisition | |
Allocation of purchase price | The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition. (in millions) Net property, plant, and equipment $ 145.3 Other long-term liabilities (11.8) Long-term debt (7.3) Noncontrolling interest (6.3) Total purchase price $ 119.9 |
Tatanka Ridge | |
Asset Acquisition | |
Allocation of purchase price | The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition. (in millions) Other current assets $ 37.3 Net property, plant, and equipment 301.2 Other current liabilities (37.3) Other long-term liabilities (19.3) Noncontrolling interest (42.0) Total purchase price $ 239.9 |
Operating Revenues (Tables)
Operating Revenues (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Disaggregation of Operating Revenues | |
Operating revenues disaggregated by revenue source | (in millions) Wisconsin Illinois Other States Total Utility Non-Utility Energy Infrastructure Corporate Reconciling WEC Energy Group Consolidated Year ended December 31, 2022 Electric $ 4,956.2 $ — $ — $ 4,956.2 $ — $ — $ — $ 4,956.2 Natural gas 1,980.7 1,883.7 601.8 4,466.2 54.3 — (51.8) 4,468.7 Total regulated revenues 6,936.9 1,883.7 601.8 9,422.4 54.3 — (51.8) 9,424.9 Other non-utility revenues — — 18.7 18.7 133.6 — (9.1) 143.2 Total revenues from contracts with customers 6,936.9 1,883.7 620.5 9,441.1 187.9 — (60.9) 9,568.1 Other operating revenues 23.6 7.2 (2.0) 28.8 402.1 0.5 (402.1) (1) 29.3 Total operating revenues $ 6,960.5 $ 1,890.9 $ 618.5 $ 9,469.9 $ 590.0 $ 0.5 $ (463.0) $ 9,597.4 (in millions) Wisconsin Illinois Other States Total Utility Non-Utility Energy Infrastructure Corporate Reconciling WEC Energy Group Consolidated Year ended December 31, 2021 Electric $ 4,516.6 $ — $ — $ 4,516.6 $ — $ — $ — $ 4,516.6 Natural gas 1,490.3 1,630.3 494.0 3,614.6 46.8 — (43.8) 3,617.6 Total regulated revenues 6,006.9 1,630.3 494.0 8,131.2 46.8 — (43.8) 8,134.2 Other non-utility revenues — — 17.8 17.8 92.8 — (9.1) 101.5 Total revenues from contracts with customers 6,006.9 1,630.3 511.8 8,149.0 139.6 — (52.9) 8,235.7 Other operating revenues 30.1 42.5 7.2 79.8 399.9 0.5 (399.9) (1) 80.3 Total operating revenues $ 6,037.0 $ 1,672.8 $ 519.0 $ 8,228.8 $ 539.5 $ 0.5 $ (452.8) $ 8,316.0 (in millions) Wisconsin Illinois Other States Total Utility Non-Utility Energy Infrastructure Corporate Reconciling WEC Energy Group Consolidated Year Ended December 31, 2020 Electric $ 4,266.1 $ — $ — $ 4,266.1 $ — $ — $ — $ 4,266.1 Natural gas 1,195.6 1,267.9 361.0 2,824.5 44.4 — (42.0) 2,826.9 Total regulated revenues 5,461.7 1,267.9 361.0 7,090.6 44.4 — (42.0) 7,093.0 Other non-utility revenues — — 17.1 17.1 66.6 1.7 (9.1) 76.3 Total revenues from contracts with customers 5,461.7 1,267.9 378.1 7,107.7 111.0 1.7 (51.1) 7,169.3 Other operating revenues 11.8 54.0 6.0 71.8 397.5 0.5 (397.4) (1) 72.4 Total operating revenues $ 5,473.5 $ 1,321.9 $ 384.1 $ 7,179.5 $ 508.5 $ 2.2 $ (448.5) $ 7,241.7 (1) Amounts eliminated represent lease revenues related to certain plants that We Power leases to WE to supply electricity to its customers. Lease payments are billed from We Power to WE and then recovered in WE's rates as authorized by the PSCW and the FERC. WE operates the plants and is authorized by the PSCW and Wisconsin state law to fully recover prudently incurred operating and maintenance costs in electric rates. |
Revenues from contracts with customers | Electric | |
Disaggregation of Operating Revenues | |
Operating revenues disaggregated by revenue source | The following table disaggregates electric utility operating revenues into customer class: Year Ended December 31 (in millions) 2022 2021 2020 Residential $ 1,879.1 $ 1,768.0 $ 1,743.9 Small commercial and industrial 1,530.4 1,415.7 1,325.9 Large commercial and industrial 1,042.2 931.9 821.5 Other 29.9 29.3 29.0 Total retail revenues 4,481.6 4,144.9 3,920.3 Wholesale 153.9 157.7 174.0 Resale 256.7 161.9 130.4 Steam 28.4 28.7 21.3 Other utility revenues 35.6 23.4 20.1 Total electric utility operating revenues $ 4,956.2 $ 4,516.6 $ 4,266.1 |
Revenues from contracts with customers | Natural gas | |
Disaggregation of Operating Revenues | |
Operating revenues disaggregated by revenue source | The following tables disaggregate natural gas utility operating revenues into customer class: (in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues Year ended December 31, 2022 Residential $ 1,234.0 $ 1,297.4 $ 391.3 $ 2,922.7 Commercial and industrial 672.7 408.8 218.7 1,300.2 Total retail revenues 1,906.7 1,706.2 610.0 4,222.9 Transportation 81.8 259.8 34.5 376.1 Other utility revenues (1) (2) (7.8) (82.3) (42.7) (132.8) Total natural gas utility operating revenues $ 1,980.7 $ 1,883.7 $ 601.8 $ 4,466.2 (in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues Year ended December 31, 2021 Residential $ 928.9 $ 1,017.9 $ 241.2 $ 2,188.0 Commercial and industrial 472.1 302.1 129.9 904.1 Total retail revenues 1,401.0 1,320.0 371.1 3,092.1 Transportation 80.0 231.2 31.8 343.0 Other utility revenues (1) (3) 9.3 79.1 91.1 179.5 Total natural gas utility operating revenues $ 1,490.3 $ 1,630.3 $ 494.0 $ 3,614.6 (in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues Year Ended December 31, 2020 Residential $ 752.6 $ 802.2 $ 220.8 $ 1,775.6 Commercial and industrial 338.1 221.0 115.8 674.9 Total retail revenues 1,090.7 1,023.2 336.6 2,450.5 Transportation 79.1 215.6 31.5 326.2 Other utility revenues (1) 25.8 29.1 (7.1) 47.8 Total natural gas utility operating revenues $ 1,195.6 $ 1,267.9 $ 361.0 $ 2,824.5 (1) Includes the revenues subject to the purchased gas recovery mechanisms of our utilities. (2) During 2022, we continued to recover natural gas costs we under-collected from our customers in 2021 related to the extreme weather experienced in February 2021, as well as higher natural gas costs incurred at the majority of our segments during 2022. As these amounts are billed to customers, they are reflected in retail revenues with an offsetting decrease in other utility revenues. (3) During 2021, in addition to costs related to the extreme weather event experienced in February 2021, we incurred higher natural gas costs as a result of an increase in the price of natural gas. |
Revenues from contracts with customers | Other non-utility revenues | |
Disaggregation of Operating Revenues | |
Operating revenues disaggregated by revenue source | Other non-utility operating revenues consist primarily of the following: Year Ended December 31 (in millions) 2022 2021 2020 Wind generation revenues $ 101.0 $ 60.3 $ 34.6 We Power revenues 23.4 23.3 22.9 Appliance service revenues 18.7 17.8 17.1 Other 0.1 0.1 1.7 Total other non-utility operating revenues $ 143.2 $ 101.5 $ 76.3 |
Other operating revenues | |
Disaggregation of Operating Revenues | |
Operating revenues disaggregated by revenue source | Other operating revenues consist primarily of the following: Year Ended December 31 (in millions) 2022 2021 2020 Late payment charges (1) $ 55.6 $ 54.9 $ 29.4 Alternative revenues (2) (30.3) 21.2 38.8 Other 4.0 4.2 4.2 Total other operating revenues $ 29.3 $ 80.3 $ 72.4 (1) The increase in late payment charges during 2021, compared with 2020, was a result of the expiration of various regulatory orders from our utility commissions in response to the COVID-19 pandemic, which included the suspension of late payment charges during a designated time period. See Note 26, Regulatory Environment, for more information. (2) Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. Negative amounts can also result from revenues to be refunded to customers subject to decoupling mechanisms, wholesale true-ups, conservation improvement rider true-ups, and certain late payment charges. |
Credit Losses (Tables)
Credit Losses (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Credit Loss [Abstract] | |
Schedule of gross receivables and related allowances for credit losses | We have included tables below that show our gross third-party receivable balances and the related allowance for credit losses at December 31, 2022 and 2021, by reportable segment. (in millions) Wisconsin Illinois Other States Total Utility Non-Utility Energy Infrastructure Corporate WEC Energy Group Consolidated December 31, 2022 Accounts receivable and unbilled revenues $ 1,199.4 $ 624.2 $ 164.4 $ 1,988.0 $ 25.4 $ 4.3 $ 2,017.7 Allowance for credit losses 82.0 111.0 6.3 199.3 — — 199.3 Accounts receivable and unbilled revenues, net (1) $ 1,117.4 $ 513.2 $ 158.1 $ 1,788.7 $ 25.4 $ 4.3 $ 1,818.4 Total accounts receivable, net – past due greater than 90 days (1) $ 51.9 $ 52.9 $ 1.9 $ 106.7 $ — $ — $ 106.7 Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1) 97.0 % 100.0 % — % 96.8 % — % — % 96.8 % (in millions) Wisconsin Illinois Other States Total Utility Non-Utility Energy Infrastructure Corporate WEC Energy Group Consolidated December 31, 2021 Accounts receivable and unbilled revenues $ 1,053.1 $ 523.1 $ 105.7 $ 1,681.9 $ 17.0 $ 5.1 $ 1,704.0 Allowance for credit losses 84.0 105.5 8.8 198.3 — — 198.3 Accounts receivable and unbilled revenues, net (1) $ 969.1 $ 417.6 $ 96.9 $ 1,483.6 $ 17.0 $ 5.1 $ 1,505.7 Total accounts receivable, net – past due greater than 90 days (1) $ 46.5 $ 36.6 $ 3.4 $ 86.5 $ — $ — $ 86.5 Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1) 97.6 % 100.0 % — % 94.8 % — % — % 94.8 % (1) Our exposure to credit losses for certain regulated utility customers is mitigated by regulatory mechanisms we have in place. Specifically, rates related to all of the customers in our Illinois segment, as well as the residential rates of WE, WPS, and WG in our Wisconsin segment, include riders or other mechanisms for cost recovery or refund of uncollectible expense based on the difference between the actual provision for credit losses and the amounts recovered in rates. As a result, at December 31, 2022, $1,079.1 million, or 59.3%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses. |
Rollforward of the allowances for credit losses by reportable segment | A rollforward of the allowance for credit losses by reportable segment for the years ended December 31, 2022, 2021, and 2020, is included below: (in millions) Wisconsin Illinois Other States Total Utility Corporate WEC Energy Group Consolidated Balance at January 1, 2022 $ 84.0 $ 105.5 $ 8.8 $ 198.3 $ — $ 198.3 Provision for credit losses 50.5 33.0 2.6 86.1 — 86.1 Provision for credit losses deferred for future recovery or refund 29.7 33.2 — 62.9 — 62.9 Write-offs charged against the allowance (117.0) (82.6) (6.4) (206.0) — (206.0) Recoveries of amounts previously written off 34.8 21.9 1.3 58.0 — 58.0 Balance at December 31, 2022 $ 82.0 $ 111.0 $ 6.3 $ 199.3 $ — $ 199.3 On a consolidated basis, there was a $1.0 million increase in the allowance for credit losses during the year ended December 31, 2022. We believe that the high energy costs that customers are seeing, which have been driven by high natural gas prices, contributed to higher past due accounts receivable balances and a related increase in the allowance for credit losses. The increase was substantially offset by customer write-offs related to collection practices returning to pre-pandemic levels, including the restoration of our ability to disconnect customers. After a customer is disconnected for a period of time without payment on their account, we will write off that customer balance. (in millions) Wisconsin Illinois Other States Total Utility Corporate WEC Energy Group Consolidated Balance at January 1, 2021 $ 102.1 $ 111.6 $ 6.4 $ 220.1 $ — $ 220.1 Provision for credit losses 46.4 25.6 3.7 75.7 — 75.7 Provision for credit losses deferred for future recovery or refund (16.6) 3.5 — (13.1) — (13.1) Write-offs charged against the allowance (74.8) (52.5) (2.5) (129.8) — (129.8) Recoveries of amounts previously written off 26.9 17.3 1.2 45.4 — 45.4 Balance at December 31, 2021 $ 84.0 $ 105.5 $ 8.8 $ 198.3 $ — $ 198.3 The allowance for credit losses decreased during the year ended December 31, 2021, primarily related to normal collection practices resuming in April 2021 for our Wisconsin utilities and in June 2021 for our Illinois utilities. Across all of our reportable segments, higher year-over-year natural gas prices drove an increase in gross accounts receivable balances, partially offsetting the decrease in the allowance for credit losses attributed to collection efforts. (in millions) Wisconsin Illinois Other States Total Utility Corporate WEC Energy Group Consolidated Balance at January 1, 2020 $ 59.9 $ 75.9 $ 4.1 $ 139.9 $ 0.1 $ 140.0 Provision for credit losses 47.5 51.1 4.3 102.9 — 102.9 Provision for credit losses deferred for future recovery or refund 24.6 30.6 — 55.2 — 55.2 Write-offs charged against the allowance (65.9) (63.0) (3.4) (132.3) — (132.3) Recoveries of amounts previously written off 36.0 17.0 1.4 54.4 — 54.4 Sale of PDL residential solar facilities — — — — (0.1) (0.1) Balance at December 31, 2020 $ 102.1 $ 111.6 $ 6.4 $ 220.1 $ — $ 220.1 The allowance for credit losses increased during the year ended December 31, 2020, driven by higher past due accounts receivable balances at our utility segments, primarily related to residential customers. This increase in accounts receivable balances in arrears was driven by economic disruptions caused by the COVID-19 pandemic, including higher unemployment rates. Also, as a result of the COVID-19 pandemic and related regulatory orders we received, we were unable to disconnect any of our Wisconsin and Illinois customers during the year ended December 31, 2020. |
Regulatory Assets and Liabili_2
Regulatory Assets and Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Schedule of regulatory assets | The following regulatory assets were reflected on our balance sheets as of December 31: (in millions) 2022 2021 See Note Regulatory assets (1) (2) Pension and OPEB costs (3) $ 714.3 $ 802.3 20 Plant retirement related items 688.6 722.3 Environmental remediation costs (4) 610.7 630.9 24 Income tax related items 461.9 458.8 16 AROs 169.7 194.2 1(l), 9 Derivatives 133.8 33.1 1(s) SSR (5) 123.5 129.5 Securitization 92.4 100.7 23 Uncollectible expense 69.3 42.6 5 MERC extraordinary natural gas costs (6) 35.1 59.7 26 Energy efficiency programs (7) 33.9 22.0 Energy costs recoverable through rate adjustments 26.9 85.4 1(d), 26 Other, net 146.8 85.6 Total regulatory assets $ 3,306.9 $ 3,367.1 Balance sheet presentation Other current assets $ 42.3 $ 102.3 Regulatory assets 3,264.6 3,264.8 Total regulatory assets $ 3,306.9 $ 3,367.1 (1) Based on prior and current rate treatment, we believe it is probable that our utilities will continue to recover from customers the regulatory assets in this table. In accordance with GAAP, our regulatory assets do not include the allowance for ROE that is capitalized for regulatory purposes. This allowance was $27.3 million and $30.9 million at December 31, 2022 and 2021, respectively. (2) As of December 31, 2022, we had $237.9 million of regulatory assets not earning a return, $35.3 million of regulatory assets earning a return based on short-term interest rates, and $123.5 million of regulatory assets earning a return based on long-term interest rates. The regulatory assets not earning a return primarily relate to certain environmental remediation costs, uncollectible expense, MERC's extraordinary natural gas costs, our invested capital tax rider, and unamortized loss on reacquired debt. The other regulatory assets in the table either earn a return at the applicable utility's weighted average cost of capital or the cash has not yet been expended, in which case the regulatory assets are offset by liabilities. (3) Primarily represents the unrecognized future pension and OPEB costs related to our defined benefit pension and OPEB plans. We are authorized recovery of these regulatory assets over the average remaining service life of each plan. (4) As of December 31, 2022, we had made cash expenditures of $111.1 million related to these environmental remediation costs. The remaining $499.6 million represents our estimated future cash expenditures. (5) This regulatory asset relates to WE's 2014 announcement to retire the PIPP. Despite WE's intent to retire the PIPP, MISO designated the PIPP as an SSR, which meant the PIPP's operation was necessary for reliability, and the plant could not be shut down until new generation or transmission facilities were built. In December 2014, the PSCW authorized escrow accounting for WE's SSR revenues because of the fluctuations in the actual revenues WE received under the PIPP SSR agreements. The rate order WE received from the PSCW in December 2019 authorized recovery of this SSR regulatory asset over a 15-year period that began on January 1, 2020. (6) Represents the extraordinary natural gas costs MERC incurred during February 2021 that are being recovered over 27 months, beginning in September 2021. See Note 26, Regulatory Environment, for more information on our recovery efforts associated with these costs. (7) Represents amounts recoverable from customers related to programs at the utilities designed to meet energy efficiency standards. |
Schedule of regulatory liabilities | The following regulatory liabilities were reflected on our balance sheets as of December 31: (in millions) 2022 2021 See Note Regulatory liabilities Income tax related items $ 1,956.6 $ 1,998.5 16 Removal costs (1) 1,260.9 1,248.0 Pension and OPEB benefits (2) 340.5 397.3 20 Derivatives 76.7 124.1 1(s) Energy costs refundable through rate adjustments 53.4 13.7 1(d) Uncollectible expense 24.0 37.1 5 Earnings sharing mechanisms 12.9 28.4 26 Electric transmission costs (3) 0.4 84.2 Other, net 66.5 29.0 Total regulatory liabilities $ 3,791.9 $ 3,960.3 Balance sheet presentation Other current liabilities $ 56.4 $ 14.3 Regulatory liabilities 3,735.5 3,946.0 Total regulatory liabilities $ 3,791.9 $ 3,960.3 (1) Represents amounts collected from customers to cover the future cost of property, plant, and equipment removals that are not legally required. Legal obligations related to the removal of property, plant, and equipment are recorded as AROs. See Note 9, Asset Retirement Obligations, for more information on our legal obligations. (2) Primarily represents the unrecognized future pension and OPEB benefits related to our defined benefit pension and OPEB plans. We will amortize these regulatory liabilities into net periodic benefit cost over the average remaining service life of each plan. (3) In accordance with the PSCW's approval of escrow accounting for ATC and MISO network transmission expenses for our Wisconsin electric utilities, WE and WPS defer as a regulatory asset or liability the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During 2022, WE and WPS amortized $81.0 million of their transmission regulatory liabilities to offset certain 2022 revenue deficiencies, as approved by the PSCW in order to forego filing for 2022 base rate increases. See Note 26, Regulatory Environment, for more information. |
Property, Plant, and Equipment
Property, Plant, and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment - Balances | Property, plant, and equipment consisted of the following at December 31: (in millions) 2022 2021 Electric – generation $ 5,480.5 $ 6,981.4 Electric – distribution 8,233.3 7,854.7 Natural gas – distribution, storage, and transmission 14,203.3 13,526.6 Property, plant, and equipment to be retired, net 1,085.6 277.0 Other 2,302.7 2,212.6 Less: Accumulated depreciation 8,416.2 8,894.9 Net 22,889.2 21,957.4 CWIP 972.1 406.0 Net utility and non-utility property, plant, and equipment 23,861.3 22,363.4 We Power generation 3,237.1 3,240.5 Renewable generation 2,537.1 1,837.5 Natural gas storage 292.2 289.9 Net non-utility energy infrastructure 6,066.4 5,367.9 Corporate services 163.0 188.7 Other 23.8 27.0 Less: Accumulated depreciation 1,082.3 994.4 Net 5,170.9 4,589.2 CWIP 81.6 29.8 Net other property, plant, and equipment 5,252.5 4,619.0 Total property, plant, and equipment $ 29,113.8 $ 26,982.4 |
Schedule of activity related to severance liability | Activity related to these severance liabilities for the years ended December 31 was as follows: (in millions) 2022 2021 2020 Severance liability at January 1 $ 4.9 $ 0.7 $ 2.1 Severance expense 11.3 4.6 — Severance payments — (0.4) (0.1) Other — — (1.3) Total severance liability at December 31 $ 16.2 $ 4.9 $ 0.7 |
Jointly Owned Utility Facilit_2
Jointly Owned Utility Facilities (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Jointly Owned Utility Plant, Net Ownership Amount [Abstract] | |
Schedule of jointly owned utility facilities | Information related to jointly owned utility facilities at December 31, 2022 was as follows: We Power WPS (in millions, except for percentages and MW) Elm Road Generating Station Units 1 and 2 Weston Unit 4 Columbia Energy Center Units 1 and 2 Forward Wind Two Creeks Badger Hollow I (2) Ownership 83.34 % 70.0 % 27.5 % 44.6 % 66.7 % 66.7 % Share of capacity (MW) (1) 1,060.8 387.3 311.1 61.5 100.0 100.0 In-service date 2010 and 2011 2008 1975 and 1978 2008 2020 2021 Property, plant, and equipment $ 2,425.1 $ 612.1 $ 426.1 $ 119.3 $ 136.8 $ 146.2 Accumulated depreciation $ (505.7) $ (213.0) $ (159.7) $ (53.9) $ (9.7) $ (4.9) CWIP $ 64.1 $ 1.2 $ 6.8 $ 0.2 $ 0.1 $ — (1) Capacity for our jointly-owned electric generation facilities, other than Forward Wind, Two Creeks, and Badger Hollow I, is based on rated capacity, which is the net power output under average operating conditions with equipment in an average state of repair as of a given month in a given year. Values are primarily based on the net dependable expected capacity ratings for summer 2023 established by tests and may change slightly from year to year. The summer period is the most relevant for capacity planning purposes. This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand. Capacity for Forward Wind is based on nameplate capacity, which is the amount of energy a turbine should produce at optimal wind speeds. Capacity for Two Creeks and Badger Hollow I is based on nameplate capacity, which is the maximum output that a generator should produce at continuous full power. (2) Commercial operation was achieved in November 2021 for Badger Hollow I. |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of changes to asset retirement obligations | The following table shows changes to our AROs during the years ended December 31: (in millions) 2022 2021 2020 Balance as of January 1 $ 462.0 $ 513.5 $ 483.5 Accretion 16.1 21.2 20.7 Additions and revisions to estimated cash flows 15.0 (1) (53.9) (2) 39.7 (3) Liabilities settled (13.8) (18.8) (30.4) Balance as of December 31 $ 479.3 $ 462.0 $ 513.5 (1) AROs increased $12.1 million in 2022, as a result of an ARO being recorded for the legal requirement to dismantle, at retirement, the Thunderhead non-utility wind generation project. Also in 2022, AROs increased $1.9 million due to revisions made to estimated cash flows primarily for changes in the cost to retire natural gas distribution mains and service pipes at PGL and NSG. (2) AROs decreased $152.0 million in 2021, due to revisions made to estimated cash flows primarily for changes in the cost to retire natural gas distribution lines at PGL and NSG. Also in 2021, AROs increased $50.7 million due to new natural gas distribution lines being placed into service at PGL and NSG. AROs increased by $26.3 million as a result of AROs being recorded for the legal requirement to dismantle, at retirement, the Badger Hollow I solar generation project and the Tatanka Ridge and Jayhawk non-utility wind generation projects. AROs increased $7.8 million due to revisions made to removal estimates for wind generation projects at WE and WPS. AROs increased $6.8 million due to revisions made to the removal estimates for fly ash landfills and ash ponds at WPS. (3) AROs increased $39.3 million in 2020, primarily due to new natural gas distribution lines being placed into service at PGL. Also in 2020, AROs increased by $8.5 million as a result of AROs being recorded for the legal requirement to dismantle, at retirement, the Two Creeks solar generation project. AROs decreased $9.2 million due to revisions made to estimated cash flows for the abatement of asbestos at WE. |
Goodwill and Intangibles (Table
Goodwill and Intangibles (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Schedule of changes to goodwill balances by segment | The table below shows our goodwill balances by segment at December 31, 2022. We had no changes to the carrying amount of goodwill during the years ended December 31, 2022 and 2021. (in millions) Wisconsin Illinois Other States Non-Utility Energy Infrastructure Total Goodwill balance (1) $ 2,104.3 $ 758.7 $ 183.2 $ 6.6 $ 3,052.8 (1) We had no accumulated impairment losses related to our goodwill as of December 31, 2022. |
Schedule of intangible liabilities obtained through acquisitions by WECI | The intangible liabilities below were all obtained through acquisitions by WECI and are classified as other long-term liabilities on our balance sheets. December 31, 2022 December 31, 2021 (in millions) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Gross Carrying Amount Accumulated Amortization Net Carrying Amount PPAs (1) $ 343.9 $ (16.9) $ 327.0 $ 87.9 $ (6.5) $ 81.4 Proxy revenue swap (2) 7.2 (2.8) 4.4 7.2 (2.1) 5.1 Interconnection agreements (3) 4.7 (0.7) 4.0 4.7 (0.5) 4.2 Total intangible liabilities $ 355.8 $ (20.4) $ 335.4 $ 99.8 $ (9.1) $ 90.7 (1) Represents PPAs related to the acquisition of Blooming Grove, Tatanka Ridge, Jayhawk, and Thunderhead expiring between 2030 and 2034. The weighted-average remaining useful life of the PPAs is 11 years. (2) Represents an agreement with a counterparty to swap the market revenue of Upstream's wind generation for fixed quarterly payments over 10 years, which expires in 2029. The remaining useful life of the proxy revenue swap is six years. (3) Represents interconnection agreements related to the acquisitions of Tatanka Ridge and Bishop Hill III, expiring in 2040 and 2041, respectively. These agreements relate to payments for connecting our facilities to the infrastructure of another utility to facilitate the movement of power onto the electric grid. The weighted-average remaining useful life of the interconnection agreements is 18 years. |
Schedule of amortization over the next five years | Amortization for the next five years is estimated to be: For the Years Ending December 31 (in millions) 2023 2024 2025 2026 2027 Amortization to be recorded as an increase to operating revenues $ 29.8 $ 29.8 $ 29.8 $ 29.8 $ 29.8 Amortization to be recorded as a decrease to other operation and maintenance 0.2 0.2 0.2 0.2 0.2 |
Common Equity (Tables)
Common Equity (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Stockholders' Equity Note [Abstract] | |
Schedule of stock-based compensation expense and related tax benefit recognized in income | The following table summarizes our pre-tax stock-based compensation expense and the related tax benefit recognized in income for the years ended December 31: (in millions) 2022 2021 2020 Stock options $ 6.5 $ 6.5 $ 6.0 Restricted stock 7.0 6.1 7.4 Performance units 21.3 3.1 22.3 Stock-based compensation expense $ 34.8 $ 15.7 $ 35.7 Related tax benefit $ 9.6 $ 4.3 $ 9.8 |
Schedule of stock option activity | The following is a summary of our stock option activity during 2022: Stock Options Number of Options Weighted-Average Exercise Price Weighted-Average Remaining Contractual Life (in years) Aggregate Intrinsic Value (in millions) Outstanding as of January 1, 2022 3,111,907 $ 69.84 Granted 437,269 $ 96.04 Exercised (622,459) $ 54.05 Forfeited (16,778) $ 92.16 Outstanding as of December 31, 2022 2,909,939 $ 77.03 6.2 $ 49.7 Exercisable as of December 31, 2022 1,807,644 $ 67.40 5.0 $ 47.8 |
Schedule of restricted stock activity | The following restricted stock activity occurred during 2022: Restricted Shares Number of Shares Weighted-Average Grant Date Fair Value Outstanding and unvested as of January 1, 2022 99,061 $ 88.89 Granted 72,211 $ 96.04 Released (76,109) $ 88.51 Forfeited (5,278) $ 92.80 Outstanding and unvested as of December 31, 2022 89,885 $ 94.73 |
Schedule of shares purchased to fulfill exercised stock options and restricted stock awards | The following is a summary of shares purchased to fulfill exercised stock options and restricted stock awards during the years ended December 31: (in millions) 2022 2021 2020 Shares purchased 0.7 0.4 1.0 Cost of shares purchased $ 69.2 $ 33.1 $ 99.2 |
Schedule of common stock dividends declared | During the year ended December 31, 2022, our Board of Directors declared common stock dividends which are summarized below: Date Declared Date Payable Per Share Period January 20, 2022 March 1, 2022 $0.7275 First quarter April 21, 2022 June 1, 2022 $0.7275 Second quarter July 21, 2022 September 1, 2022 $0.7275 Third quarter October 20, 2022 December 1, 2022 $0.7275 Fourth quarter |
Preferred Stock (Tables)
Preferred Stock (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Class of Stock Disclosures [Abstract] | |
Schedule of preferred stock by class | The following table shows preferred stock authorized and outstanding at December 31, 2022 and 2021: (in millions, except share and per share amounts) Shares Authorized Shares Outstanding Redemption Price Per Share Total WEC Energy Group $0.01 par value Preferred Stock 15,000,000 — — $ — WE $100 par value, Six Per Cent. Preferred Stock 45,000 44,498 — 4.4 $100 par value, Serial Preferred Stock 3.60% Series 2,286,500 260,000 $ 101 26.0 $25 par value, Serial Preferred Stock 5,000,000 — — — WPS $100 par value, Preferred Stock 1,000,000 — — — PGL $100 par value, Cumulative Preferred Stock 430,000 — — — NSG $100 par value, Cumulative Preferred Stock 160,000 — — — Total $ 30.4 |
Short-Term Debt and Lines of _2
Short-Term Debt and Lines of Credit (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Short-Term Debt [Abstract] | |
Short-term debt balances and their corresponding weighted-average interest rates | The following table shows our short-term borrowings and their corresponding weighted-average interest rates as of December 31: (in millions, except percentages) 2022 2021 Commercial paper Amount outstanding at December 31 $ 1,643.5 $ 1,896.1 Average interest rate on amounts outstanding at December 31 4.64 % 0.26 % Operating expense loans Amount outstanding at December 31 (1) $ 3.6 $ 0.9 (1) Coyote Ridge, Tatanka Ridge, and Jayhawk entered into operating expense loans. In accordance with their limited liability company operating agreements, they r eceived loans from the holders of their noncontrolling interests in proportion to their ownership interests. |
Schedule of revolving credit facilities | The information in the table below relates to our revolving credit facilities used to support our commercial paper borrowing programs, including remaining available capacity under these facilities as of December 31: (in millions) Maturity 2022 Revolving credit facility (WEC Energy Group) September 2026 $ 1,500.0 Revolving credit facility (WE) September 2026 500.0 Revolving credit facility (WPS) September 2026 400.0 Revolving credit facility (WG) September 2026 350.0 Revolving credit facility (PGL) September 2026 350.0 Total short-term credit capacity $ 3,100.0 Less: Letters of credit issued inside credit facilities $ 2.3 Commercial paper outstanding 1,643.5 Available capacity under existing facilities $ 1,454.2 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Debt Disclosure [Abstract] | |
Schedule of long-term debt instruments | The following table is a summary of our long-term debt outstanding (excluding finance leases) as of December 31: 2022 2021 (in millions) Maturity Date Weighted Average Interest Rate Balance Weighted Average Interest Rate Balance WEC Energy Group Senior Notes (unsecured) (1) 2023-2033 2.44 % $ 3,970.0 1.67 % $ 3,070.0 WEC Energy Group Junior Notes (unsecured) (1) (2) 2067 6.72 % 500.0 2.27 % 500.0 WE Debentures (unsecured) 2024-2095 4.22 % 3,285.0 4.13 % 2,785.0 WEPCo Environmental Trust (secured, nonrecourse) (6) (10) 2023-2035 1.58 % 105.9 1.58 % 114.7 WPS Senior Notes (unsecured) 2025-2051 4.11 % 1,975.0 3.89 % 1,675.0 WG Debentures (unsecured) 2024-2046 3.35 % 790.0 3.35 % 790.0 Integrys Junior Notes (unsecured) (3) 2073 6.00 % 221.4 6.00 % 221.4 PGL First and Refunding Mortgage Bonds (secured) (4) 2024-2047 3.41 % 1,970.0 3.31 % 1,870.0 NSG First Mortgage Bonds (secured) (5) 2027-2043 3.56 % 157.0 3.56 % 157.0 MERC Senior Notes (unsecured) 2025-2047 3.04 % 210.0 3.04 % 210.0 MGU Senior Notes (unsecured) 2025-2047 3.18 % 150.0 3.18 % 150.0 UMERC Senior Notes (unsecured) 2029 3.26 % 160.0 3.26 % 160.0 Bluewater Gas Storage Senior Notes (unsecured) (6) 2023-2047 3.76 % 112.6 3.76 % 115.2 ATC Holding Senior Notes (unsecured) 2025-2030 4.05 % 475.0 4.05 % 475.0 We Power Subsidiaries Notes (secured, nonrecourse) (6) (7) 2023-2041 5.62 % 896.5 5.60 % 934.7 WECC Notes (unsecured) 2028 6.94 % 50.0 6.94 % 50.0 WECI Wind Holding I Senior Notes (secured, nonrecourse) (6) (8) 2023-2032 2.75 % 332.1 2.75 % 374.6 WECI Wind Holding II Senior Notes (secured, nonrecourse) (6) (9) 2023 - 2031 6.38 % 199.3 — % — Total 15,559.8 13,652.6 Integrys acquisition fair value adjustment 1.2 2.9 Jayhawk acquisition 7.3 7.3 Unamortized debt issuance costs (81.8) (77.7) Unamortized discount, net and other (22.3) (21.7) Total long-term debt, including current portion (11) 15,464.2 13,563.4 Current portion of long-term debt (808.5) (91.0) Total long-term debt $ 14,655.7 $ 13,472.4 (1) In connection with our outstanding 2007 Junior Notes, we executed an RCC, which we amended on June 29, 2015, for the benefit of persons that buy, hold, or sell a specified series of our long-term indebtedness (covered debt). Our 6.20% Senior Notes due April 1, 2033 have been designated as the covered debt under the RCC. The RCC provides that we may not redeem, defease, or purchase, and that our subsidiaries may not purchase, any 2007 Junior Notes on or before May 15, 2037, unless, subject to certain limitations described in the RCC, we have received a specified amount of proceeds from the sale of qualifying securities. (2) Variable interest rate reset quarterly. The rates were 6.72% and 2.27% as of December 31, 2022 and 2021, respectively. Until their expiration on November 15, 2021, we had two interest rate swaps with a combined notional value of $250.0 million. The swaps provided a fixed interest rate of 4.9765% on $250.0 million of the outstanding notes. See Note 18, Derivative Instruments, for more information on the two interest rate swaps. (3) The terms of Integrys's 2013 6.00% Junior Notes, due August 1, 2073, provide that, effective August 2023, they will bear interest at a variable rate, which we expect to based off of SOFR, and will reset quarterly. (4) PGL's First Mortgage Bonds are subject to the terms and conditions of PGL's First Mortgage Indenture dated January 2, 1926, as supplemented. Under the terms of the Indenture, substantially all property owned by PGL is pledged as collateral for these outstanding debt securities. PGL has used certain First Mortgage Bonds to secure tax exempt interest rates. The Illinois Finance Authority has issued Tax Exempt Bonds, and the proceeds from the sale of these bonds were loaned to PGL. In return, PGL issued $100 million of collateralized First Mortgage Bonds. (5) NSG's First Mortgage Bonds are subject to the terms and conditions of NSG's First Mortgage Indenture dated April 1, 1955, as supplemented. Under the terms of the Indenture, substantially all property owned by NSG is pledged as collateral for these outstanding debt securities. (6) The long-term debt of Bluewater, WECI Wind Holding I, WECI Wind Holding II, WEPCo Environmental Trust, and We Power's subsidiaries requires periodic principal payments. (7) We Power's subsidiaries' senior notes are secured by a collateral assignment of the leases between We Power's subsidiaries and WE related to PWGS and ERGS, as applicable. (8) WECI Wind Holding I's Senior Notes are secured by a first priority security interest in the ownership interest of its subsidiaries as well as a pledge of equity in WECI Wind Holding I. (9) WECI Wind Holding II's Senior Notes are secured by a first priority security interest in the ownership interest of its subsidiaries as well as a pledge of equity in WECI Wind Holding II. (10) WEPCo Environmental Trust’s ETBs are secured by a pledge of and lien on environmental control property, which includes the right to impose, collect and receive a non-bypassable environmental control charge paid by all of WE's retail electric distribution customers, the right to obtain true-up adjustments of the environmental control charges, and all revenues or other proceeds arising from those rights and interests. See Note 23, Variable Interest Entities, for more information. |
Schedule of current maturities of long-term debt | The following table shows the long-term debt securities (excluding finance leases) maturing within one year of December 31, 2022: (in millions) Interest Rate Maturity Date (1) Principal Amount WEC Energy Group Senior Notes (unsecured) 0.55% September $ 700.0 WEPCo Environmental Trust (secured, nonrecourse) 1.58% Semi-annually 8.9 Bluewater Gas Storage Senior Notes (unsecured) 3.76% Semi-annually 2.8 We Power Subsidiaries Notes – PWGS (secured, nonrecourse) 4.91% Monthly 7.6 We Power Subsidiaries Notes – ERGS (secured, nonrecourse) 5.209% Semi-annually 14.7 We Power Subsidiaries Notes – ERGS (secured, nonrecourse) 4.673% Semi-annually 11.1 We Power Subsidiaries Notes – PWGS (secured, nonrecourse) 6.00% Monthly 6.6 WECI Wind Holding I Senior Notes (secured, nonrecourse) 2.75% Semi-annually 42.0 WECI Wind Holding II Senior Notes (secured, nonrecourse) 6.38% Semi-annually 14.8 Total $ 808.5 (1) Maturity dates listed as semi-annually and monthly are associated with debt that requires periodic principal payments. |
Schedule of future maturities of long-term debt | The following table shows the future maturities of our long-term debt outstanding (excluding obligations under finance leases) as of December 31, 2022: (in millions) Payments 2023 $ 808.5 2024 1,239.6 2025 1,685.5 2026 126.8 2027 1,230.7 Thereafter 10,468.7 Total $ 15,559.8 |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Leases [Abstract] | |
Schedule of lease expense and supplemental cash flow information for leases | The components of lease expense and supplemental cash flow information related to our leases for the years ended December 31 are as follows: (in millions) 2022 2021 2020 Finance lease expense Amortization of right of use assets (1) $ 6.0 $ 8.1 $ 6.3 Interest on lease liabilities (2) 0.9 1.6 2.5 Operating lease expense (3) 6.1 3.4 5.4 Short-term lease expense (3) 0.9 0.2 0.3 Total lease expense $ 13.9 $ 13.3 $ 14.5 Other information Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from finance leases $ 0.9 $ 1.6 $ 2.5 Operating cash flows from operating leases $ 5.7 $ 5.3 $ 6.7 Financing cash flows from finance leases $ 6.0 $ 8.1 $ 6.3 Non-cash activities: Right of use assets obtained in exchange for finance lease liabilities $ 57.6 $ 73.6 $ 22.8 Right of use assets obtained in exchange for operating lease liabilities $ — $ 0.5 $ — Weighted-average remaining lease term – finance leases 30.0 years 20.5 years 41.5 years Weighted-average remaining lease term – operating leases 12.0 years 12.5 years 13.0 years Weighted-average discount rate – finance lease (4) 3.9 % 2.4 % 4.9 % Weighted average discount rate – operating leases (4) 3.4 % 3.4 % 3.4 % (1) Amortization of right of use assets was included as a component of depreciation and amortization expense. (2) Interest on lease liabilities was included as a component of interest expense. (3) Operating and short-term lease expense were included as a component of operation and maintenance expense. |
Schedule of finance and operating lease right of use assets and obligations | The following table summarizes our finance and operating lease right of use assets and obligations at December 31: (in millions) 2022 2021 Balance Sheet Location Right of use assets Operating lease right of use assets, net $ 15.7 $ 19.5 Other long-term assets Finance lease right of use assets, net Power purchase commitment $ 71.8 $ 76.7 Land leases – utility solar generation $ 102.4 $ 47.0 Other $ 1.1 $ 0.3 Total finance lease right of use assets, net (1) $ 175.3 $ 124.0 Property, plant, and equipment, net Lease obligations Current operating lease liabilities $ 4.0 $ 3.7 Other current liabilities Long-term operating lease liabilities $ 25.4 $ 29.1 Other long-term liabilities Current finance lease liabilities Power purchase commitment $ 72.7 $ 78.4 Current portion of long-term debt Long-term finance lease liabilities Land leases – utility solar generation $ 109.3 $ 51.0 Other $ 1.2 $ 0.3 Total long-term finance lease liabilities $ 110.5 $ 51.3 Long-term debt (1) Amounts are net of accumulated amortization of $146.3 million and $139.7 million at December 31, 2022 and 2021, respectively. |
Schedule of future minimum lease payments for operating and finance leases | Future minimum lease payments under our operating and finance leases and the present value of our net minimum lease payments as of December 31, 2022, were as follows: (in millions) Total Operating Leases Power Purchase Commitment Land Leases - Utility Solar Generation Other Total Finance Leases 2023 $ 4.9 $ 72.7 $ 3.6 $ — $ 76.3 2024 4.3 — 3.9 0.1 4.0 2025 3.8 — 4.0 0.1 4.1 2026 3.9 — 4.0 0.1 4.1 2027 4.0 — 4.1 0.1 4.2 Thereafter 16.6 — 304.1 2.7 306.8 Total minimum lease payments 37.5 72.7 323.7 3.1 399.5 Less: Interest (8.1) — (214.4) (1.9) (216.3) Present value of minimum lease payments 29.4 72.7 109.3 1.2 183.2 Less: Short-term lease liabilities (4.0) (72.7) — — (72.7) Long-term lease liabilities $ 25.4 $ — $ 109.3 $ 1.2 $ 110.5 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Income Tax Disclosure [Abstract] | |
Summary of Income Tax Expense | The following table is a summary of income tax expense for the years ended December 31: (in millions) 2022 2021 2020 Current tax expense $ 50.2 $ 93.9 $ 49.2 Deferred income taxes, net 278.5 111.0 182.2 ITCs (5.8) (4.6) (3.5) Total income tax expense $ 322.9 $ 200.3 $ 227.9 |
Statutory rate reconciliation | The provision for income taxes for each of the years ended December 31 differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes as a result of the following: 2022 2021 2020 Effective Effective Effective (in millions) Amount Tax Rate Amount Tax Rate Amount Tax Rate Statutory federal income tax $ 363.5 21.0 % $ 315.1 21.0 % $ 299.9 21.0 % State income taxes net of federal tax benefit 109.7 6.3 % 96.1 6.4 % 90.5 6.3 % Wind PTCs (107.6) (6.2) % (81.3) (5.4) % (51.5) (3.6) % Federal excess deferred tax amortization (1) (36.9) (2.1) % (37.3) (2.5) % (36.7) (2.6) % AFUDC – Equity (6.2) (0.4) % (3.8) (0.3) % (4.4) (0.3) % ITC restored (5.8) (0.3) % (4.6) (0.3) % (3.5) (0.2) % Federal excess deferred tax amortization – Wisconsin unprotected (2) (0.8) — % (77.9) (5.2) % (57.6) (4.0) % Other, net 7.0 0.3 % (6.0) (0.3) % (8.8) (0.7) % Total income tax expense $ 322.9 18.6 % $ 200.3 13.4 % $ 227.9 15.9 % (1) The Tax Legislation required our regulated utilities to remeasure their deferred income taxes and we began to amortize the resulting excess protected deferred income taxes beginning in 2018 in accordance with normalization requirements. The decrease in income tax expense related to the amortization of the deferred tax benefits is offset by a decrease in revenue as the benefits are returned to customers, resulting in no impact on net income. (2) In accordance with the rate order received from the PSCW in December 2019, our Wisconsin utilities are amortizing these unprotected deferred tax benefits over periods ranging from two years to four years, to reduce near-term rate impacts to their customers. The decrease in income tax expense related to the amortization of the deferred tax benefits is offset by a decrease in revenue as the benefits are returned to customers, resulting in no impact on net income. |
Components of deferred income taxes | The components of deferred income taxes as of December 31 were as follows: (in millions) 2022 2021 Deferred tax assets Tax gross up – regulatory items $ 459.0 $ 469.5 Future tax benefits 187.7 104.6 Deferred revenues 86.8 97.8 Other 190.2 205.9 Total deferred tax assets 923.7 877.8 Valuation allowance (1.2) (1.2) Net deferred tax assets $ 922.5 $ 876.6 Deferred tax liabilities Property-related $ 4,072.5 $ 3,909.0 Investment in affiliates 839.7 648.6 Employee benefits and compensation 219.5 170.6 Deferred costs – plant retirements 212.8 223.9 Other 203.6 233.0 Total deferred tax liabilities 5,548.1 5,185.1 Deferred tax liability, net $ 4,625.6 $ 4,308.5 |
Components of deferred tax assets associated with federal and state tax benefit carryforwards | The components of net deferred tax assets associated with federal and state tax benefit carryforwards as of December 31, 2022 and 2021 are summarized in the tables below: 2022 (in millions) Gross Value Deferred Tax Effect Valuation Allowance Earliest Year of Expiration Future tax benefits as of December 31, 2022 Federal tax credit $ — $ 176.4 $ — 2041 State net operating loss 72.6 4.5 (1.2) 2032 Other state benefits — 6.8 — 2023 Balance as of December 31, 2022 $ 72.6 $ 187.7 $ (1.2) 2021 (in millions) Gross Value Deferred Tax Effect Valuation Allowance Earliest Year of Expiration Future tax benefits as of December 31, 2021 Federal tax credit $ — $ 91.5 $ — 2041 State net operating loss 72.0 4.4 (1.2) 2031 Other state benefits — 8.7 — 2023 Balance as of December 31, 2021 $ 72.0 $ 104.6 $ (1.2) |
Schedule of unrecognized tax benefits roll forward | A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows: (in millions) 2022 2021 2020 Balance as of January 1 $ 6.8 $ 11.9 $ 17.9 Additions for tax positions of prior years 0.3 — 1.6 Additions based on tax positions related to the current year 0.4 1.6 0.1 Reductions for tax positions of prior years (1.2) (6.7) (7.7) Balance as of December 31 $ 6.3 $ 6.8 $ 11.9 |
Roll forward of interest accrued on unrecognized tax benefits | Interest accrued related to unrecognized tax benefits is as follows: (in millions) 2022 2021 2020 Balance as of January 1 $ 0.1 $ 0.5 $ 0.8 Interest expense (income) related to unrecognized tax benefits 0.4 (0.4) (0.3) Balance as of December 31 $ 0.5 $ 0.1 $ 0.5 |
Summary of income tax examinations | As of December 31, 2022, with a few exceptions, we were subject to examination by federal and state or local tax authorities for the 2017 through 2022 tax years in our major operating jurisdictions as follows: Jurisdiction Years Federal 2019–2022 Illinois 2017–2022 Michigan 2018–2022 Minnesota 2018–2022 Wisconsin 2018–2022 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Fair Value Disclosures [Abstract] | |
Schedule of fair value of assets and liabilities measured on a recurring basis categorized by level within the fair value hierarchy | The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy: December 31, 2022 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 16.3 $ 16.2 $ — $ 32.5 FTRs — — 7.8 7.8 Coal contracts — 34.5 — 34.5 Total derivative assets $ 16.3 $ 50.7 $ 7.8 $ 74.8 Investments held in rabbi trust $ 50.9 $ — $ — $ 50.9 Derivative liabilities Natural gas contracts $ 81.4 $ 15.2 $ — $ 96.6 December 31, 2021 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 46.4 $ 18.2 $ — $ 64.6 FTRs — — 2.4 2.4 Coal contracts — 53.0 — 53.0 Total derivative assets $ 46.4 $ 71.2 $ 2.4 $ 120.0 Investments held in rabbi trust $ 79.6 $ — $ — $ 79.6 Derivative liabilities Natural gas contracts $ 8.4 $ 6.7 $ — $ 15.1 |
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 at December 31: (in millions) 2022 2021 2020 Balance at the beginning of the period $ 2.4 $ 2.4 $ 3.1 Purchases 23.7 6.1 7.6 Realized and unrealized gains included in earnings (1) 0.5 — — Settlements (18.8) (6.1) (8.3) Balance at the end of the period $ 7.8 $ 2.4 $ 2.4 Losses included in earnings attributable to the change in unrealized losses of Level 3 derivatives held at the end of the reporting period (1) $ (0.4) $ — $ — (1) Amounts relate to FTRs and TCRs acquired by certain wind generating facilities included in our non-utility energy infrastructure segment. These realized and unrealized gains and losses are recorded in operating revenues on our income statements. |
Schedule of carrying value and estimated fair value of financial instruments not recorded at fair value | The following table shows the financial instruments included on our balance sheets that are not recorded at fair value at December 31: 2022 2021 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock of subsidiary $ 30.4 $ 22.7 $ 30.4 $ 30.3 Long-term debt, including current portion (1) 15,464.2 13,921.3 13,563.4 14,819.4 (1) The carrying amount of long-term debt excludes finance lease obligations of $183.2 million and $129.7 million at December 31, 2022 and 2021, respectively. |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of derivative assets and liabilities | None of the derivatives shown below were designated as hedging instruments. December 31, 2022 December 31, 2021 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Current Natural gas contracts $ 32.5 $ 88.2 $ 60.6 $ 14.0 FTRs 7.8 — 2.4 — Coal contracts 18.9 — 44.0 — Total current 59.2 88.2 107.0 14.0 Long-term Natural gas contracts — 8.4 4.0 1.1 Coal contracts 15.6 — 9.0 — Total long-term 15.6 8.4 13.0 1.1 Total $ 74.8 $ 96.6 $ 120.0 $ 15.1 |
Schedule of estimated notional sales volumes and realized gains (losses) | Our estimated notional sales volumes and realized gains and losses were as follows for the years ended: December 31, 2022 December 31, 2021 December 31, 2020 (in millions) Volumes Gains Volumes Gains Volumes Gains (Losses) Natural gas contracts 183.3 Dth $ 299.5 197.6 Dth $ 136.5 188.6 Dth $ (54.1) FTRs and TCRs 27.2 MWh 11.8 28.2 MWh 17.7 29.8 MWh 4.1 Total $ 311.3 $ 154.2 $ (50.0) |
Schedule of net derivative instruments | The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets: December 31, 2022 December 31, 2021 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 74.8 $ 96.6 $ 120.0 $ 15.1 Gross amount not offset on the balance sheet (17.5) (82.5) (1) (15.2) (2) (9.2) (3) Net amount $ 57.3 $ 14.1 $ 104.8 $ 5.9 (1) Includes cash collateral posted of $65.0 million. (2) Includes cash collateral received of $6.4 million. (3) Includes cash collateral posted of $0.4 million. |
Schedule of cash flow hedges recorded in other comprehensive income (loss) and earnings | The table below shows the amounts related to these cash flow hedges recorded in other comprehensive income (loss) and in earnings, along with our total interest expense on the income statements, for the years ended December 31: (in millions) 2022 2021 2020 Derivative gain (loss) recognized in other comprehensive income / loss $ — $ 0.8 $ (5.9) Net derivative gain (loss) reclassified from accumulated other comprehensive loss to interest expense 0.4 (1.3) (2.1) Total interest expense line item on the income statements 515.1 471.1 493.7 |
Guarantees (Tables)
Guarantees (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Guarantees [Abstract] | |
Schedule of outstanding guarantees | The following table shows our outstanding guarantees: Total Amounts Committed at December 31, 2022 Expiration (in millions) Less Than 1 Year 1 to 3 Years Over 3 Years Standby letters of credit (1) $ 115.7 $ 8.0 $ 0.2 $ 107.5 Surety bonds (2) 34.0 33.9 0.1 — Other guarantees (3) 9.4 — — 9.4 Total guarantees $ 159.1 $ 41.9 $ 0.3 $ 116.9 (1) At our request or the request of our subsidiaries, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to our subsidiaries. These amounts are not reflected on our balance sheets. (2) Primarily for environmental remediation, workers compensation self-insurance programs, and obtaining various licenses, permits, and rights-of-way. These amounts are not reflected on our balance sheets. (3) Related to workers compensation coverage for which a liability was recorded on our balance sheets. |
Employee Benefits (Tables)
Employee Benefits (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Retirement Benefits [Abstract] | |
Reconciliation of the changes in the plans' benefit obligations and fair value of assets | The following tables provide a reconciliation of the changes in our plans' benefit obligations and fair value of assets: Pension Benefits OPEB Benefits (in millions) 2022 2021 2022 2021 Change in benefit obligation Obligation at January 1 $ 3,136.6 $ 3,346.4 $ 530.2 $ 556.1 Service cost 50.8 54.3 14.3 15.7 Interest cost 91.8 87.5 15.4 14.5 Participant contributions — — 12.5 12.5 Plan amendments — — 0.2 (3.9) Actuarial gain (682.3) (101.3) (127.9) (20.3) Benefit payments (281.0) (250.3) (45.7) (47.5) Federal subsidy on benefits paid N/A N/A 1.4 1.2 Transfer — — 1.9 1.9 Obligation at December 31 $ 2,315.9 $ 3,136.6 $ 402.3 $ 530.2 Change in fair value of plan assets Fair value at January 1 $ 3,328.9 $ 3,225.0 $ 1,000.2 $ 951.4 Actual return on plan assets (431.3) 291.8 (135.4) 79.9 Employer contributions 11.4 62.4 3.7 3.9 Participant contributions — — 12.5 12.5 Benefit payments (281.0) (250.3) (45.7) (47.5) Fair value at December 31 $ 2,628.0 $ 3,328.9 $ 835.3 $ 1,000.2 Funded status at December 31 $ 312.1 $ 192.3 $ 433.0 $ 470.0 |
Amounts recognized on the balance sheets at December 31 related to the funded status of the benefit plans | The amounts recognized on our balance sheets at December 31 related to the funded status of the benefit plans were as follows: Pension Benefits OPEB Benefits (in millions) 2022 2021 2022 2021 Pension and OPEB assets $ 470.6 $ 389.0 $ 446.1 $ 492.3 Pension and OPEB obligations 158.5 196.7 13.1 22.3 Total net assets $ 312.1 $ 192.3 $ 433.0 $ 470.0 |
Defined Benefit Plan Disclosure [Line Items] | |
Amounts that had not yet been recognized in the entity's net periodic benefit cost | The following table shows the amounts that had not yet been recognized in our net periodic benefit cost (credit) as of December 31: Pension Benefits OPEB Benefits (in millions) 2022 2021 2022 2021 Pre-tax accumulated other comprehensive income (loss) (1) Net actuarial loss (gain) $ 12.2 $ 7.5 $ (1.6) $ (1.4) Prior service credits — — — (0.1) Total $ 12.2 $ 7.5 $ (1.6) $ (1.5) Net regulatory assets (liabilities) (2) Net actuarial loss (gain) $ 669.2 $ 798.6 $ (200.8) $ (300.1) Prior service credits (2.1) (0.5) (44.2) (60.3) Total $ 667.1 $ 798.1 $ (245.0) $ (360.4) (1) Amounts related to the nonregulated entities are included in accumulated other comprehensive loss. (2) Amounts related to the utilities and WBS are recorded as net regulatory assets or liabilities. |
Schedule of the components of net periodic benefit cost | The components of net periodic benefit cost (credit) (including amounts capitalized to our balance sheets) for the years ended December 31 were as follows: Pension Benefits OPEB Benefits (in millions) 2022 2021 2020 2022 2021 2020 Service cost $ 50.8 $ 54.3 $ 50.1 $ 14.3 $ 15.7 $ 15.2 Interest cost 91.8 87.5 102.8 15.4 14.5 18.6 Expected return on plan assets (208.0) (200.9) (190.3) (68.9) (66.0) (60.3) Plan settlement 6.2 3.9 17.9 — — — Plan curtailment — — — — (6.4) — Amortization of prior service cost (credit) 1.6 1.6 1.6 (15.9) (15.9) (15.0) Amortization of net actuarial loss (gain) 75.3 109.4 102.6 (24.7) (24.4) (22.4) Net periodic benefit cost (credit) $ 17.7 $ 55.8 $ 84.7 $ (79.8) $ (82.5) $ (63.9) |
Weighted-average assumptions used to determine benefit obligations and net periodic benefit cost for the plans | The weighted-average assumptions used to determine the benefit obligations for the plans were as follows for the years ended December 31: Pension Benefits OPEB Benefits 2022 2021 2022 2021 Discount rate 5.49% 2.96% 5.50% 2.92% Rate of compensation increase 4.00% 4.00% N/A N/A Interest credit rate 4.61% 3.73% N/A N/A Assumed medical cost trend rate (Pre 65) N/A N/A 6.50% 5.70% Ultimate trend rate (Pre 65) N/A N/A 5.00% 5.00% Year ultimate trend rate is reached (Pre 65) N/A N/A 2031 2028 Assumed medical cost trend rate (Post 65) N/A N/A 6.00% 5.67% Ultimate trend rate (Post 65) N/A N/A 5.00% 5.00% Year ultimate trend rate is reached (Post 65) N/A N/A 2031 2028 The weighted-average assumptions used to determine the net periodic benefit cost for the plans were as follows for the years ended December 31: Pension Benefits 2022 2021 2020 Discount rate 3.18% 2.71% 3.34% Expected return on plan assets 6.88% 6.88% 6.87% Rate of compensation increase 4.00% 4.00% 4.00% Interest credit rate 3.78% 3.71% 3.70% OPEB Benefits 2022 2021 2020 Discount rate 2.92% 2.66% 3.39% Expected return on plan assets 7.00% 7.00% 7.00% Assumed medical cost trend rate (Pre 65) 5.70% 5.85% 6.00% Ultimate trend rate (Pre 65) 5.00% 5.00% 5.00% Year ultimate trend rate is reached (Pre 65) 2028 2028 2028 Assumed medical cost trend rate (Post 65) 5.67% 5.80% 5.91% Ultimate trend rate (Post 65) 5.00% 5.00% 5.00% Year ultimate trend rate is reached (Post 65) 2028 2028 2028 |
Investments recorded at fair value, by asset class | The following tables provide the fair values of our investments by asset class: December 31, 2022 Pension Plan Assets OPEB Assets (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Asset Class Equity securities: United States equity $ 231.5 $ — $ — $ 231.5 $ 92.5 $ — $ — $ 92.5 International equity 202.2 — — 202.2 83.9 — — 83.9 Fixed income securities: (1) United States bonds — 838.7 — 838.7 129.8 145.3 — 275.1 International bonds — 95.0 — 95.0 — 13.2 — 13.2 433.7 933.7 — 1,367.4 306.2 158.5 — 464.7 Investments measured at net asset value: Equity securities 466.0 186.6 Fixed income securities 101.0 65.5 Other 693.6 118.5 Total $ 2,628.0 $ 835.3 (1) This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries. December 31, 2021 Pension Plan Assets OPEB Assets (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Asset Class Equity securities: United States equity $ 417.1 $ — $ — $ 417.1 $ 135.4 $ — $ — $ 135.4 International equity 313.7 — — 313.7 109.1 — — 109.1 Fixed income securities: (1) United States bonds — 1,068.7 — 1,068.7 165.0 192.3 — 357.3 International bonds — 118.5 — 118.5 — 15.6 — 15.6 730.8 1,187.2 — 1,918.0 409.5 207.9 — 617.4 Investments measured at net asset value: Equity securities 659.2 224.5 Fixed income securities 127.7 112.3 Other 624.0 46.0 Total $ 3,328.9 $ 1,000.2 (1) This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries. |
Schedule of expected future benefit payments | The following table shows the payments, reflecting expected future service, that we expect to make for pension and OPEB over the next 10 years: (in millions) Pension Benefits OPEB Benefits 2023 $ 209.6 $ 34.5 2024 207.2 34.3 2025 200.1 34.2 2026 202.1 34.3 2027 193.5 34.4 2028-2032 866.5 168.0 |
Pension Benefits | |
Defined Benefit Plan Disclosure [Line Items] | |
Information for pension or OPEB plans with an accumulated benefit obligation in excess of plan assets | The following table shows information for pension plans with an accumulated benefit obligation in excess of plan assets. Amounts presented are as of December 31: (in millions) 2022 2021 Accumulated benefit obligation $ 185.7 $ 372.4 Fair value of plan assets 32.8 186.3 |
Information for pension plans with a projected benefit obligation in excess of plan assets | The following table shows information for pension plans with a projected benefit obligation in excess of plan assets. Amounts presented are as of December 31: (in millions) 2022 2021 Projected benefit obligation $ 191.3 $ 383.0 Fair value of plan assets 32.8 186.3 |
OPEB Benefits | |
Defined Benefit Plan Disclosure [Line Items] | |
Information for pension or OPEB plans with an accumulated benefit obligation in excess of plan assets | The following table shows information for OPEB plans with an accumulated benefit obligation in excess of plan assets. Amounts presented are as of December 31: (in millions) 2022 2021 Accumulated benefit obligation $ 20.6 $ 25.1 Fair value of plan assets 7.4 2.8 |
Investment in Transmission Af_2
Investment in Transmission Affiliates (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Schedule of changes to our investments in ATC and ATC Holdco | The following tables provide a reconciliation of the changes in our investments in ATC and ATC Holdco: 2022 (in millions) ATC ATC Holdco Total Balance at January 1 $ 1,766.9 $ 22.5 $ 1,789.4 Add: Earnings from equity method investment 192.6 2.1 194.7 Add: Capital contributions 45.5 — 45.5 Less: Distributions 120.4 — 120.4 Balance at December 31 $ 1,884.6 $ 24.6 $ 1,909.2 2021 (in millions) ATC ATC Holdco Total Balance at January 1 $ 1,733.5 $ 30.8 $ 1,764.3 Add: Earnings (loss) from equity method investment 166.4 (8.3) 158.1 Less: Distributions 133.0 — 133.0 Balance at December 31 $ 1,766.9 $ 22.5 $ 1,789.4 2020 (in millions) ATC ATC Holdco Total Balance at January 1 $ 1,684.7 $ 36.1 $ 1,720.8 Add: Earnings from equity method investment 174.3 1.5 175.8 Add: Capital contributions 21.2 — 21.2 Less: Distributions 146.7 — 146.7 Less: Return of capital — 6.8 6.8 Balance at December 31 $ 1,733.5 $ 30.8 $ 1,764.3 |
Schedule of significant related party transactions with ATC | The following table summarizes our significant related party transactions with ATC during the years ended December 31: (in millions) 2022 2021 2020 Charges to ATC for services and construction $ 18.9 $ 22.9 $ 27.5 Charges from ATC for network transmission services 363.7 361.0 350.5 Net refund (payment) from (to) ATC related to FERC ROE orders (0.1) 7.3 10.7 |
Schedule of receivables and payables with ATC | As of December 31, 2022 and 2021, our balance sheets included the following receivables and payables for services provided to or received from ATC: (in millions) 2022 2021 Accounts receivable for services provided to ATC $ 1.2 $ 2.0 Accounts payable for services received from ATC 30.4 30.2 Amounts due from ATC for transmission infrastructure upgrades (1) 26.6 13.0 |
Schedule of summarized income statement data for ATC | Summarized financial data for ATC is included in the tables below: Year Ended December 31 (in millions) 2022 2021 2020 Income statement data Operating revenues $ 751.2 $ 754.8 $ 758.1 Operating expenses 381.5 376.2 372.5 Other expense, net 123.0 113.9 110.8 Net income $ 246.7 $ 264.7 $ 274.8 |
Schedule of summarized balance sheet data for ATC | (in millions) December 31, 2022 December 31, 2021 Balance sheet data Current assets $ 89.6 $ 89.8 Noncurrent assets 5,997.8 5,628.1 Total assets $ 6,087.4 $ 5,717.9 Current liabilities $ 511.9 $ 436.9 Long-term debt 2,613.0 2,513.0 Other noncurrent liabilities 485.8 422.0 Members' equity 2,476.7 2,346.0 Total liabilities and members' equity $ 6,087.4 $ 5,717.9 |
Segment Information (Tables)
Segment Information (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Segment Reporting [Abstract] | |
Schedule of information concerning our reportable segments | The following tables show summarized financial information related to our reportable segments for the years ended December 31, 2022, 2021, and 2020. Utility Operations 2022 (in millions) Wisconsin Illinois Other States Total Utility Electric Transmission Non-Utility Energy Infrastructure Corporate and Other Reconciling WEC Energy Group Consolidated External revenues $ 6,960.5 $ 1,890.9 $ 618.5 $ 9,469.9 $ — $ 127.0 $ 0.5 $ — $ 9,597.4 Intersegment revenues — — — — — 463.0 — (463.0) — Other operation and maintenance 1,351.3 459.2 98.5 1,909.0 — 51.0 (12.9) (9.1) 1,938.0 Depreciation and amortization 754.7 230.9 40.9 1,026.5 — 139.2 25.0 (68.1) 1,122.6 Equity in earnings of transmission affiliates — — — — 194.7 — — — 194.7 Interest expense 555.9 73.8 13.9 643.6 19.4 68.9 119.4 (336.2) 515.1 Income tax expense (benefit) 247.5 83.1 13.1 343.7 45.8 (20.9) (45.7) — 322.9 Net income (loss) 759.6 226.9 39.7 1,026.2 129.5 324.8 (70.8) — 1,409.7 Net income (loss) attributed to common shareholders 758.4 226.9 39.7 1,025.0 129.5 324.4 (70.8) — 1,408.1 Capital expenditures and asset acquisitions 1,610.8 484.9 101.1 2,196.8 — 483.8 16.3 — 2,696.9 Total assets (1) 27,384.0 8,101.0 1,639.6 37,124.6 1,909.4 5,320.6 774.0 (3,256.5) 41,872.1 (1) Total assets at December 31, 2022 reflect an elimination of $1,632.9 million for all lease activity between We Power and WE. Utility Operations 2021 (in millions) Wisconsin Illinois Other States Total Utility Electric Transmission Non-Utility Energy Infrastructure Corporate and Other Reconciling WEC Energy Group Consolidated External revenues $ 6,037.0 $ 1,672.8 $ 519.0 $ 8,228.8 $ — $ 86.7 $ 0.5 $ — $ 8,316.0 Intersegment revenues — — — — — 452.8 — (452.8) — Other operation and maintenance 1,455.2 433.5 90.4 1,979.1 — 43.1 (7.5) (9.2) 2,005.5 Depreciation and amortization 726.9 218.1 38.1 983.1 — 125.3 25.9 (60.0) 1,074.3 Equity in earnings of transmission affiliates — — — — 158.1 — — — 158.1 Interest expense 555.6 66.6 6.2 628.4 19.4 71.0 92.8 (340.5) 471.1 Loss on debt extinguishment — — — — — — 36.3 — 36.3 Income tax expense (benefit) 119.9 79.3 11.5 210.7 32.3 3.1 (45.8) — 200.3 Net income (loss) 707.7 223.0 35.8 966.5 106.3 276.2 (50.5) — 1,298.5 Net income (loss) attributed to common shareholders 706.5 223.0 35.8 965.3 106.3 279.2 (50.5) — 1,300.3 Capital expenditures and asset acquisitions 1,389.7 533.7 95.9 2,019.3 — 335.3 18.1 — 2,372.7 Total assets (1) 25,687.9 7,853.4 1,506.1 35,047.4 1,792.7 4,627.7 785.3 (3,264.6) 38,988.5 (1) Total assets at December 31, 2021 reflect an elimination of $1,729.9 million for all lease activity between We Power and WE. Utility Operations 2020 (in millions) Wisconsin Illinois Other States Total Utility Electric Transmission Non-Utility Energy Infrastructure Corporate and Other Reconciling WEC Energy Group Consolidated External revenues $ 5,473.5 $ 1,321.9 $ 384.1 $ 7,179.5 $ — $ 60.0 $ 2.2 $ — $ 7,241.7 Intersegment revenues — — — — — 448.5 — (448.5) — Other operation and maintenance 1,476.7 435.4 87.0 1,999.1 — 24.9 17.4 (9.2) 2,032.2 Depreciation and amortization 674.5 196.7 33.5 904.7 — 98.9 25.1 (52.8) 975.9 Equity in earnings of transmission affiliates — — — — 175.8 — — — 175.8 Interest expense 561.3 63.5 10.2 635.0 19.4 60.8 124.0 (345.5) 493.7 Loss on debt extinguishment — — — — — — 38.4 — 38.4 Income tax expense (benefit) 132.7 66.1 13.1 211.9 43.7 44.7 (72.4) — 227.9 Net income (loss) 691.6 203.5 39.0 934.1 112.6 261.1 (106.4) — 1,201.4 Net income (loss) attributed to common shareholders 690.4 203.5 39.0 932.9 112.6 260.8 (106.4) — 1,199.9 Capital expenditures and asset acquisitions 1,382.4 652.7 144.3 2,179.4 — 661.8 33.1 — 2,874.3 Total assets (1) 24,599.2 7,471.8 1,336.2 33,407.2 1,764.7 4,455.2 762.2 (3,361.2) 37,028.1 (1) Total assets at December 31, 2020 reflect an elimination of $1,824.5 million for all lease activity between We Power and WE. |
Variable Interest Entities (Tab
Variable Interest Entities (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
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) December 31, 2022 December 31, 2021 Assets Other current assets (restricted cash) $ 3.0 $ 2.4 Regulatory assets 92.4 100.7 Other long-term assets (restricted cash) 0.6 0.6 Liabilities Current portion of long-term debt 8.9 8.8 Other current liabilities (accrued interest) 0.1 0.1 Long-term debt 94.1 102.7 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of minimum future commitments related to purchase obligations | The following table shows our minimum future commitments related to these purchase obligations as of December 31, 2022, including those of our subsidiaries: Payments Due By Period (in millions) Date Contracts Extend Through Total Amounts Committed 2023 2024 2025 2026 2027 Later Years Electric utility: Nuclear 2033 $ 6,829.1 $ 548.5 $ 600.3 $ 634.5 $ 681.6 $ 730.4 $ 3,633.8 Coal supply and transportation 2030 936.1 393.3 279.2 207.9 24.7 7.6 23.4 Purchased power 2051 256.2 63.4 54.2 47.8 44.2 19.6 27.0 Natural gas utility: Supply and transportation 2048 1,938.8 382.1 344.2 228.4 173.7 158.8 651.6 Non-utility energy infrastructure: Purchased power 2049 495.0 26.2 26.1 26.7 27.3 27.8 360.9 Natural gas storage and transportation 2048 5.8 4.9 0.1 — — — 0.8 Total $ 10,461.0 $ 1,418.4 $ 1,304.1 $ 1,145.3 $ 951.5 $ 944.2 $ 4,697.5 |
Schedule of regulatory assets and reserves related to manufactured gas plant sites | We have established the following regulatory assets and reserves for manufactured gas plant sites as of December 31: (in millions) 2022 2021 Regulatory assets $ 610.7 $ 630.9 Reserves for future environmental remediation 499.6 532.6 |
Supplemental Cash Flow Inform_2
Supplemental Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract] | |
Schedule of supplemental cash flow information | Year Ended December 31 (in millions) 2022 2021 2020 Cash paid for interest, net of amount capitalized $ 485.2 $ 473.8 $ 492.9 Cash paid for income taxes, net 52.4 33.8 27.9 Significant non-cash investing and financing transactions: Accounts payable related to construction costs 197.4 127.8 153.1 Increase in receivable related to insurance proceeds — 41.7 2.7 Liabilities accrued for software licensing agreement 7.4 — — |
Reconciliation of cash, cash equivalents, and restricted cash | The following table reconciles the cash, cash equivalents, and restricted cash amounts reported within the balance sheets at December 31 to the total of these amounts shown on the statements of cash flows: (in millions) 2022 2021 2020 Cash and cash equivalents $ 28.9 $ 16.3 $ 24.8 Restricted cash included in other current assets 25.6 19.6 — Restricted cash included in other long-term assets 127.7 51.6 47.8 Cash, cash equivalents, and restricted cash $ 182.2 $ 87.5 $ 72.6 |
Regulatory Environment (Tables)
Regulatory Environment (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
2023 and 2024 Rates | |
Public Utilities, General Disclosures | |
Schedule of regulatory decisions | The final orders reflect the following: WE WPS WG 2023 base rate increase Electric $ 283.5 million / 9.1% $ 120.5 million / 9.8% N/A Gas $ 46.1 million / 9.6% $ 26.4 million / 7.1% $ 46.5 million / 6.4% Steam $ 7.6 million / 35.3% N/A N/A ROE 9.8% 9.8% 9.8% Common equity component average on a financial basis 53.0% 53.0% 53.0% |
2020 and 2021 rates | |
Public Utilities, General Disclosures | |
Schedule of regulatory decisions | WE WPS WG 2020 Effective rate increase (decrease) Electric (1) (2) $ 15.3 million / 0.5% $ 15.8 million / 1.6% N/A Gas (3) $ 10.4 million / 2.8% $ 4.3 million / 1.4% $ (1.5) million / (0.2)% Steam $ 1.9 million / 8.6% N/A N/A ROE 10.0% 10.0% 10.2% Common equity component average on a financial basis 52.5% 52.5% 52.5% (1) Amounts are net of certain deferred tax benefits from the Tax Legislation that were utilized to reduce near-term rate impact. The WE and WPS rate orders reflected the majority of the unprotected deferred tax benefits from the Tax Legislation being amortized over two years. For WE, approximately $65 million of tax benefits were amortized in each of 2020 and 2021. For WPS, approximately $11 million of tax benefits were amortized in 2020 and approximately $39 million were amortized in 2021. The unprotected deferred tax benefits related to the unrecovered balances of certain of WE's retired plants and its SSR regulatory asset were used to reduce the related regulatory asset. Unprotected deferred tax benefits by their nature are eligible to be returned to customers in a manner and timeline determined to be appropriate by our regulators. (2) The WPS rate order was net of $21 million of refunds related to its 2018 earnings sharing mechanism. These refunds were made to customers evenly over two years, with half returned in 2020 and the remainder returned in 2021. (3) The WE amount includes certain deferred tax expense from the Tax Legislation, and the WPS and WG amounts are net of certain deferred tax benefits from the Tax Legislation that were utilized to reduce near-term rate impact. The rate orders for all three gas utilities reflected all of the unprotected deferred tax expense and benefits from the Tax Legislation being amortized evenly over four years. For WE, approximately $5 million of previously deferred tax expense is being amortized each year. For WPS and WG, approximately $5 million and $3 million, respectively, of previously deferred tax benefits are being amortized each year. Unprotected deferred tax expense and benefits by their nature are eligible to be recovered from or returned to customers in a manner and timeline determined to be appropriate by our regulators. |
Other Income, Net (Tables)
Other Income, Net (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Other Income and Expenses [Abstract] | |
Schedule of other income, net | Total other income, net was as follows for the years ended December 31: (in millions) 2022 2021 2020 Non-service components of net periodic benefit costs $ 104.4 $ 72.2 $ 41.2 AFUDC–Equity 29.4 18.0 20.9 Earnings from equity method investments (1) 9.3 19.9 2.4 Gains (losses) from investments held in rabbi trust (12.6) 18.6 12.7 Other, net (1.7) 4.5 2.3 Other income, net $ 128.8 $ 133.2 $ 79.5 (1) Amount does not include equity earnings of transmission affiliates as those earnings are shown as a separate line item on the income statements. |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies Nature of Operations (Details) customer in Millions | Dec. 31, 2022 customer |
ATC | |
Product Information | |
Equity method investment, ownership interest (as a percent) | 60% |
ATC Holdco | |
Product Information | |
Equity method investment, ownership interest (as a percent) | 75% |
Electric | |
Product Information | |
Number of customers | 1.6 |
Natural gas | |
Product Information | |
Number of customers | 3 |
Summary of Significant Accoun_5
Summary of Significant Accounting Policies Cash and Cash Equivalents (Details) | 12 Months Ended |
Dec. 31, 2022 | |
Accounting Policies [Abstract] | |
Maximum term of original maturity to classify instrument as cash equivalent | 3 months |
Summary of Significant Accoun_6
Summary of Significant Accounting Policies Operating Revenues (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 USD ($) contract performance_obligations | Dec. 31, 2021 USD ($) | Dec. 31, 2020 USD ($) | |
Electric | |||
Disaggregation of Operating Revenues | |||
Number of days payment is due | 30 days | ||
Electric | Retail | |||
Disaggregation of Operating Revenues | |||
Number of performance obligations | 1 | ||
Percent fuel and purchased power costs can vary from the rate case approved costs before deferral is required | 2% | ||
Electric | Wholesale | |||
Disaggregation of Operating Revenues | |||
Number of performance obligations | 2 | ||
Number of contracts | contract | 1 | ||
Natural gas | |||
Disaggregation of Operating Revenues | |||
Number of days payment is due | 30 days | ||
Other non-utility revenues | |||
Disaggregation of Operating Revenues | |||
Number of days payment is due | 30 days | ||
Appliance service repairs | Maximum | |||
Disaggregation of Operating Revenues | |||
Duration of contract for remaining performance obligations in contract | 1 year | ||
We Power revenues | |||
Disaggregation of Operating Revenues | |||
Revenues amortized from deferred revenue during the period | $ | $ 23.4 | $ 23.3 | $ 22.9 |
Summary of Significant Accoun_7
Summary of Significant Accounting Policies Materials, Supplies, and Inventories (Details) $ in Millions | Dec. 31, 2022 USD ($) $ / MMBTU | Dec. 31, 2021 USD ($) $ / MMBTU |
Accounting Policies [Abstract] | ||
Natural gas in storage | $ 446.3 | $ 326 |
Materials and supplies | 257 | 225.3 |
Fossil fuel | 103.8 | 84.5 |
Total | $ 807.1 | $ 635.8 |
LIFO Method Related Items [Abstract] | ||
Percentage of LIFO inventory | 13% | 19% |
Excess of replacement or current costs over stated LIFO value | $ 98.3 | $ 114.2 |
Natural gas price benchmark | $ / MMBTU | 3.41 | 3.67 |
Summary of Significant Accoun_8
Summary of Significant Accounting Policies Property, Plant, and Equipment (Details) | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Software | Minimum | |||
Property, plant, and equipment | |||
Estimated useful life | 3 years | ||
Software | Maximum | |||
Property, plant, and equipment | |||
Estimated useful life | 15 years | ||
PWGS | Minimum | |||
Property, plant, and equipment | |||
Estimated useful life | 10 years | ||
PWGS | Maximum | |||
Property, plant, and equipment | |||
Estimated useful life | 45 years | ||
ERGS | Minimum | |||
Property, plant, and equipment | |||
Estimated useful life | 10 years | ||
ERGS | Maximum | |||
Property, plant, and equipment | |||
Estimated useful life | 55 years | ||
WE | |||
Property, plant, and equipment | |||
Annual utility composite depreciation rate (as a percent) | 3.06% | 3.09% | 3.19% |
WPS | |||
Property, plant, and equipment | |||
Annual utility composite depreciation rate (as a percent) | 2.67% | 2.66% | 2.63% |
WG | |||
Property, plant, and equipment | |||
Annual utility composite depreciation rate (as a percent) | 2.47% | 2.44% | 2.33% |
PGL | |||
Property, plant, and equipment | |||
Annual utility composite depreciation rate (as a percent) | 3.13% | 3.12% | 3.16% |
NSG | |||
Property, plant, and equipment | |||
Annual utility composite depreciation rate (as a percent) | 2.43% | 2.52% | 2.48% |
MERC | |||
Property, plant, and equipment | |||
Annual utility composite depreciation rate (as a percent) | 2.56% | 2.58% | 2.47% |
MGU | |||
Property, plant, and equipment | |||
Annual utility composite depreciation rate (as a percent) | 2.75% | 2.70% | 2.67% |
UMERC | |||
Property, plant, and equipment | |||
Annual utility composite depreciation rate (as a percent) | 3.01% | 2.94% | 2.97% |
Summary of Significant Accoun_9
Summary of Significant Accounting Policies AFUDC (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Allowance for Funds Used During Construction | |||
AFUDC - Debt | $ 11 | $ 6.8 | $ 8 |
AFUDC - Equity | 29.4 | 18 | 20.9 |
WE | |||
Allowance for Funds Used During Construction | |||
AFUDC - Debt | 6.9 | 2.9 | 2.6 |
AFUDC - Equity | 18.8 | 7.9 | 7 |
WPS | |||
Allowance for Funds Used During Construction | |||
AFUDC - Debt | 2.3 | 3.5 | 4.6 |
AFUDC - Equity | 5.8 | 9 | 11.8 |
WG | |||
Allowance for Funds Used During Construction | |||
AFUDC - Debt | 1.4 | 0.2 | 0.6 |
AFUDC - Equity | 3.9 | 0.6 | 1.6 |
UMERC | |||
Allowance for Funds Used During Construction | |||
AFUDC - Debt | 0.1 | 0.1 | 0 |
AFUDC - Equity | 0.1 | 0.1 | 0.1 |
WBS | |||
Allowance for Funds Used During Construction | |||
AFUDC - Debt | 0.1 | 0.1 | 0.1 |
AFUDC - Equity | 0.3 | 0.2 | 0.2 |
Other | |||
Allowance for Funds Used During Construction | |||
AFUDC - Debt | 0.2 | 0 | 0.1 |
AFUDC - Equity | $ 0.5 | $ 0.2 | $ 0.2 |
Retail operations | WE | |||
Allowance for Funds Used During Construction | |||
Percentage of retail jurisdictional construction work in progress expenditures subject to AFUDC | 50% | ||
Average AFUDC rate (as a percent) | 8.68% | ||
Retail operations | WPS | |||
Allowance for Funds Used During Construction | |||
Percentage of retail jurisdictional construction work in progress expenditures subject to AFUDC | 50% | ||
Average AFUDC rate (as a percent) | 7.55% | ||
Retail operations | WG | |||
Allowance for Funds Used During Construction | |||
Percentage of retail jurisdictional construction work in progress expenditures subject to AFUDC | 50% | ||
Average AFUDC rate (as a percent) | 8.32% | ||
Retail operations | UMERC | |||
Allowance for Funds Used During Construction | |||
Percentage of retail jurisdictional construction work in progress expenditures subject to AFUDC | 50% | ||
Average AFUDC rate (as a percent) | 6.28% | ||
Retail operations | WBS | |||
Allowance for Funds Used During Construction | |||
Percentage of retail jurisdictional construction work in progress expenditures subject to AFUDC | 50% | ||
Average AFUDC rate (as a percent) | 7.55% | ||
Wholesale operations | WE | |||
Allowance for Funds Used During Construction | |||
Average AFUDC rate (as a percent) | 5.35% | ||
Wholesale operations | WPS | |||
Allowance for Funds Used During Construction | |||
Average AFUDC rate (as a percent) | 5.49% |
Summary of Significant Accou_10
Summary of Significant Accounting Policies Cloud Computing Hosting Arrangements that are Service Contracts (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Accounting Policies [Abstract] | ||
Capitalized implementation costs, gross | $ 4.7 | $ 3.3 |
Capitalized implementation costs, accumulated amortization | $ 1.5 | $ 0.6 |
Summary of Significant Accou_11
Summary of Significant Accounting Policies Asset Impairment (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Accounting Policies [Abstract] | ||
Impairment losses for indefinite-lived intangible assets | $ 0 | $ 0 |
Summary of Significant Accou_12
Summary of Significant Accounting Policies Stock-Based Compensation (Details) - $ / shares | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||
Jan. 31, 2023 | Mar. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Number of shares authorized for issuance | 9,000,000 | ||||
Stock options | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Vesting period (in years) | 3 years | ||||
Minimum exercise price of stock option as a percent of common stock fair value on the grant date | 100% | ||||
Period after the grant date during which stock options can't be exercised (in months) | 6 months | ||||
Maximum term of awards (in years) | 10 years | ||||
Stock options granted (in shares) | 437,269 | 530,612 | 554,594 | ||
Estimated weighted-average fair value per stock option (in dollars per share) | $ 14.71 | $ 13.20 | $ 10.94 | ||
Risk-free interest rate, minimum (as a percent) | 0.20% | 0.10% | 0.20% | ||
Risk-free interest rate, maximum (as a percent) | 1.60% | 0.90% | 1.90% | ||
Dividend yield (as a percent) | 3.20% | 2.90% | 3% | ||
Expected volatility (as a percent) | 21% | 21% | 16.30% | ||
Expected life (in years) | 8 years 8 months 12 days | 8 years 8 months 12 days | 8 years 7 months 6 days | ||
Stock options | Subsequent event | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Stock options granted (in shares) | 257,780 | ||||
Estimated weighted-average fair value per stock option (in dollars per share) | $ 19.58 | ||||
Restricted stock | Employees | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Vesting period (in years) | 3 years | ||||
Percentage to vest each year after grant date | 33% | ||||
Restricted stock | Directors | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Vesting period (in years) | 1 year | ||||
Performance units | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Vesting period (in years) | 3 years | ||||
Performance units | Performance units granted prior to 2023 | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Maximum adjustment to payout ratio | 10% | ||||
Performance units | Performance units granted prior to 2023 | Minimum | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Payout ratio (as a percent) | 0% | ||||
Performance units | Performance units granted prior to 2023 | Maximum | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Payout ratio (as a percent) | 175% | ||||
Performance units | Performance units granted in 2023 | Subsequent event | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Vesting period (in years) | 3 years | ||||
Maximum adjustment to payout ratio | 25% | ||||
Percentage of payout based on total shareholder return | 55% | ||||
Percentage of payout based on ROE | 45% | ||||
Performance units | Performance units granted in 2023 | Maximum | Subsequent event | |||||
Share-based Compensation Arrangement by Share-based Payment Award | |||||
Payout ratio (as a percent) | 200% |
Summary of Significant Accou_13
Summary of Significant Accounting Policies Earnings Per Share (Details) - shares | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Stock options | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Antidilutive securities excluded from computation of earnings per share | 653,323 | 769,030 | 207,445 |
Summary of Significant Accou_14
Summary of Significant Accounting Policies - Leases (Details) | Dec. 31, 2022 |
Accounting Policies [Abstract] | |
Minimum lease term to recognize right of use asset and lease liabilities | 1 year |
Summary of Significant Accou_15
Summary of Significant Accounting Policies Customer Concentrations of Credit Risk (Details) - Customer Concentration Risk | 12 Months Ended |
Dec. 31, 2022 customer | |
Customer concentrations of credit risk | |
Number of customers that account for more than 10% of revenues | 0 |
Revenue Benchmark | Fair Value, Concentration of Risk, All Financial Instruments | |
Customer concentrations of credit risk | |
Threshold percentage of revenues from major customers | 10% |
Acquisitions - Sapphire Sky (De
Acquisitions - Sapphire Sky (Details) - Sapphire Sky - Subsequent event $ in Millions | 1 Months Ended | |
Feb. 28, 2023 USD ($) | Feb. 07, 2023 MW | |
Asset Acquisition | ||
Duration of offtake agreement for the sale of energy produced | 12 years | |
WECI | ||
Asset Acquisition | ||
Ownership interest in generating facility acquired | 90% | |
Capacity of generation unit | MW | 250 | |
Total purchase price | $ | $ 442.9 |
Acquisitions - Maple Flats (Det
Acquisitions - Maple Flats (Details) - Maple Flats - WECI $ in Millions | 1 Months Ended |
Oct. 31, 2022 USD ($) MW | |
Asset Acquisition | |
Ownership interest in generating facility acquired | 80% |
Capacity of generation unit | MW | 250 |
Acquisition purchase price, expected | $ | $ 360 |
Duration of offtake agreement for the sale of energy produced | 15 years |
Acquisitions - Blooming Grove (
Acquisitions - Blooming Grove (Details) $ in Millions | 1 Months Ended | ||
Dec. 31, 2020 USD ($) MW | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | |
Asset Acquisition - Allocation of Purchase Price to Assets acquired, Liabilities assumed, less Noncontrolling Interest | |||
Net property, plant, and equipment | $ 29,113.8 | $ 26,982.4 | |
Other current liabilities | $ (884.6) | $ (680.9) | |
Blooming Grove | WECI | |||
Asset Acquisition | |||
Ownership interest in generating facility acquired | 90% | ||
Capacity of generation unit | MW | 250 | ||
Total purchase price | $ 364.6 | ||
Cash and restricted cash acquired | $ 24.1 | ||
Duration of offtake agreement for the sale of energy produced | 12 years | ||
Asset Acquisition - Allocation of Purchase Price to Assets acquired, Liabilities assumed, less Noncontrolling Interest | |||
Accounts receivable | $ 0.3 | ||
Net property, plant, and equipment | 488.3 | ||
Other long-term assets | 2.9 | ||
Accounts payable | (13.7) | ||
Other current liabilities | (1.5) | ||
Long-term liabilities | (68.7) | ||
Noncontrolling interest | (43) | ||
Total purchase price | $ 364.6 |
Acquisitions - Samson I (Detail
Acquisitions - Samson I (Details) - Samson I - WECI - Subsequent event $ in Millions | 1 Months Ended |
Jan. 31, 2023 USD ($) MW | |
Asset Acquisition | |
Ownership interest in generating facility acquired | 80% |
Capacity of generation unit | MW | 250 |
Acquisition purchase price, expected | $ | $ 250 |
Duration of offtake agreement for the sale of energy produced | 15 years |
Acquisitions - Whitewater (Deta
Acquisitions - Whitewater (Details) - Whitewater - WE and WPS - Subsequent event $ in Millions | 1 Months Ended | |
Jan. 31, 2023 USD ($) | Jan. 01, 2023 MW | |
Asset Acquisition | ||
Capacity of generation unit | MW | 236.5 | |
Total purchase price | $ | $ 72.7 |
Acquisitions - Red Barn (Detail
Acquisitions - Red Barn (Details) - Red Barn Wind Park - WPS $ in Millions | 1 Months Ended |
Jan. 31, 2022 USD ($) MW | |
Asset Acquisition | |
Capacity of generation unit | MW | 82 |
Acquisition purchase price, expected | $ | $ 160 |
Acquisitions - Thunderhead (Det
Acquisitions - Thunderhead (Details) $ in Millions | 1 Months Ended | ||
Sep. 30, 2022 USD ($) MW | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | |
Asset Acquisition - Allocation of Purchase Price to Assets acquired, Liabilities assumed, less Noncontrolling Interest | |||
Net property, plant, and equipment | $ 29,113.8 | $ 26,982.4 | |
Current liabilities | (4,611) | (3,753) | |
Liabilities, Noncurrent | $ (25,644.5) | $ (24,122.2) | |
Thunderhead | WECI | |||
Asset Acquisition | |||
Ownership interest in generating facility acquired | 90% | ||
Capacity of generation unit | MW | 300 | ||
Total purchase price | $ 382 | ||
Duration of offtake agreement for the sale of energy produced | 12 years | ||
Asset Acquisition - Allocation of Purchase Price to Assets acquired, Liabilities assumed, less Noncontrolling Interest | |||
Accounts receivable | $ 0.2 | ||
Other prepayments | 0.3 | ||
Net property, plant, and equipment | 692.3 | ||
Other long-term assets | 5.1 | ||
Current liabilities | (0.2) | ||
Liabilities, Noncurrent | (273.2) | ||
Noncontrolling interest | (42.5) | ||
Total purchase price | $ 382 |
Acquisitions - Jayhawk (Details
Acquisitions - Jayhawk (Details) $ in Millions | 1 Months Ended | ||
Feb. 28, 2021 USD ($) MW | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | |
Asset Acquisition - Allocation of Purchase Price to Assets acquired, Liabilities assumed, less Noncontrolling Interest | |||
Net property, plant, and equipment | $ 29,113.8 | $ 26,982.4 | |
Long-term Debt | (15,464.2) | $ (13,563.4) | |
Jayhawk | WECI | |||
Asset Acquisition | |||
Ownership interest in generating facility acquired | 90% | ||
Capacity of generation unit | MW | 190 | ||
Total purchase price | $ 119.9 | ||
Additional capital expenditures | 161.3 | ||
Current project investment | $ 281.2 | ||
Duration of offtake agreement for the sale of energy produced | 10 years | ||
Percentage of tax benefits entitled to | 99% | ||
Number of years will receive tax benefits | 10 years | ||
Asset Acquisition - Allocation of Purchase Price to Assets acquired, Liabilities assumed, less Noncontrolling Interest | |||
Net property, plant, and equipment | $ 145.3 | ||
Long-term liabilities | (11.8) | ||
Long-term Debt | (7.3) | ||
Noncontrolling interest | (6.3) | ||
Total purchase price | $ 119.9 |
Acquisitions - Tatanka Ridge (D
Acquisitions - Tatanka Ridge (Details) $ in Millions | 1 Months Ended | ||
Dec. 31, 2020 USD ($) MW | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | |
Asset Acquisition - Allocation of Purchase Price to Assets acquired, Liabilities assumed, less Noncontrolling Interest | |||
Current assets | $ 3,187.7 | $ 2,656.7 | |
Net property, plant, and equipment | 29,113.8 | 26,982.4 | |
Current liabilities | $ (4,611) | $ (3,753) | |
Tatanka Ridge | WECI | |||
Asset Acquisition | |||
Ownership interest in generating facility acquired | 85% | ||
Capacity of generation unit | MW | 155 | ||
Total purchase price | $ 239.9 | ||
Duration of offtake agreement for the sale of energy produced | 12 years | ||
Duration of offtake agreement for the sale of energy produced for company 2 | 10 years | ||
Percent of tax benefits entitled to | 99% | ||
Number of years will receive tax benefits | 11 years | ||
Asset Acquisition - Allocation of Purchase Price to Assets acquired, Liabilities assumed, less Noncontrolling Interest | |||
Current assets | $ 37.3 | ||
Net property, plant, and equipment | 301.2 | ||
Current liabilities | (37.3) | ||
Long-term liabilities | (19.3) | ||
Noncontrolling interest | (42) | ||
Total purchase price | $ 239.9 |
Dispositions (Details)
Dispositions (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 USD ($) a | Dec. 31, 2021 USD ($) | Dec. 31, 2020 USD ($) | |
Dispositions | |||
Proceeds from the sale of assets | $ 69 | $ 21.9 | $ 20.3 |
Corporate and Other | |||
Dispositions | |||
Proceeds from the sale of assets | 10.5 | ||
After-tax gain on sale | $ 3 | ||
Illinois | |||
Dispositions | |||
NumberofAcresSold | a | 11 | ||
Proceeds from sale of other real estate | $ 55.1 | ||
Pre-tax gain on sale of other real estate | $ 54.5 |
Operating Revenues - Disaggrega
Operating Revenues - Disaggregation Of Operating Revenues by Segment (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Disaggregation of Operating Revenues | |||
Operating revenues | $ 9,597.4 | $ 8,316 | $ 7,241.7 |
Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 9,568.1 | 8,235.7 | 7,169.3 |
Other operating revenues | |||
Disaggregation of Operating Revenues | |||
Other operating revenues | 29.3 | 80.3 | 72.4 |
Total regulated revenues | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 9,424.9 | 8,134.2 | 7,093 |
Electric | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 4,956.2 | 4,516.6 | 4,266.1 |
Natural gas | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 4,468.7 | 3,617.6 | 2,826.9 |
Natural gas | Transferred over time | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 4,466.2 | 3,614.6 | 2,824.5 |
Other non-utility revenues | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 143.2 | 101.5 | 76.3 |
Reconciling Eliminations | |||
Disaggregation of Operating Revenues | |||
Operating revenues | (463) | (452.8) | (448.5) |
Reconciling Eliminations | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | (60.9) | (52.9) | (51.1) |
Reconciling Eliminations | Other operating revenues | |||
Disaggregation of Operating Revenues | |||
Other operating revenues | (402.1) | (399.9) | (397.4) |
Reconciling Eliminations | Total regulated revenues | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | (51.8) | (43.8) | (42) |
Reconciling Eliminations | Electric | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 0 | 0 | 0 |
Reconciling Eliminations | Natural gas | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | (51.8) | (43.8) | (42) |
Reconciling Eliminations | Other non-utility revenues | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | (9.1) | (9.1) | (9.1) |
Total Utility Operations | |||
Disaggregation of Operating Revenues | |||
Operating revenues | 9,469.9 | 8,228.8 | 7,179.5 |
Total Utility Operations | Other operating revenues | |||
Disaggregation of Operating Revenues | |||
Other operating revenues | 28.8 | 79.8 | 71.8 |
Total Utility Operations | Transferred over time | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 9,441.1 | 8,149 | 7,107.7 |
Total Utility Operations | Total regulated revenues | Transferred over time | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 9,422.4 | 8,131.2 | 7,090.6 |
Total Utility Operations | Electric | Transferred over time | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 4,956.2 | 4,516.6 | 4,266.1 |
Total Utility Operations | Natural gas | Transferred over time | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 4,466.2 | 3,614.6 | 2,824.5 |
Total Utility Operations | Other non-utility revenues | Transferred over time | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 18.7 | 17.8 | 17.1 |
Wisconsin | |||
Disaggregation of Operating Revenues | |||
Operating revenues | 6,960.5 | 6,037 | 5,473.5 |
Wisconsin | Other operating revenues | |||
Disaggregation of Operating Revenues | |||
Other operating revenues | 23.6 | 30.1 | 11.8 |
Wisconsin | Transferred over time | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 6,936.9 | 6,006.9 | 5,461.7 |
Wisconsin | Total regulated revenues | Transferred over time | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 6,936.9 | 6,006.9 | 5,461.7 |
Wisconsin | Electric | Transferred over time | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 4,956.2 | 4,516.6 | 4,266.1 |
Wisconsin | Natural gas | Transferred over time | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 1,980.7 | 1,490.3 | 1,195.6 |
Wisconsin | Other non-utility revenues | Transferred over time | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 0 | 0 | 0 |
Illinois | |||
Disaggregation of Operating Revenues | |||
Operating revenues | 1,890.9 | 1,672.8 | 1,321.9 |
Illinois | Other operating revenues | |||
Disaggregation of Operating Revenues | |||
Other operating revenues | 7.2 | 42.5 | 54 |
Illinois | Transferred over time | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 1,883.7 | 1,630.3 | 1,267.9 |
Illinois | Total regulated revenues | Transferred over time | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 1,883.7 | 1,630.3 | 1,267.9 |
Illinois | Electric | Transferred over time | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 0 | 0 | 0 |
Illinois | Natural gas | Transferred over time | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 1,883.7 | 1,630.3 | 1,267.9 |
Illinois | Other non-utility revenues | Transferred over time | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 0 | 0 | 0 |
Other States | |||
Disaggregation of Operating Revenues | |||
Operating revenues | 618.5 | 519 | 384.1 |
Other States | Other operating revenues | |||
Disaggregation of Operating Revenues | |||
Other operating revenues | (2) | 7.2 | 6 |
Other States | Transferred over time | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 620.5 | 511.8 | 378.1 |
Other States | Total regulated revenues | Transferred over time | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 601.8 | 494 | 361 |
Other States | Electric | Transferred over time | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 0 | 0 | 0 |
Other States | Natural gas | Transferred over time | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 601.8 | 494 | 361 |
Other States | Other non-utility revenues | Transferred over time | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 18.7 | 17.8 | 17.1 |
Non-Utility Energy Infrastructure | |||
Disaggregation of Operating Revenues | |||
Operating revenues | 590 | 539.5 | 508.5 |
Non-Utility Energy Infrastructure | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 187.9 | 139.6 | 111 |
Non-Utility Energy Infrastructure | Other operating revenues | |||
Disaggregation of Operating Revenues | |||
Other operating revenues | 402.1 | 399.9 | 397.5 |
Non-Utility Energy Infrastructure | Total regulated revenues | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 54.3 | 46.8 | 44.4 |
Non-Utility Energy Infrastructure | Electric | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 0 | 0 | 0 |
Non-Utility Energy Infrastructure | Natural gas | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 54.3 | 46.8 | 44.4 |
Non-Utility Energy Infrastructure | Other non-utility revenues | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 133.6 | 92.8 | 66.6 |
Corporate and Other | |||
Disaggregation of Operating Revenues | |||
Operating revenues | 0.5 | 0.5 | 2.2 |
Corporate and Other | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 0 | 0 | 1.7 |
Corporate and Other | Other operating revenues | |||
Disaggregation of Operating Revenues | |||
Other operating revenues | 0.5 | 0.5 | 0.5 |
Corporate and Other | Total regulated revenues | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 0 | 0 | 0 |
Corporate and Other | Electric | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 0 | 0 | 0 |
Corporate and Other | Natural gas | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 0 | 0 | 0 |
Corporate and Other | Other non-utility revenues | Revenues from contracts with customers | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | $ 0 | $ 0 | $ 1.7 |
Operating Revenues - Disaggre_2
Operating Revenues - Disaggregation of Electric Utility Operating Revenues by Customer Class (Details) - Revenues from contracts with customers - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | $ 9,568.1 | $ 8,235.7 | $ 7,169.3 |
Electric | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 4,956.2 | 4,516.6 | 4,266.1 |
Wisconsin | Transferred over time | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 6,936.9 | 6,006.9 | 5,461.7 |
Wisconsin | Electric | Transferred over time | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 4,956.2 | 4,516.6 | 4,266.1 |
Wisconsin | Electric | Transferred over time | Total retail revenues | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 4,481.6 | 4,144.9 | 3,920.3 |
Wisconsin | Electric | Transferred over time | Residential | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 1,879.1 | 1,768 | 1,743.9 |
Wisconsin | Electric | Transferred over time | Small commercial and industrial | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 1,530.4 | 1,415.7 | 1,325.9 |
Wisconsin | Electric | Transferred over time | Large commercial and industrial | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 1,042.2 | 931.9 | 821.5 |
Wisconsin | Electric | Transferred over time | Other | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 29.9 | 29.3 | 29 |
Wisconsin | Electric | Transferred over time | Wholesale | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 153.9 | 157.7 | 174 |
Wisconsin | Electric | Transferred over time | Resale | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 256.7 | 161.9 | 130.4 |
Wisconsin | Electric | Transferred over time | Steam | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 28.4 | 28.7 | 21.3 |
Wisconsin | Electric | Transferred over time | Other utility revenues | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | $ 35.6 | $ 23.4 | $ 20.1 |
Operating Revenues - Disaggre_3
Operating Revenues - Disaggregation of Natural Gas Utility Operating Revenues by Customer Class (Details) - Revenues from contracts with customers - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | $ 9,568.1 | $ 8,235.7 | $ 7,169.3 |
Natural gas | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 4,468.7 | 3,617.6 | 2,826.9 |
Natural gas | Transferred over time | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 4,466.2 | 3,614.6 | 2,824.5 |
Natural gas | Transferred over time | Total retail revenues | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 4,222.9 | 3,092.1 | 2,450.5 |
Natural gas | Transferred over time | Residential | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 2,922.7 | 2,188 | 1,775.6 |
Natural gas | Transferred over time | Commercial and industrial | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 1,300.2 | 904.1 | 674.9 |
Natural gas | Transferred over time | Transport | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 376.1 | 343 | 326.2 |
Natural gas | Transferred over time | Other utility revenues | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | (132.8) | 179.5 | 47.8 |
Wisconsin | Transferred over time | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 6,936.9 | 6,006.9 | 5,461.7 |
Wisconsin | Natural gas | Transferred over time | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 1,980.7 | 1,490.3 | 1,195.6 |
Wisconsin | Natural gas | Transferred over time | Total retail revenues | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 1,906.7 | 1,401 | 1,090.7 |
Wisconsin | Natural gas | Transferred over time | Residential | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 1,234 | 928.9 | 752.6 |
Wisconsin | Natural gas | Transferred over time | Commercial and industrial | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 672.7 | 472.1 | 338.1 |
Wisconsin | Natural gas | Transferred over time | Transport | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 81.8 | 80 | 79.1 |
Wisconsin | Natural gas | Transferred over time | Other utility revenues | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | (7.8) | 9.3 | 25.8 |
Illinois | Transferred over time | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 1,883.7 | 1,630.3 | 1,267.9 |
Illinois | Natural gas | Transferred over time | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 1,883.7 | 1,630.3 | 1,267.9 |
Illinois | Natural gas | Transferred over time | Total retail revenues | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 1,706.2 | 1,320 | 1,023.2 |
Illinois | Natural gas | Transferred over time | Residential | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 1,297.4 | 1,017.9 | 802.2 |
Illinois | Natural gas | Transferred over time | Commercial and industrial | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 408.8 | 302.1 | 221 |
Illinois | Natural gas | Transferred over time | Transport | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 259.8 | 231.2 | 215.6 |
Illinois | Natural gas | Transferred over time | Other utility revenues | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | (82.3) | 79.1 | 29.1 |
Other States | Transferred over time | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 620.5 | 511.8 | 378.1 |
Other States | Natural gas | Transferred over time | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 601.8 | 494 | 361 |
Other States | Natural gas | Transferred over time | Total retail revenues | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 610 | 371.1 | 336.6 |
Other States | Natural gas | Transferred over time | Residential | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 391.3 | 241.2 | 220.8 |
Other States | Natural gas | Transferred over time | Commercial and industrial | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 218.7 | 129.9 | 115.8 |
Other States | Natural gas | Transferred over time | Transport | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 34.5 | 31.8 | 31.5 |
Other States | Natural gas | Transferred over time | Other utility revenues | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | $ (42.7) | $ 91.1 | $ (7.1) |
Operating Revenues - Other Non-
Operating Revenues - Other Non-Utility Operating Revenues (Details) - Revenues from contracts with customers - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | $ 9,568.1 | $ 8,235.7 | $ 7,169.3 |
Other non-utility revenues | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 143.2 | 101.5 | 76.3 |
Other non-utility revenues | We Power revenues | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 23.4 | 23.3 | 22.9 |
Other non-utility revenues | Other | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 0.1 | 0.1 | 1.7 |
Transferred over time | Other non-utility revenues | Wind generation revenues | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | 101 | 60.3 | 34.6 |
Transferred over time | Other non-utility revenues | Appliance service repairs | |||
Disaggregation of Operating Revenues | |||
Revenues from contracts with customers | $ 18.7 | $ 17.8 | $ 17.1 |
Operating Revenues - Other Oper
Operating Revenues - Other Operating Revenues (Details) - Other operating revenues - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Disaggregation of Operating Revenues | |||
Other operating revenues | $ 29.3 | $ 80.3 | $ 72.4 |
Late payment charges | |||
Disaggregation of Operating Revenues | |||
Other operating revenues | 55.6 | 54.9 | 29.4 |
Alternative revenues | |||
Disaggregation of Operating Revenues | |||
Other operating revenues | (30.3) | 21.2 | 38.8 |
Other | |||
Disaggregation of Operating Revenues | |||
Other operating revenues | $ 4 | $ 4.2 | $ 4.2 |
Credit Losses - Gross Receivabl
Credit Losses - Gross Receivables and Related Allowances (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 |
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable and unbilled revenues | $ 2,017.7 | $ 1,704 | ||
Allowance for credit losses | 199.3 | 198.3 | $ 220.1 | $ 140 |
Accounts receivable and unbilled revenues, net | 1,818.4 | 1,505.7 | ||
Total accounts receivable, net - past due greater than 90 days | $ 106.7 | $ 86.5 | ||
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms | 96.80% | 94.80% | ||
Amount of net accounts receivable with regulatory protections | $ 1,079.1 | |||
Percent of net accounts receivable with regulatory protections | 59.30% | |||
Public utilities | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable and unbilled revenues | $ 1,988 | $ 1,681.9 | ||
Allowance for credit losses | 199.3 | 198.3 | 220.1 | 139.9 |
Accounts receivable and unbilled revenues, net | 1,788.7 | 1,483.6 | ||
Total accounts receivable, net - past due greater than 90 days | $ 106.7 | $ 86.5 | ||
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms | 96.80% | 94.80% | ||
Wisconsin | Public utilities | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable and unbilled revenues | $ 1,199.4 | $ 1,053.1 | ||
Allowance for credit losses | 82 | 84 | 102.1 | 59.9 |
Accounts receivable and unbilled revenues, net | 1,117.4 | 969.1 | ||
Total accounts receivable, net - past due greater than 90 days | $ 51.9 | $ 46.5 | ||
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms | 97% | 97.60% | ||
Illinois | Public utilities | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable and unbilled revenues | $ 624.2 | $ 523.1 | ||
Allowance for credit losses | 111 | 105.5 | 111.6 | 75.9 |
Accounts receivable and unbilled revenues, net | 513.2 | 417.6 | ||
Total accounts receivable, net - past due greater than 90 days | $ 52.9 | $ 36.6 | ||
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms | 100% | 100% | ||
Other States | Public utilities | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable and unbilled revenues | $ 164.4 | $ 105.7 | ||
Allowance for credit losses | 6.3 | 8.8 | 6.4 | 4.1 |
Accounts receivable and unbilled revenues, net | 158.1 | 96.9 | ||
Total accounts receivable, net - past due greater than 90 days | $ 1.9 | $ 3.4 | ||
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms | 0% | 0% | ||
Non-Utility Energy Infrastructure | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable and unbilled revenues | $ 25.4 | $ 17 | ||
Allowance for credit losses | 0 | 0 | ||
Accounts receivable and unbilled revenues, net | 25.4 | 17 | ||
Total accounts receivable, net - past due greater than 90 days | $ 0 | $ 0 | ||
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms | 0% | 0% | ||
Corporate and Other | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable and unbilled revenues | $ 4.3 | $ 5.1 | ||
Allowance for credit losses | 0 | 0 | $ 0 | $ 0.1 |
Accounts receivable and unbilled revenues, net | 4.3 | 5.1 | ||
Total accounts receivable, net - past due greater than 90 days | $ 0 | $ 0 | ||
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms | 0% | 0% |
Credit Losses - Rollforward of
Credit Losses - Rollforward of Allowances (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | |||
Balance at Beginning of Year | $ 198.3 | $ 220.1 | $ 140 |
Provision for credit losses | 86.1 | 75.7 | 102.9 |
Provision for credit losses deferred for future recovery or refund | 62.9 | (13.1) | 55.2 |
Write-offs charged against the allowance | (206) | (129.8) | (132.3) |
Recovery of amounts previously written off | 58 | 45.4 | 54.4 |
Sale of PDL residential solar facilities | (0.1) | ||
Balance at End of Year | 199.3 | 198.3 | 220.1 |
Change in allowance for credit losses | 1 | ||
Public utilities | |||
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | |||
Balance at Beginning of Year | 198.3 | 220.1 | 139.9 |
Provision for credit losses | 86.1 | 75.7 | 102.9 |
Provision for credit losses deferred for future recovery or refund | 62.9 | (13.1) | 55.2 |
Write-offs charged against the allowance | (206) | (129.8) | (132.3) |
Recovery of amounts previously written off | 58 | 45.4 | 54.4 |
Sale of PDL residential solar facilities | 0 | ||
Balance at End of Year | 199.3 | 198.3 | 220.1 |
Wisconsin | Public utilities | |||
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | |||
Balance at Beginning of Year | 84 | 102.1 | 59.9 |
Provision for credit losses | 50.5 | 46.4 | 47.5 |
Provision for credit losses deferred for future recovery or refund | 29.7 | (16.6) | 24.6 |
Write-offs charged against the allowance | (117) | (74.8) | (65.9) |
Recovery of amounts previously written off | 34.8 | 26.9 | 36 |
Sale of PDL residential solar facilities | 0 | ||
Balance at End of Year | 82 | 84 | 102.1 |
Illinois | Public utilities | |||
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | |||
Balance at Beginning of Year | 105.5 | 111.6 | 75.9 |
Provision for credit losses | 33 | 25.6 | 51.1 |
Provision for credit losses deferred for future recovery or refund | 33.2 | 3.5 | 30.6 |
Write-offs charged against the allowance | (82.6) | (52.5) | (63) |
Recovery of amounts previously written off | 21.9 | 17.3 | 17 |
Sale of PDL residential solar facilities | 0 | ||
Balance at End of Year | 111 | 105.5 | 111.6 |
Other States | Public utilities | |||
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | |||
Balance at Beginning of Year | 8.8 | 6.4 | 4.1 |
Provision for credit losses | 2.6 | 3.7 | 4.3 |
Provision for credit losses deferred for future recovery or refund | 0 | 0 | 0 |
Write-offs charged against the allowance | (6.4) | (2.5) | (3.4) |
Recovery of amounts previously written off | 1.3 | 1.2 | 1.4 |
Sale of PDL residential solar facilities | 0 | ||
Balance at End of Year | 6.3 | 8.8 | 6.4 |
Corporate and Other | |||
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | |||
Balance at Beginning of Year | 0 | 0 | 0.1 |
Provision for credit losses | 0 | 0 | 0 |
Provision for credit losses deferred for future recovery or refund | 0 | 0 | 0 |
Write-offs charged against the allowance | 0 | 0 | 0 |
Recovery of amounts previously written off | 0 | 0 | 0 |
Balance at End of Year | $ 0 | $ 0 | 0 |
Corporate and Other | WPS Power Development, LLC Residential Solar Facilities | |||
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | |||
Sale of PDL residential solar facilities | $ (0.1) |
Regulatory Assets and Liabili_3
Regulatory Assets and Liabilities - Regulatory Assets (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | ||
Sep. 30, 2021 | Dec. 31, 2019 | Dec. 31, 2022 | Dec. 31, 2021 | |
Regulatory assets | ||||
Other current assets | $ 42.3 | $ 102.3 | ||
Regulatory assets | 3,264.6 | 3,264.8 | ||
Total regulatory assets | 3,306.9 | 3,367.1 | ||
Allowance for return on equity capitalized for regulatory purposes | 27.3 | 30.9 | ||
Regulatory assets not earning a return | 237.9 | |||
Regulatory assets earning a return based on short-term interest rates | 35.3 | |||
Regulatory assets earning a return based on long-term interest rates | 123.5 | |||
Estimated future cash expenditures for environmental remediation | 499.6 | 532.6 | ||
Pension and OPEB costs | ||||
Regulatory assets | ||||
Total regulatory assets | 714.3 | 802.3 | ||
Plant retirement related items | ||||
Regulatory assets | ||||
Total regulatory assets | 688.6 | 722.3 | ||
Environmental remediation costs | ||||
Regulatory assets | ||||
Total regulatory assets | 610.7 | 630.9 | ||
Cash expenditures for environmental remediation costs | 111.1 | |||
Estimated future cash expenditures for environmental remediation | 499.6 | |||
Income tax related items | ||||
Regulatory assets | ||||
Total regulatory assets | 461.9 | 458.8 | ||
Asset retirement obligations (AROs) | ||||
Regulatory assets | ||||
Total regulatory assets | 169.7 | 194.2 | ||
Derivatives | ||||
Regulatory assets | ||||
Total regulatory assets | 133.8 | 33.1 | ||
System support resource (SSR) | ||||
Regulatory assets | ||||
Total regulatory assets | 123.5 | 129.5 | ||
Recovery period of regulatory asset | 15 years | |||
Securitization | ||||
Regulatory assets | ||||
Total regulatory assets | 92.4 | 100.7 | ||
Uncollectible expense | ||||
Regulatory assets | ||||
Total regulatory assets | 69.3 | 42.6 | ||
MERC extraordinary natural gas costs | ||||
Regulatory assets | ||||
Total regulatory assets | 35.1 | 59.7 | ||
Recovery period of regulatory asset | 27 months | |||
Energy efficiency programs | ||||
Regulatory assets | ||||
Total regulatory assets | 33.9 | 22 | ||
Energy costs recoverable through rate adjustments | ||||
Regulatory assets | ||||
Total regulatory assets | 26.9 | 85.4 | ||
Other, net | ||||
Regulatory assets | ||||
Total regulatory assets | $ 146.8 | $ 85.6 |
Regulatory Assets and Liabili_4
Regulatory Assets and Liabilities - Regulatory Liabilities (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Regulatory liabilities | ||
Other current liabilities | $ 56.4 | $ 14.3 |
Regulatory liabilities | 3,735.5 | 3,946 |
Total regulatory liabilities | 3,791.9 | 3,960.3 |
Income tax related items | ||
Regulatory liabilities | ||
Total regulatory liabilities | 1,956.6 | 1,998.5 |
Removal costs | ||
Regulatory liabilities | ||
Total regulatory liabilities | 1,260.9 | 1,248 |
Pension and OPEB benefits | ||
Regulatory liabilities | ||
Total regulatory liabilities | 340.5 | 397.3 |
Derivatives | ||
Regulatory liabilities | ||
Total regulatory liabilities | 76.7 | 124.1 |
Energy costs refundable through rate adjustments | ||
Regulatory liabilities | ||
Total regulatory liabilities | 53.4 | 13.7 |
Uncollectible expense | ||
Regulatory liabilities | ||
Total regulatory liabilities | 24 | 37.1 |
Earnings sharing mechanisms | ||
Regulatory liabilities | ||
Total regulatory liabilities | 12.9 | 28.4 |
Electric transmission costs | ||
Regulatory liabilities | ||
Total regulatory liabilities | 0.4 | 84.2 |
Amortization of transmission regulatory liabilities | 81 | |
Other, net | ||
Regulatory liabilities | ||
Total regulatory liabilities | $ 66.5 | $ 29 |
Regulatory Assets and Liabili_5
Regulatory Assets and Liabilities - Plant Retirements (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2019 |
Regulatory assets | |||
Total regulatory assets | $ 3,306.9 | $ 3,367.1 | |
Deferred tax liabilities | 4,072.5 | 3,909 | |
Securitization | |||
Regulatory assets | |||
Total regulatory assets | 92.4 | $ 100.7 | |
Edgewater Unit 4 | |||
Regulatory assets | |||
Total regulatory assets | 3.2 | ||
Pleasant Prairie power plant | |||
Regulatory assets | |||
Net book value of retired plant | 575.1 | ||
Deferred unprotected tax benefits | 17.5 | ||
Total regulatory assets | 557.6 | ||
Deferred tax liabilities | 156.7 | ||
Pleasant Prairie power plant | Securitization | |||
Regulatory assets | |||
Total regulatory assets | $ 100 | ||
Presque Isle power plant | |||
Regulatory assets | |||
Net book value of retired plant | 163.7 | ||
Deferred unprotected tax benefits | 5.2 | ||
Total regulatory assets | 158.5 | ||
Deferred tax liabilities | 44.4 | ||
Pulliam power plant | |||
Regulatory assets | |||
Total regulatory assets | $ 36.6 |
Property, Plant, and Equipmen_2
Property, Plant, and Equipment - Balances (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Property, plant, and equipment | ||
Accumulated depreciation | $ 10,383.8 | $ 9,889.3 |
Net property, plant, and equipment | 29,113.8 | 26,982.4 |
OCPP generating units 5-8 | WE | ||
Property, plant, and equipment | ||
Net book value of plant to be retired | 812.5 | |
Columbia generating unit 1 | WPS | ||
Property, plant, and equipment | ||
Net book value of plant to be retired | 84 | |
Columbia generating unit 2 | WPS | ||
Property, plant, and equipment | ||
Net book value of plant to be retired | 189.1 | |
Regulated operations | ||
Property, plant, and equipment | ||
Accumulated depreciation | 8,416.2 | 8,894.9 |
Net | 22,889.2 | 21,957.4 |
CWIP | 972.1 | 406 |
Net property, plant, and equipment | 23,861.3 | 22,363.4 |
Regulated operations | Electric - generation | ||
Property, plant, and equipment | ||
Property, plant, and equipment | 5,480.5 | 6,981.4 |
Regulated operations | Electric - distribution | ||
Property, plant, and equipment | ||
Property, plant, and equipment | 8,233.3 | 7,854.7 |
Regulated operations | Natural gas - distribution, storage, and transmission | ||
Property, plant, and equipment | ||
Property, plant, and equipment | 14,203.3 | 13,526.6 |
Regulated operations | Property, plant, and equipment to be retired, net | ||
Property, plant, and equipment | ||
Property, plant, and equipment to be retired, net | 1,085.6 | 277 |
Regulated operations | Other | ||
Property, plant, and equipment | ||
Property, plant, and equipment | 2,302.7 | 2,212.6 |
Non-regulated operations | ||
Property, plant, and equipment | ||
Accumulated depreciation | 1,082.3 | 994.4 |
Net | 5,170.9 | 4,589.2 |
CWIP | 81.6 | 29.8 |
Net property, plant, and equipment | 5,252.5 | 4,619 |
Non-regulated operations | Other | ||
Property, plant, and equipment | ||
Property, plant, and equipment | 23.8 | 27 |
Non-regulated operations | We Power generation | ||
Property, plant, and equipment | ||
Property, plant, and equipment | 3,237.1 | 3,240.5 |
Non-regulated operations | Renewable generation | ||
Property, plant, and equipment | ||
Property, plant, and equipment | 2,537.1 | 1,837.5 |
Non-regulated operations | Natural gas storage | ||
Property, plant, and equipment | ||
Property, plant, and equipment | 292.2 | 289.9 |
Non-regulated operations | Corporate services | ||
Property, plant, and equipment | ||
Property, plant, and equipment | 163 | 188.7 |
Non-Utility Energy Infrastructure | Non-regulated operations | ||
Property, plant, and equipment | ||
Property, plant, and equipment | $ 6,066.4 | $ 5,367.9 |
Property, Plant, and Equipmen_3
Property, Plant, and Equipment - Severance Liability (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Property, Plant and Equipment [Abstract] | |||
Severance liability at January 1 | $ 4.9 | $ 0.7 | $ 2.1 |
Severance expense | 11.3 | 4.6 | 0 |
Severance payments | 0 | (0.4) | (0.1) |
Other | 0 | 0 | (1.3) |
Severance liability at December 31 | $ 16.2 | $ 4.9 | $ 0.7 |
Property, Plant, and Equipmen_4
Property, Plant, and Equipment - Public Service Building (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2022 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Property, plant, and equipment | ||||
Proceeds from insurance settlement | $ 41.6 | $ 0 | $ 23.2 | |
Building | WE | ||||
Property, plant, and equipment | ||||
Costs incurred for repairs and restorations | 95.3 | |||
Proceeds from insurance settlement | $ 41 | 20 | ||
Costs included in other operation and maintenance | $ 12.5 | |||
Repairs and restorations to be recovered through rates | $ 21.8 |
Jointly Owned Utility Facilit_3
Jointly Owned Utility Facilities (Details) $ in Millions | Dec. 31, 2022 USD ($) MW |
Elm Road Generating Station Units 1 and 2 | We Power | |
Jointly owned utility facilities | |
Joint plant ownership percentage | 83.34% |
Share of capacity (MW) | MW | 1,060.8 |
Property, plant, and equipment | $ 2,425.1 |
Accumulated depreciation | (505.7) |
Construction work in progress | $ 64.1 |
Weston Unit 4 | WPS | |
Jointly owned utility facilities | |
Joint plant ownership percentage | 70% |
Share of capacity (MW) | MW | 387.3 |
Property, plant, and equipment | $ 612.1 |
Accumulated depreciation | (213) |
Construction work in progress | $ 1.2 |
Columbia Energy Center Units 1 and 2 | WPS | |
Jointly owned utility facilities | |
Joint plant ownership percentage | 27.50% |
Share of capacity (MW) | MW | 311.1 |
Property, plant, and equipment | $ 426.1 |
Accumulated depreciation | (159.7) |
Construction work in progress | $ 6.8 |
Forward Wind Energy Center | WPS | |
Jointly owned utility facilities | |
Joint plant ownership percentage | 44.60% |
Share of capacity (MW) | MW | 61.5 |
Property, plant, and equipment | $ 119.3 |
Accumulated depreciation | (53.9) |
Construction work in progress | $ 0.2 |
Two Creeks | WPS | |
Jointly owned utility facilities | |
Joint plant ownership percentage | 66.70% |
Share of capacity (MW) | MW | 100 |
Property, plant, and equipment | $ 136.8 |
Accumulated depreciation | (9.7) |
Construction work in progress | $ 0.1 |
Badger Hollow I | WPS | |
Jointly owned utility facilities | |
Joint plant ownership percentage | 66.70% |
Share of capacity (MW) | MW | 100 |
Property, plant, and equipment | $ 146.2 |
Accumulated depreciation | (4.9) |
Construction work in progress | $ 0 |
Badger Hollow II | WE | |
Jointly owned utility facilities | |
Joint plant ownership percentage | 66.70% |
Share of capacity (MW) | MW | 100 |
Construction work in progress | $ 107.5 |
Paris | WE and WPS | |
Jointly owned utility facilities | |
Joint plant ownership percentage | 90% |
Jointly owned utility plant, proportionate ownership share of solar capacity | MW | 180 |
Jointly owned utility plant, proportionate ownership share of battery storage | MW | 99 |
Construction work in progress | $ 207.6 |
Darien | WE and WPS | |
Jointly owned utility facilities | |
Joint plant ownership percentage | 90% |
Jointly owned utility plant, proportionate ownership share of solar capacity | MW | 225 |
Jointly owned utility plant, proportionate ownership share of battery storage | MW | 68 |
Construction work in progress | $ 9.4 |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Changes to asset retirement obligations | |||
Balance as of January 1 | $ 462 | $ 513.5 | $ 483.5 |
Accretion | 16.1 | 21.2 | 20.7 |
Additions and revisions to estimated cash flows | 15 | (53.9) | 39.7 |
Liabilities settled | (13.8) | (18.8) | (30.4) |
Balance as of December 31 | 479.3 | 462 | 513.5 |
Thunderhead | Wind and solar generation projects | |||
Changes to asset retirement obligations | |||
ARO additions | 12.1 | ||
PGL and NSG | Natural gas distribution pipe | |||
Changes to asset retirement obligations | |||
ARO increase (decrease) due to revisions made to estimated cash flows | $ 1.9 | ||
PGL and NSG | Natural gas distribution lines | |||
Changes to asset retirement obligations | |||
ARO additions | 50.7 | ||
ARO increase (decrease) due to revisions made to estimated cash flows | (152) | ||
WPS, Tatanka, and Jayhawk | Wind and solar generation projects | |||
Changes to asset retirement obligations | |||
ARO additions | 26.3 | ||
WE and WPS | Wind and solar generation projects | |||
Changes to asset retirement obligations | |||
ARO increase (decrease) due to revisions made to estimated cash flows | 7.8 | ||
WPS | Fly ash landfills and ash ponds | |||
Changes to asset retirement obligations | |||
ARO increase (decrease) due to revisions made to estimated cash flows | $ 6.8 | ||
PGL | Natural gas distribution lines | |||
Changes to asset retirement obligations | |||
ARO additions | 39.3 | ||
Two Creeks | Wind and solar generation projects | |||
Changes to asset retirement obligations | |||
ARO additions | 8.5 | ||
WE | Abatement of asbestos | |||
Changes to asset retirement obligations | |||
ARO increase (decrease) due to revisions made to estimated cash flows | $ (9.2) |
Goodwill and Intangibles - Good
Goodwill and Intangibles - Goodwill (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |
Sep. 30, 2022 | Dec. 31, 2022 | Dec. 31, 2021 | |
Goodwill | |||
Changes to the carrying amount of goodwill | $ 0 | $ 0 | |
Goodwill | 3,052.8 | 3,052.8 | |
Accumulated impairment losses | 0 | ||
Goodwill impairment loss | $ 0 | ||
Wisconsin | |||
Goodwill | |||
Goodwill | 2,104.3 | 2,104.3 | |
Illinois | |||
Goodwill | |||
Goodwill | 758.7 | 758.7 | |
Other States | |||
Goodwill | |||
Goodwill | 183.2 | 183.2 | |
Non-Utility Energy Infrastructure | |||
Goodwill | |||
Goodwill | $ 6.6 | $ 6.6 |
Goodwill and Intangibles - Inde
Goodwill and Intangibles - Indefinite Lived Intangible Assets (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Indefinite-lived Intangible Assets | ||
Indefinite-lived intangible assets | $ 24.9 | $ 5.7 |
Spectrum Frequencies | ||
Indefinite-lived Intangible Assets | ||
Changes to the carrying amount of indefinite-lived intangible asset | 19.2 | |
MGU | Trade name | ||
Indefinite-lived Intangible Assets | ||
Indefinite-lived intangible assets | $ 5.7 |
Goodwill and Intangibles - Inta
Goodwill and Intangibles - Intangible Liabilities (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Finite-Lived Intangible Assets | |||
Amortization | $ 11.3 | $ 7.5 | $ 0.8 |
Period of amortization | 5 years | ||
Amortization to be recorded as an increase to operating revenues | |||
Amortization to be recorded in the next five years | |||
2023 | $ 29.8 | ||
2024 | 29.8 | ||
2025 | 29.8 | ||
2026 | 29.8 | ||
2027 | 29.8 | ||
Amortization to be recorded as a decrease to other operation and maintenance | |||
Amortization to be recorded in the next five years | |||
2023 | 0.2 | ||
2024 | 0.2 | ||
2025 | 0.2 | ||
2026 | 0.2 | ||
2027 | 0.2 | ||
WECI | |||
Finite-Lived Intangible Assets | |||
Gross Carrying Amount | 355.8 | 99.8 | |
Accumulated Amortization | (20.4) | (9.1) | |
Net Carrying Amount | 335.4 | 90.7 | |
PPAs | WECI | |||
Finite-Lived Intangible Assets | |||
Gross Carrying Amount | 343.9 | 87.9 | |
Accumulated Amortization | (16.9) | (6.5) | |
Net Carrying Amount | $ 327 | 81.4 | |
PPAs | Blooming Grove Wind Energy Center LLC, Tatanka Ridge Wind, LLC, and Jayhawk Wind, LLC | |||
Finite-Lived Intangible Assets | |||
Weighted average useful life | 11 years | ||
Proxy revenue swap | WECI | |||
Finite-Lived Intangible Assets | |||
Gross Carrying Amount | $ 7.2 | 7.2 | |
Accumulated Amortization | (2.8) | (2.1) | |
Net Carrying Amount | $ 4.4 | 5.1 | |
Proxy revenue swap | Upstream Wind Energy LLC | |||
Finite-Lived Intangible Assets | |||
Weighted average useful life | 6 years | ||
Length of proxy revenue contract, in years | 10 years | ||
Interconnection agreements | WECI | |||
Finite-Lived Intangible Assets | |||
Gross Carrying Amount | $ 4.7 | 4.7 | |
Accumulated Amortization | (0.7) | (0.5) | |
Net Carrying Amount | $ 4 | $ 4.2 | |
Interconnection agreements | Tatanka Ridge Wind LLC and Bishop Hill Energy III LLC | |||
Finite-Lived Intangible Assets | |||
Weighted average useful life | 18 years |
Common Equity - Stock-Based Com
Common Equity - Stock-Based Compensation Expense (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Share Based Compensation Arrangement By Share Based Payment Award | |||
Stock-based compensation expense | $ 34.8 | $ 15.7 | $ 35.7 |
Related tax benefit | 9.6 | 4.3 | 9.8 |
Stock options | |||
Share Based Compensation Arrangement By Share Based Payment Award | |||
Stock-based compensation expense | 6.5 | 6.5 | 6 |
Restricted stock | |||
Share Based Compensation Arrangement By Share Based Payment Award | |||
Stock-based compensation expense | 7 | 6.1 | 7.4 |
Performance units | |||
Share Based Compensation Arrangement By Share Based Payment Award | |||
Stock-based compensation expense | $ 21.3 | $ 3.1 | $ 22.3 |
Common Equity - Stock Options (
Common Equity - Stock Options (Details) - Stock options - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Options Activity | ||||
Outstanding, shares, beginning balance | 2,909,939 | 3,111,907 | ||
Granted, shares | 437,269 | 530,612 | 554,594 | |
Exercised, shares | (622,459) | |||
Forfeited, shares | (16,778) | |||
Outstanding, shares, ending balance | 2,909,939 | 3,111,907 | ||
Options - Weighted Average Exercise Price | ||||
Outstanding, Weighted-Average Exercise Price, Beginning | $ 77.03 | $ 69.84 | ||
Granted, Weighted-Average Exercise Price | 96.04 | |||
Exercised, Weighted-Average Exercise Price | 54.05 | |||
Forfeited, Weighted-Average Exercise Price | 92.16 | |||
Outstanding, Weighted-Average Exercise Price, Ending | $ 77.03 | $ 69.84 | ||
Options - Additional Disclosures | ||||
Outstanding, Weighted-Average Remaining Contractual Life (Years) | 6 years 2 months 12 days | |||
Outstanding, Aggregate Intrinsic Value | $ 49.7 | |||
Exercisable, shares | 1,807,644 | |||
Exercisable, Weighted-Average Exercise Price (in dollars per share) | $ 67.40 | |||
Exercisable, Weighted-Average Remaining Contractual Life (Years) | 5 years | |||
Exercisable, Aggregate Intrinsic Value | $ 47.8 | |||
Intrinsic value of options exercised | 29.2 | $ 12.9 | $ 47.1 | |
Tax benefit from option exercises | 8 | $ 3.5 | $ 12.9 | |
Compensation cost not yet recognized | $ 2.3 | |||
Weighted-average period over which unrecognized compensation cost is expected to be recognized | 1 year 6 months | |||
Estimated weighted-average fair value per stock option (in dollars per share) | $ 14.71 | $ 13.20 | $ 10.94 | |
Subsequent event | ||||
Options Activity | ||||
Granted, shares | 257,780 | |||
Options - Weighted Average Exercise Price | ||||
Granted, Weighted-Average Exercise Price | $ 93.69 | |||
Options - Additional Disclosures | ||||
Estimated weighted-average fair value per stock option (in dollars per share) | $ 19.58 |
Common Equity - Restricted Shar
Common Equity - Restricted Shares (Details) - Restricted stock - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Restricted Stock Activity | ||||
Outstanding, shares, beginning of period | 89,885 | 99,061 | ||
Granted, shares | 72,211 | |||
Released, shares | (76,109) | |||
Forfeited, shares | (5,278) | |||
Outstanding, shares, end of period | 89,885 | 99,061 | ||
Restricted Stock Weighted-Average Grant Date Fair Value | ||||
Outstanding, weighted-average grant date fair value, beginning of period | $ 94.73 | $ 88.89 | ||
Granted, weighted-average grant date fair value | 96.04 | |||
Released, weighted-average grant date fair value | 88.51 | |||
Forfeited, weighted-average grant date fair value | 92.80 | |||
Outstanding, weighted-average grant date fair value, end of period | $ 94.73 | $ 88.89 | ||
Restricted Stock - Additional Disclosures | ||||
Intrinsic value of released restricted shares | $ 7.5 | $ 6.5 | $ 11.1 | |
Tax benefit from released restricted shares | 2.1 | $ 1.8 | $ 3.1 | |
Compensation cost not yet recognized | $ 2.8 | |||
Weighted-average period over which unrecognized compensation cost is expected to be recognized | 1 year 8 months 12 days | |||
Subsequent event | ||||
Restricted Stock Activity | ||||
Granted, shares | 75,453 | |||
Restricted Stock Weighted-Average Grant Date Fair Value | ||||
Granted, weighted-average grant date fair value | $ 93.69 |
Common Equity - Performance Uni
Common Equity - Performance Units (Details) - Performance units - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Share-based Compensation Arrangement by Share-based Payment Award | ||||
Performance units granted | 171,492 | 152,382 | 153,465 | |
Intrinsic value of settled performance units | $ 20.2 | $ 27.7 | $ 34.5 | |
Tax benefit from distribution of performance units | $ 5.1 | $ 6.8 | $ 8.4 | |
Performance units outstanding | 375,834 | |||
Liability recorded on balance sheet | $ 22.4 | |||
Compensation cost not yet recognized | $ 13.5 | |||
Weighted-average period over which unrecognized compensation cost is expected to be recognized | 1 year 8 months 12 days | |||
Subsequent event | ||||
Share-based Compensation Arrangement by Share-based Payment Award | ||||
Performance units granted | 157,035 | |||
Intrinsic value of settled performance units | $ 9.7 | |||
Tax benefit from distribution of performance units | $ 2.4 |
Common Equity - Dividend Restri
Common Equity - Dividend Restrictions (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 USD ($) period | Dec. 31, 2021 | |
Dividend Payment Restrictions | ||
Junior notes minimum interest deferral payment period (in periods) | period | 1 | |
Junior notes maximum interest payment deferral period (in years) | 10 years | |
Restricted net assets of consolidated subsidiaries | $ 9,800 | |
Undistributed earnings of investees accounted for by the equity method | $ 487 | |
WE | ||
Dividend Payment Restrictions | ||
Maximum debt to capitalization ratio | 65% | |
WE | 3.60% Serial Preferred Stock | ||
Dividend Payment Restrictions | ||
Dividend rate (as a percent) | 3.60% | 3.60% |
WE | 3.60% Serial Preferred Stock | Common stock equity to total capitalization is between 25% and 20% | ||
Dividend Payment Restrictions | ||
Period of dividend restrictions | 12 months | |
WE | 3.60% Serial Preferred Stock | Common stock equity to total capitalization is less than 20% | ||
Dividend Payment Restrictions | ||
Period of dividend restrictions | 12 months | |
WE | 3.60% Serial Preferred Stock | Minimum | Common stock equity to total capitalization is between 25% and 20% | ||
Dividend Payment Restrictions | ||
Percentage of common equity to total capitalization required to be maintained | 20% | |
WE | 3.60% Serial Preferred Stock | Maximum | Common stock equity to total capitalization is between 25% and 20% | ||
Dividend Payment Restrictions | ||
Percentage of net income for which dividends can be declared | 75% | |
Percentage of common equity to total capitalization required to be maintained | 25% | |
WE | 3.60% Serial Preferred Stock | Maximum | Common stock equity to total capitalization is less than 20% | ||
Dividend Payment Restrictions | ||
Percentage of net income for which dividends can be declared | 50% | |
Percentage of common equity to total capitalization required to be maintained | 20% | |
WE | Public Service Commission of Wisconsin | Minimum | ||
Dividend Payment Restrictions | ||
Common equity ratio required to be maintained (as a percent) | 53% | |
WPS | ||
Dividend Payment Restrictions | ||
Maximum debt to capitalization ratio | 65% | |
WPS | Public Service Commission of Wisconsin | Minimum | ||
Dividend Payment Restrictions | ||
Common equity ratio required to be maintained (as a percent) | 53% | |
WG | Public Service Commission of Wisconsin | Minimum | ||
Dividend Payment Restrictions | ||
Common equity ratio required to be maintained (as a percent) | 53% | |
UMERC | ||
Dividend Payment Restrictions | ||
Maximum debt to capitalization ratio | 65% | |
Bluewater Gas Storage, LLC | ||
Dividend Payment Restrictions | ||
Maximum debt to capitalization ratio | 65% | |
ATC Holding LLC | ||
Dividend Payment Restrictions | ||
Maximum debt to capitalization ratio | 65% | |
WECI Wind Holding I | ||
Dividend Payment Restrictions | ||
Minimum debt service ratio to be maintained for 12-months prior to distribution | 1.2 | |
Period needed to maintain minimum debt service coverage ratio | 12 months | |
WECI Wind Holding II | ||
Dividend Payment Restrictions | ||
Minimum debt service ratio to be maintained for 12-months prior to distribution | 1.2 | |
Period needed to maintain minimum debt service coverage ratio | 12 months |
Common Equity - Share Repurchas
Common Equity - Share Repurchase Program (Details) - USD ($) shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Stockholders' Equity Note [Abstract] | |||
New shares of common stock issued | 0 | 0 | 0 |
Shares purchased | 0.7 | 0.4 | 1 |
Cost of shares purchased | $ 69.2 | $ 33.1 | $ 99.2 |
Common Equity - Common Stock Di
Common Equity - Common Stock Dividends (Details) - $ / shares | 3 Months Ended | 12 Months Ended | |||||||
Jan. 19, 2023 | Dec. 31, 2022 | Sep. 30, 2022 | Jun. 30, 2022 | Mar. 31, 2022 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Dividends Paid and Payable | |||||||||
Dividends per share (in dollars per share) | $ 0.7275 | $ 0.7275 | $ 0.7275 | $ 0.7275 | $ 2.91 | $ 2.71 | $ 2.53 | ||
Subsequent event | |||||||||
Dividends Paid and Payable | |||||||||
Dividends per share (in dollars per share) | $ 0.78 | ||||||||
Annualized dividend (in dollars per share) | $ 3.12 | ||||||||
Subsequent event | Minimum | |||||||||
Dividends Paid and Payable | |||||||||
Target dividend payout ratio (as a percent) | 65% | ||||||||
Subsequent event | Maximum | |||||||||
Dividends Paid and Payable | |||||||||
Target dividend payout ratio (as a percent) | 70% |
Preferred Stock (Details)
Preferred Stock (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | ||
Total preferred stock value issued | $ 30.4 | $ 30.4 |
WEC Energy Group | $.01 par value Preferred Stock | ||
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | ||
Par or stated value per share | $ 0.01 | $ 0.01 |
Shares authorized | 15,000,000 | 15,000,000 |
Shares outstanding | 0 | 0 |
Redemption price per share | $ 0 | $ 0 |
Total preferred stock value issued | $ 0 | $ 0 |
WE | $100 par value, Six Per Cent. Preferred Stock | ||
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | ||
Par or stated value per share | $ 100 | $ 100 |
Dividend rate (as a percent) | 6% | 6% |
Shares authorized | 45,000 | 45,000 |
Shares outstanding | 44,498 | 44,498 |
Redemption price per share | $ 0 | $ 0 |
Total preferred stock value issued | $ 4.4 | $ 4.4 |
WE | $100 par value, Serial Preferred Stock, 3.60% series | ||
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | ||
Par or stated value per share | $ 100 | $ 100 |
Dividend rate (as a percent) | 3.60% | 3.60% |
Shares authorized | 2,286,500 | 2,286,500 |
Shares outstanding | 260,000 | 260,000 |
Redemption price per share | $ 101 | $ 101 |
Total preferred stock value issued | $ 26 | $ 26 |
WE | $25 par value, Serial Preferred Stock | ||
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | ||
Par or stated value per share | $ 25 | $ 25 |
Shares authorized | 5,000,000 | 5,000,000 |
Shares outstanding | 0 | 0 |
Redemption price per share | $ 0 | $ 0 |
Total preferred stock value issued | $ 0 | $ 0 |
WPS | $100 par value, Preferred Stock | ||
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | ||
Par or stated value per share | $ 100 | $ 100 |
Shares authorized | 1,000,000 | 1,000,000 |
Shares outstanding | 0 | 0 |
Redemption price per share | $ 0 | $ 0 |
Total preferred stock value issued | $ 0 | $ 0 |
PGL | $100 par value, Cumulative Preferred Stock | ||
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | ||
Par or stated value per share | $ 100 | $ 100 |
Shares authorized | 430,000 | 430,000 |
Shares outstanding | 0 | 0 |
Redemption price per share | $ 0 | $ 0 |
Total preferred stock value issued | $ 0 | $ 0 |
NSG | $100 par value, Cumulative Preferred Stock | ||
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | ||
Par or stated value per share | $ 100 | $ 100 |
Shares authorized | 160,000 | 160,000 |
Shares outstanding | 0 | 0 |
Redemption price per share | $ 0 | $ 0 |
Total preferred stock value issued | $ 0 | $ 0 |
Short-Term Debt and Lines of _3
Short-Term Debt and Lines of Credit - Outstanding Amounts (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | |||
Mar. 31, 2021 | Mar. 31, 2020 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Short-term Debt [Line Items] | |||||
Issuance of short-term loan | $ 2.7 | $ 0.9 | $ 340 | ||
WE | |||||
Short-term Debt [Line Items] | |||||
Maximum debt to capitalization ratio | 65% | ||||
WPS | |||||
Short-term Debt [Line Items] | |||||
Maximum debt to capitalization ratio | 65% | ||||
WG | |||||
Short-term Debt [Line Items] | |||||
Maximum debt to capitalization ratio | 65% | ||||
PGL | |||||
Short-term Debt [Line Items] | |||||
Maximum debt to capitalization ratio | 65% | ||||
WEC Energy Group | |||||
Short-term Debt [Line Items] | |||||
Commercial paper outstanding | $ 399.7 | 736.1 | |||
Issuance of short-term loan | $ 0 | 0 | $ 340 | ||
Maximum debt to capitalization ratio | 70% | ||||
WEC Energy Group | WEC Senior Notes 0.80% due 2024 | |||||
Short-term Debt [Line Items] | |||||
Interest rate | 0.80% | ||||
Issuance of debt | $ 600 | ||||
Commercial paper | |||||
Short-term Debt [Line Items] | |||||
Commercial paper outstanding | $ 1,643.5 | $ 1,896.1 | |||
Average interest rate on amount outstanding | 4.64% | 0.26% | |||
Average amount outstanding during the year | $ 1,487.2 | ||||
Weighted- average interest rate during the year | 1.98% | ||||
Operating expense loans | |||||
Short-term Debt [Line Items] | |||||
Operating expense loan outstanding | $ 3.6 | $ 0.9 | |||
Term loan | |||||
Short-term Debt [Line Items] | |||||
Issuance of short-term loan | $ 340 | ||||
Length of term loan | 364 days |
Short-Term Debt and Lines of _4
Short-Term Debt and Lines of Credit - Credit Facilities (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 USD ($) extension | Dec. 31, 2021 USD ($) | |
Line of Credit Facility [Line Items] | ||
Short-term credit capacity | $ 3,100 | |
Available capacity under existing agreements | $ 1,454.2 | |
Number of extensions available on a credit facility | extension | 2 | |
Length of credit facility extension | 1 year | |
WE | Credit facility maturing September 2026 | ||
Line of Credit Facility [Line Items] | ||
Short-term credit capacity | $ 500 | |
Number of extensions available on a credit facility | extension | 2 | |
Length of credit facility extension | 1 year | |
WPS | Credit facility maturing September 2026 | ||
Line of Credit Facility [Line Items] | ||
Short-term credit capacity | $ 400 | |
Number of extensions available on a credit facility | extension | 2 | |
Length of credit facility extension | 1 year | |
WG | Credit facility maturing September 2026 | ||
Line of Credit Facility [Line Items] | ||
Short-term credit capacity | $ 350 | |
Number of extensions available on a credit facility | extension | 2 | |
Length of credit facility extension | 1 year | |
PGL | Credit facility maturing September 2026 | ||
Line of Credit Facility [Line Items] | ||
Short-term credit capacity | $ 350 | |
Number of extensions available on a credit facility | extension | 2 | |
Length of credit facility extension | 1 year | |
WEC Energy Group | ||
Line of Credit Facility [Line Items] | ||
Commercial paper outstanding | $ 399.7 | $ 736.1 |
WEC Energy Group | Credit facility maturing September 2026 | ||
Line of Credit Facility [Line Items] | ||
Short-term credit capacity | $ 1,500 | |
Number of extensions available on a credit facility | extension | 2 | |
Length of credit facility extension | 1 year | |
Letter of Credit | ||
Line of Credit Facility [Line Items] | ||
Letters of credit issued inside credit facilities | $ 2.3 | |
Commercial paper | ||
Line of Credit Facility [Line Items] | ||
Commercial paper outstanding | $ 1,643.5 | $ 1,896.1 |
Long-Term Debt - Debt Outstandi
Long-Term Debt - Debt Outstanding (Details) $ in Millions | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | Nov. 15, 2021 USD ($) number_of_interest_rate_swaps |
Long-term debt | |||
Total | $ 15,559.8 | $ 13,652.6 | |
Integrys acquisition fair value adjustment | 1.2 | 2.9 | |
Long-term debt, including current portion | 15,464.2 | 13,563.4 | |
Unamortized debt issuance costs | (81.8) | (77.7) | |
Unamortized discount, net and other | (22.3) | (21.7) | |
Current portion of long-term debt | (808.5) | (91) | |
Long-term debt | 14,655.7 | 13,472.4 | |
Finance lease obligation | $ 183.2 | $ 129.7 | |
WE | |||
Long-term debt | |||
Weighted average interest rate | 4.22% | 4.13% | |
Unsecured debt | $ 3,285 | $ 2,785 | |
WEPCo Environmental Trust Finance I, LLC | |||
Long-term debt | |||
Weighted average interest rate | 1.58% | 1.58% | |
Secured debt | $ 105.9 | $ 114.7 | |
WPS | |||
Long-term debt | |||
Weighted average interest rate | 4.11% | 3.89% | |
Senior notes | $ 1,975 | $ 1,675 | |
WG | |||
Long-term debt | |||
Weighted average interest rate | 3.35% | 3.35% | |
Unsecured debt | $ 790 | $ 790 | |
Integrys | 6.00% Integrys junior notes | |||
Long-term debt | |||
Weighted average interest rate | 6% | 6% | |
Unsecured debt | $ 221.4 | $ 221.4 | |
PGL | |||
Long-term debt | |||
Weighted average interest rate | 3.41% | 3.31% | |
Secured debt | $ 1,970 | $ 1,870 | |
PGL | Collateralized First Mortgage Bonds | |||
Long-term debt | |||
Secured debt | $ 100 | ||
NSG | |||
Long-term debt | |||
Weighted average interest rate | 3.56% | 3.56% | |
Secured debt | $ 157 | $ 157 | |
MERC | |||
Long-term debt | |||
Weighted average interest rate | 3.04% | 3.04% | |
Senior notes | $ 210 | $ 210 | |
MGU | |||
Long-term debt | |||
Weighted average interest rate | 3.18% | 3.18% | |
Senior notes | $ 150 | $ 150 | |
UMERC | |||
Long-term debt | |||
Weighted average interest rate | 3.26% | 3.26% | |
Senior notes | $ 160 | $ 160 | |
Bluewater Gas Storage | |||
Long-term debt | |||
Weighted average interest rate | 3.76% | 3.76% | |
Senior notes | $ 112.6 | $ 115.2 | |
ATC Holding LLC | |||
Long-term debt | |||
Weighted average interest rate | 4.05% | 4.05% | |
Senior notes | $ 475 | $ 475 | |
We Power | |||
Long-term debt | |||
Weighted average interest rate | 5.62% | 5.60% | |
Secured debt | $ 896.5 | $ 934.7 | |
WECC | |||
Long-term debt | |||
Weighted average interest rate | 6.94% | 6.94% | |
Unsecured debt | $ 50 | $ 50 | |
WECI Wind Holding I | |||
Long-term debt | |||
Weighted average interest rate | 2.75% | 2.75% | |
Senior notes | $ 332.1 | $ 374.6 | |
WECI Wind Holding II | |||
Long-term debt | |||
Weighted average interest rate | 6.38% | 0% | |
Senior notes | $ 199.3 | $ 0 | |
Jayhawk Wind LLC | |||
Long-term debt | |||
Long-term debt, including current portion | $ 7.3 | $ 7.3 | |
WEC Energy Group | |||
Long-term debt | |||
Weighted average interest rate | 2.44% | 1.67% | |
Senior notes | $ 3,970 | $ 3,070 | |
Current portion of long-term debt | (700) | 0 | |
Long-term debt | $ 3,747.2 | $ 3,549.8 | |
WEC Energy Group | WEC Energy Group junior notes due 2067 | |||
Long-term debt | |||
Weighted average interest rate | 6.72% | 2.27% | |
Unsecured debt | $ 500 | $ 500 | $ 500 |
Interest rate | 6.72% | 2.27% | |
WEC Energy Group | 6.20% WEC Energy Group senior notes | |||
Long-term debt | |||
Interest rate | 6.20% | ||
WEC Energy Group | Interest rate swaps | |||
Long-term debt | |||
Number of interest rate swaps executed | number_of_interest_rate_swaps | 2 | ||
Interest rate swap fixed interest rate | 4.9765% | ||
Interest rate swap notional value | $ 250 |
Long-Term Debt - Issuances and
Long-Term Debt - Issuances and Redemptions (Details) - USD ($) $ in Millions | 1 Months Ended | |||
Jan. 31, 2023 | Dec. 31, 2022 | Nov. 30, 2022 | Sep. 30, 2022 | |
WE 4.75% Debentures due September 30, 2032 | WE | ||||
Long-term debt | ||||
Issuance of debt | $ 500 | |||
Interest rate | 4.75% | |||
WPS 5.35% Senior Notes due November 10, 2025 | WPS | ||||
Long-term debt | ||||
Issuance of debt | $ 300 | |||
Interest rate | 5.35% | |||
5.23% PGL Series MMM due December 1, 2027 | PGL | ||||
Long-term debt | ||||
Issuance of debt | $ 100 | |||
Interest rate | 5.23% | |||
6.38% WECI Wind Holding II LLC Senior Notes Due 2031 | WECI Wind Holding II | ||||
Long-term debt | ||||
Issuance of debt | $ 199.3 | |||
Interest rate | 6.38% | |||
WEC Energy Group | WEC 5.00% Senior Notes Due September 27, 2025 | ||||
Long-term debt | ||||
Issuance of debt | $ 500 | |||
Interest rate | 5% | |||
WEC Energy Group | WEC 5.15% Senior Notes Due October 1, 2027 | ||||
Long-term debt | ||||
Issuance of debt | $ 400 | |||
Interest rate | 5.15% | |||
WEC Energy Group | WEC 4.75% Senior Notes due January 9, 2026 | Subsequent event | ||||
Long-term debt | ||||
Issuance of debt | $ 650 | |||
Interest rate | 4.75% | |||
WEC Energy Group | WEC 4.75% $450M Senior Notes due January 15, 2028 | Subsequent event | ||||
Long-term debt | ||||
Issuance of debt | $ 450 | |||
Interest rate | 4.75% |
Long-Term Debt - Debt Maturing
Long-Term Debt - Debt Maturing Within One Year (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Long-term debt maturing within one year | ||
2023 | $ 808.5 | |
2024 | 1,239.6 | |
2025 | 1,685.5 | |
2026 | 126.8 | |
2027 | 1,230.7 | |
Thereafter | 10,468.7 | |
Long-term Debt, Gross | 15,559.8 | $ 13,652.6 |
WEC Energy Group | ||
Long-term debt maturing within one year | ||
2023 | 700 | |
2024 | 600 | |
2025 | 620 | |
2026 | 0 | |
2027 | 900 | |
Thereafter | $ 1,650 | |
WEC 0.55% Senior Notes due September 15, 2023 | WEC Energy Group | ||
Long-term debt maturing within one year | ||
Interest rate | 0.55% | |
Principal amount of unsecured debt | $ 700 | |
WEPCo Environmental Trust Bonds 1.578%, due 2035 | WEPCo Environmental Trust Finance I, LLC | ||
Long-term debt maturing within one year | ||
Interest rate | 1.58% | |
Principal amount of unsecured debt | $ 8.9 | |
3.76% Bluewater Gas Storage senior notes | Bluewater Gas Storage | ||
Long-term debt maturing within one year | ||
Interest rate | 3.76% | |
Principal amount of senior notes | $ 2.8 | |
4.91% We Power subsidiaries notes - PWGS | We Power | ||
Long-term debt maturing within one year | ||
Interest rate | 4.91% | |
Principal amount of secured debt | $ 7.6 | |
5.209% We Power subsidiaries notes - ERGS | We Power | ||
Long-term debt maturing within one year | ||
Interest rate | 5.209% | |
Principal amount of secured debt | $ 14.7 | |
4.673% We Power subsidiaries notes - ERGS | We Power | ||
Long-term debt maturing within one year | ||
Interest rate | 4.673% | |
Principal amount of secured debt | $ 11.1 | |
6.00% We Power subsidiaries notes - PWGS | We Power | ||
Long-term debt maturing within one year | ||
Interest rate | 6% | |
Principal amount of secured debt | $ 6.6 | |
2.75% WECI Wind Holding I senior notes | WECI Wind Holding I | ||
Long-term debt maturing within one year | ||
Interest rate | 2.75% | |
Principal amount of senior notes | $ 42 | |
6.38% WECI Wind Holding II LLC Senior Notes Due 2031 | WECI Wind Holding II | ||
Long-term debt maturing within one year | ||
Interest rate | 6.38% | |
Principal amount of senior notes | $ 14.8 |
Leases - Power Purchase Commitm
Leases - Power Purchase Commitment (Details) $ in Millions | 1 Months Ended | 5 Months Ended |
Jan. 31, 2023 USD ($) | May 31, 2022 MW | |
Whitewater | Wisconsin Electric Power Company & Wisconsin Public Service | Subsequent event | ||
Leases | ||
Total purchase price | $ | $ 72.7 | |
Power purchase commitment | ||
Leases | ||
Power purchase contract period | 25 years | |
Firm capacity from power purchase contract (in megawatts) | 236.5 | |
Minimum energy requirements over remaining term of power purchase contract (in megawatts) | 0 |
Leases - Land Leases - Utility
Leases - Land Leases - Utility Solar Generation (Details) - Land lease - utility solar generation | 12 Months Ended |
Dec. 31, 2022 renewal_terms | |
Leases | |
Minimum number of contract renewals | 1 |
Contract term | 50 years |
Leases - Lease Expense and Supp
Leases - Lease Expense and Supplemental Cash Flow Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Lease expense | |||
Amortization of finance lease right of use assets | $ 6 | $ 8.1 | $ 6.3 |
Interest on finance lease liabilities | 0.9 | 1.6 | 2.5 |
Operating lease expense | 6.1 | 3.4 | 5.4 |
Short-term lease expense | 0.9 | 0.2 | 0.3 |
Lease expense | 13.9 | 13.3 | 14.5 |
Other information | |||
Operating cash flows from finance leases | 0.9 | 1.6 | 2.5 |
Operating cash flows from operating leases | 5.7 | 5.3 | 6.7 |
Financing cash flows from finance leases | 6 | 8.1 | 6.3 |
Right-of-use asset obtained in exchange for finance lease liabilities | 57.6 | 73.6 | 22.8 |
Right of use assets obtained in exchange for operating lease liabilities | $ 0 | $ 0.5 | $ 0 |
Weighted average remaining lease term - finance leases | 30 years | 20 years 6 months | 41 years 6 months |
Weighted average remaining lease term - operating leases | 12 years | 12 years 6 months | 13 years |
Weighted average discount rate - finance leases | 3.90% | 2.40% | 4.90% |
Weighted average discount rate - operating leases | 3.40% | 3.40% | 3.40% |
Leases - Finance and Operating
Leases - Finance and Operating Lease Right of Use Assets and Obligations (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Leases | ||
Operating lease right of use assets | $ 15.7 | $ 19.5 |
Finance lease right of use assets | 175.3 | 124 |
Current operating lease liabilities | 4 | 3.7 |
Long-term operating lease liabilities | 25.4 | 29.1 |
Current finance lease liabilities | 72.7 | |
Long-term finance lease liabilities | 110.5 | 51.3 |
Accumulated amortization | $ 146.3 | $ 139.7 |
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration] | Other | Other |
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration] | Property, plant, and equipment, net of accumulated depreciation and amortization of $10,383.8 and $9,889.3, respectively | Property, plant, and equipment, net of accumulated depreciation and amortization of $10,383.8 and $9,889.3, respectively |
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration] | Other | Other |
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration] | Other | Other |
Finance Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration] | Current portion of long-term debt (December 31, 2022 and December 31, 2021 include $8.9 and $8.8, respectively, related to WEPCo Environmental Trust) | Current portion of long-term debt (December 31, 2022 and December 31, 2021 include $8.9 and $8.8, respectively, related to WEPCo Environmental Trust) |
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration] | Long-term debt (December 31, 2022 and December 31, 2021 include $94.1 and $102.7, respectively, related to WEPCo Environmental Trust) | Long-term debt (December 31, 2022 and December 31, 2021 include $94.1 and $102.7, respectively, related to WEPCo Environmental Trust) |
Power purchase commitment | ||
Leases | ||
Finance lease right of use assets | $ 71.8 | $ 76.7 |
Current finance lease liabilities | 72.7 | 78.4 |
Long-term finance lease liabilities | 0 | |
Land lease - utility solar generation | ||
Leases | ||
Finance lease right of use assets | 102.4 | 47 |
Current finance lease liabilities | 0 | |
Long-term finance lease liabilities | 109.3 | 51 |
Other | ||
Leases | ||
Finance lease right of use assets | 1.1 | 0.3 |
Current finance lease liabilities | 0 | |
Long-term finance lease liabilities | $ 1.2 | $ 0.3 |
Leases - Future Minimum Lease P
Leases - Future Minimum Lease Payments (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Total operating leases | ||
2023 | $ 4.9 | |
2024 | 4.3 | |
2025 | 3.8 | |
2026 | 3.9 | |
2027 | 4 | |
Thereafter | 16.6 | |
Total minimum lease payments | 37.5 | |
Less: interest | (8.1) | |
Present value of minimum lease payments | 29.4 | |
Less: short-term lease liabilities | (4) | $ (3.7) |
Long-term operating lease liabilities | 25.4 | 29.1 |
Finance leases | ||
2023 | 76.3 | |
2024 | 4 | |
2025 | 4.1 | |
2026 | 4.1 | |
2027 | 4.2 | |
Thereafter | 306.8 | |
Total minimum lease payments | 399.5 | |
Less: interest | (216.3) | |
Present value of minimum lease payments | 183.2 | 129.7 |
Less: short-term lease liabilities | (72.7) | |
Long-term finance lease liabilities | 110.5 | 51.3 |
Power purchase commitment | ||
Finance leases | ||
2023 | 72.7 | |
2024 | 0 | |
2025 | 0 | |
2026 | 0 | |
2027 | 0 | |
Thereafter | 0 | |
Total minimum lease payments | 72.7 | |
Less: interest | 0 | |
Present value of minimum lease payments | 72.7 | |
Less: short-term lease liabilities | (72.7) | (78.4) |
Long-term finance lease liabilities | 0 | |
Land lease - utility solar generation | ||
Finance leases | ||
2023 | 3.6 | |
2024 | 3.9 | |
2025 | 4 | |
2026 | 4 | |
2027 | 4.1 | |
Thereafter | 304.1 | |
Total minimum lease payments | 323.7 | |
Less: interest | (214.4) | |
Present value of minimum lease payments | 109.3 | |
Less: short-term lease liabilities | 0 | |
Long-term finance lease liabilities | 109.3 | 51 |
Other | ||
Finance leases | ||
2023 | 0 | |
2024 | 0.1 | |
2025 | 0.1 | |
2026 | 0.1 | |
2027 | 0.1 | |
Thereafter | 2.7 | |
Total minimum lease payments | 3.1 | |
Less: interest | (1.9) | |
Present value of minimum lease payments | 1.2 | |
Less: short-term lease liabilities | 0 | |
Long-term finance lease liabilities | $ 1.2 | $ 0.3 |
Income Taxes - Summary of Incom
Income Taxes - Summary of Income Tax Expense (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Income Tax Disclosure [Abstract] | |||
Current tax expense | $ 50.2 | $ 93.9 | $ 49.2 |
Deferred income taxes, net | 278.5 | 111 | 182.2 |
ITCs | (5.8) | (4.6) | (3.5) |
Total income tax expense | $ 322.9 | $ 200.3 | $ 227.9 |
Income Taxes - Statutory Rate R
Income Taxes - Statutory Rate Reconciliation (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Statutory rate reconciliation of amount | ||||
Statutory federal income tax | $ 363.5 | $ 315.1 | $ 299.9 | |
State income taxes net of federal tax benefit | 109.7 | 96.1 | 90.5 | |
Wind PTCs | (107.6) | (81.3) | (51.5) | |
Federal excess deferred tax amortization | (36.9) | (37.3) | (36.7) | |
AFUDC - Equity | (6.2) | (3.8) | (4.4) | |
ITC restored | (5.8) | (4.6) | (3.5) | |
Federal excess deferred tax amortization - Wisconsin unprotected | (0.8) | (77.9) | (57.6) | |
Other, net | 7 | (6) | (8.8) | |
Total income tax expense | $ 322.9 | $ 200.3 | $ 227.9 | |
Statutory rate reconciliation of percent | ||||
Statutory federal income tax | 21% | 21% | 21% | |
State income taxes net of federal tax benefit | 6.30% | 6.40% | 6.30% | |
Wind PTCs | (6.20%) | (5.40%) | (3.60%) | |
Federal excess deferred tax amortization | (2.10%) | (2.50%) | (2.60%) | |
AFUDC - Equity | (0.40%) | (0.30%) | (0.30%) | |
ITC restored | (0.30%) | (0.30%) | (0.20%) | |
Federal excess deferred tax amortization - Wisconsin unprotected | 0% | (5.20%) | (4.00%) | |
Other, net | 0.30% | (0.30%) | (0.70%) | |
Total income tax expense | 18.60% | 13.40% | 15.90% | |
Public Service Commission of Wisconsin (PSCW) | Tax Cuts and Jobs Act of 2017 | 2020 and 2021 rates | ||||
Income taxes | ||||
Income statement impact of amortizing unprotected tax benefits | $ 0 | $ 0 | $ 0 | |
Public Service Commission of Wisconsin (PSCW) | Tax Cuts and Jobs Act of 2017 | 2020 and 2021 rates | Electric rates | ||||
Income taxes | ||||
Amortization period | 2 years | |||
Public Service Commission of Wisconsin (PSCW) | Tax Cuts and Jobs Act of 2017 | 2020 and 2021 rates | Natural gas rates | ||||
Income taxes | ||||
Amortization period | 4 years | |||
Public Service Commission of Wisconsin (PSCW) | Tax Cuts and Jobs Act of 2017 | 2018 and 2019 rates | ||||
Income taxes | ||||
Income statement impact of amortizing protected tax benefits | $ 0 | $ 0 | $ 0 |
Income Taxes - Components of De
Income Taxes - Components of Deferred Income Taxes (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Income Tax Disclosure [Abstract] | ||
Deferred tax liability, net | $ 4,625.6 | $ 4,308.5 |
Deferred Tax Assets | ||
Tax gross up - regulatory items | 459 | 469.5 |
Future tax benefits | 187.7 | 104.6 |
Deferred revenues | 86.8 | 97.8 |
Other | 190.2 | 205.9 |
Total deferred tax assets | 923.7 | 877.8 |
Valuation allowance | (1.2) | (1.2) |
Net deferred tax assets | 922.5 | 876.6 |
Deferred Tax Liabilities | ||
Property-related | 4,072.5 | 3,909 |
Investment in affiliates | 839.7 | 648.6 |
Employee benefits and compensation | 219.5 | 170.6 |
Deferred costs - plant retirements | 212.8 | 223.9 |
Other | 203.6 | 233 |
Total deferred tax liabilities | $ 5,548.1 | $ 5,185.1 |
Income Taxes - Carryforwards (D
Income Taxes - Carryforwards (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Income taxes | ||
Balance carryforwards, gross value | $ 72.6 | $ 72 |
Balance carryforwards, deferred tax effect | 187.7 | 104.6 |
Balance carryforwards, valuation allowance | (1.2) | (1.2) |
Federal tax jurisdiction | ||
Income taxes | ||
Tax credit carryforwards, gross value | 0 | 0 |
Tax credit carryforwards, deferred tax effect | 176.4 | 91.5 |
Tax credit carryforward, valuation allowance | 0 | 0 |
State and local jurisdiction | ||
Income taxes | ||
Tax credit carryforwards, gross value | 0 | 0 |
Operating loss carryforwards, gross value | 72.6 | 72 |
Tax credit carryforwards, deferred tax effect | 6.8 | 8.7 |
Operating loss carryforwards, deferred tax effect | 4.5 | 4.4 |
Tax credit carryforward, valuation allowance | 0 | 0 |
Operating loss carryforwards, valuation allowance | $ (1.2) | $ (1.2) |
Income Taxes - Schedule of Unre
Income Taxes - Schedule of Unrecognized Tax Benefits Roll Forward (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Reconciliation of the beginning and ending amount of unrecognized tax benefits | |||
Balance of unrecognized tax benefits, January 1 | $ 6.8 | $ 11.9 | $ 17.9 |
Additions for tax positions of prior years | 0.3 | 0 | 1.6 |
Additions based on tax positions related to the current year | 0.4 | 1.6 | 0.1 |
Reductions for tax positions of prior years | (1.2) | (6.7) | (7.7) |
Balance of unrecognized tax benefits, December 31 | 6.3 | 6.8 | $ 11.9 |
Income Taxes | |||
Deferred tax assets excluded due to uncertainty in income taxes | 1.3 | 1.2 | |
Net amount of unrecognized tax benefits having impact on the effective tax rate for continuing operations | $ 5.1 | $ 5.7 |
Income Taxes - Roll forward of
Income Taxes - Roll forward of interest accrued on unrecognized tax benefits (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | ||||
Accrued interest on the consolidated balance sheets | $ 0.5 | $ 0.1 | $ 0.5 | $ 0.8 |
Interest expense (income) related to unrecognized tax benefits | 0.4 | (0.4) | (0.3) | |
Penalties in the consolidated income statements | 0 | 0 | $ 0 | |
Accrued penalties on the consolidated balance sheets | 0 | $ 0 | ||
Unrecognized tax benefits, decrease resulting from statute of limitations | $ 2.3 |
Fair Value Measurements - Asset
Fair Value Measurements - Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Assets | ||
Derivative assets | $ 74.8 | $ 120 |
Liabilities | ||
Derivative liabilities | 96.6 | 15.1 |
Fair value measurements on a recurring basis | ||
Assets | ||
Derivative assets | 74.8 | 120 |
Investments held in rabbi trust | 50.9 | 79.6 |
Fair value measurements on a recurring basis | Level 1 | ||
Assets | ||
Derivative assets | 16.3 | 46.4 |
Investments held in rabbi trust | 50.9 | 79.6 |
Fair value measurements on a recurring basis | Level 2 | ||
Assets | ||
Derivative assets | 50.7 | 71.2 |
Investments held in rabbi trust | 0 | 0 |
Fair value measurements on a recurring basis | Level 3 | ||
Assets | ||
Derivative assets | 7.8 | 2.4 |
Investments held in rabbi trust | 0 | 0 |
Fair value measurements on a recurring basis | Natural gas contracts | ||
Assets | ||
Derivative assets | 32.5 | 64.6 |
Liabilities | ||
Derivative liabilities | 96.6 | 15.1 |
Fair value measurements on a recurring basis | Natural gas contracts | Level 1 | ||
Assets | ||
Derivative assets | 16.3 | 46.4 |
Liabilities | ||
Derivative liabilities | 81.4 | 8.4 |
Fair value measurements on a recurring basis | Natural gas contracts | Level 2 | ||
Assets | ||
Derivative assets | 16.2 | 18.2 |
Liabilities | ||
Derivative liabilities | 15.2 | 6.7 |
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 | 7.8 | 2.4 |
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 | 7.8 | 2.4 |
Fair value measurements on a recurring basis | Coal contracts | ||
Assets | ||
Derivative assets | 34.5 | 53 |
Fair value measurements on a recurring basis | Coal contracts | Level 1 | ||
Assets | ||
Derivative assets | 0 | 0 |
Fair value measurements on a recurring basis | Coal contracts | Level 2 | ||
Assets | ||
Derivative assets | 34.5 | 53 |
Fair value measurements on a recurring basis | Coal contracts | Level 3 | ||
Assets | ||
Derivative assets | $ 0 | $ 0 |
Fair Value Measurements - Unrea
Fair Value Measurements - Unrealized Gains (Losses) on Investments (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Fair Value Disclosures [Abstract] | |||
Net unrealized losses in earnings related to investments held at the end of the period | $ 12.7 | ||
Net unrealized gains in earnings related to investments held at the end of the period | $ 16 | $ 6.3 |
Fair Value Measurements - Level
Fair Value Measurements - Level 3 Reconciliation (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Level 3 rollforward | |||
Balance at the beginning of the period | $ 2.4 | $ 2.4 | $ 3.1 |
Purchases | 23.7 | 6.1 | 7.6 |
Realized and unrealized gains included in earnings | 0.5 | 0 | 0 |
Settlements | (18.8) | (6.1) | (8.3) |
Balance at the end of period | 7.8 | 2.4 | 2.4 |
Losses included in earnings attributable to the change in unrealized losses of level 3 derivatives held at the end of the reporting period | $ (0.4) | $ 0 | $ 0 |
Fair Value Measurements - Finan
Fair Value Measurements - Financial Instruments (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Financial instruments | ||
Preferred stock of subsidiary | $ 30.4 | $ 30.4 |
Long-term debt, including current portion | 15,464.2 | 13,563.4 |
Finance lease obligation | 183.2 | 129.7 |
Carrying amount | ||
Financial instruments | ||
Preferred stock of subsidiary | 30.4 | 30.4 |
Long-term debt, including current portion | 15,464.2 | 13,563.4 |
Finance lease obligation | 183.2 | 129.7 |
Fair value | ||
Financial instruments | ||
Preferred stock of subsidiary | 22.7 | 30.3 |
Long-term debt, including current portion | $ 13,921.3 | $ 14,819.4 |
Derivative Instruments - Deriva
Derivative Instruments - Derivative Assets and Liabilities (Details) $ in Millions | Dec. 31, 2022 USD ($) Instruments | Dec. 31, 2021 USD ($) Instruments |
Derivative assets | ||
Other current derivative assets | $ 59.2 | $ 107 |
Other long-term derivative assets | 15.6 | 13 |
Derivative assets | $ 74.8 | $ 120 |
Current derivative assets balance sheet location | Other | Other |
Long-term derivative assets balance sheet location | Other | Other |
Derivative liabilities | ||
Other current derivative liabilities | $ 88.2 | $ 14 |
Other long-term derivative Iiabilities | 8.4 | 1.1 |
Derivative liabilities | $ 96.6 | $ 15.1 |
Current derivative liabilities balance sheet location | Other | Other |
Long-term derivative liabilities balance sheet location | Other | Other |
Natural gas contracts | ||
Derivative assets | ||
Other current derivative assets | $ 32.5 | $ 60.6 |
Other long-term derivative assets | 0 | 4 |
Derivative liabilities | ||
Other current derivative liabilities | 88.2 | 14 |
Other long-term derivative Iiabilities | 8.4 | 1.1 |
FTRs | ||
Derivative assets | ||
Other current derivative assets | 7.8 | 2.4 |
Derivative liabilities | ||
Other current derivative liabilities | 0 | 0 |
Coal contracts | ||
Derivative assets | ||
Other current derivative assets | 18.9 | 44 |
Other long-term derivative assets | 15.6 | 9 |
Derivative liabilities | ||
Other current derivative liabilities | 0 | 0 |
Other long-term derivative Iiabilities | $ 0 | $ 0 |
Hedging instruments | ||
Derivative instruments | ||
Number of derivatives designated as hedging instruments | Instruments | 0 | 0 |
Derivative Instruments - Gains
Derivative Instruments - Gains (Losses) and Notional Volumes (Details) MWh in Millions, MMBTU in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 USD ($) MMBTU MWh | Dec. 31, 2021 USD ($) MWh MMBTU | Dec. 31, 2020 USD ($) MMBTU MWh | |
Realized gains (losses) on derivatives | |||
Gains (losses) | $ 311.3 | $ 154.2 | $ (50) |
Non-Utility Energy Infrastructure | |||
Realized gains (losses) on derivatives | |||
Realized gains and losses on derivatives income statement location | Operating revenues | Operating revenues | Operating revenues |
Public utilities | |||
Realized gains (losses) on derivatives | |||
Realized gains and losses on derivatives income statement location | Cost of sales | Cost of sales | Cost of sales |
Natural gas contracts | |||
Realized gains (losses) on derivatives | |||
Gains (losses) | $ 299.5 | $ 136.5 | $ (54.1) |
Notional sales volumes | |||
Notional sales volumes | MMBTU | 183.3 | 197.6 | 188.6 |
FTRs and TCRs | |||
Realized gains (losses) on derivatives | |||
Gains (losses) | $ 11.8 | $ 17.7 | $ 4.1 |
Notional sales volumes | |||
Notional sales volumes | MWh | 27.2 | 28.2 | 29.8 |
Derivative Instruments - Balanc
Derivative Instruments - Balance Sheet Offsetting (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Cash collateral | ||
Cash collateral posted | $ 122.4 | $ 13.9 |
Cash collateral received | 13.2 | |
Offsetting derivative assets | ||
Gross amount recognized on the balance sheet | 74.8 | 120 |
Gross amount not offset on the balance sheet | (17.5) | (15.2) |
Net amount | 57.3 | 104.8 |
Cash collateral received | 6.4 | |
Offsetting derivative liabilities | ||
Gross amount recognized on the balance sheet | 96.6 | 15.1 |
Gross amount not offset on the balance sheet | (82.5) | (9.2) |
Net amount | 14.1 | 5.9 |
Cash collateral posted | $ 65 | $ 0.4 |
Derivative Instruments - Cash F
Derivative Instruments - Cash Flow Hedges (Details) $ in Millions | 12 Months Ended | |||
Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | Dec. 31, 2020 USD ($) | Nov. 15, 2021 USD ($) number_of_interest_rate_swaps | |
Derivative instruments | ||||
Total interest expense line item on the income statements | $ 515.1 | $ 471.1 | $ 493.7 | |
WEC Energy Group | ||||
Derivative instruments | ||||
Total interest expense line item on the income statements | 109.6 | 70.2 | 96.9 | |
WEC Energy Group | WEC Energy Group 2007 junior notes due 2067 | ||||
Derivative instruments | ||||
Long-term debt outstanding | 500 | 500 | $ 500 | |
Interest rate swaps | WEC Energy Group | ||||
Derivative instruments | ||||
Number of interest rate swaps | number_of_interest_rate_swaps | 2 | |||
Interest rate swap notional value | $ 250 | |||
Interest rate swap fixed interest rate | 4.9765% | |||
Derivative gain (loss) recognized in other comprehensive income / loss | 0 | 0.8 | (5.9) | |
Net derivative gain (loss) reclassified from accumulated other comprehensive loss to interest expense | 0.4 | $ (1.3) | $ (2.1) | |
Reclassification to interest expense within next twelve months | $ 0.4 |
Guarantees (Details)
Guarantees (Details) $ in Millions | Dec. 31, 2022 USD ($) |
Guarantor Obligations | |
Total guarantees | $ 159.1 |
Guarantees expiring in less than one year | 41.9 |
Guarantees expiring within one to three years | 0.3 |
Guarantees with expiration over three years | 116.9 |
Standby letters of credit (1) | |
Guarantor Obligations | |
Total guarantees | 115.7 |
Guarantees expiring in less than one year | 8 |
Guarantees expiring within one to three years | 0.2 |
Guarantees with expiration over three years | 107.5 |
Surety bonds (2) | |
Guarantor Obligations | |
Total guarantees | 34 |
Guarantees expiring in less than one year | 33.9 |
Guarantees expiring within one to three years | 0.1 |
Guarantees with expiration over three years | 0 |
Other guarantees (3) | |
Guarantor Obligations | |
Total guarantees | 9.4 |
Guarantees expiring in less than one year | 0 |
Guarantees expiring within one to three years | 0 |
Guarantees with expiration over three years | $ 9.4 |
Employee Benefits - Change in B
Employee Benefits - Change in Benefit Obligations and Plan Assets (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Pension Benefits | |||
Change in benefit obligation | |||
Obligation at January 1 | $ 3,136.6 | $ 3,346.4 | |
Service cost | 50.8 | 54.3 | $ 50.1 |
Interest cost | 91.8 | 87.5 | 102.8 |
Participant contributions | 0 | 0 | |
Plan amendments | 0 | 0 | |
Actuarial gain | (682.3) | (101.3) | |
Benefit payments | (281) | (250.3) | |
Transfer | 0 | 0 | |
Obligation at December 31 | 2,315.9 | 3,136.6 | 3,346.4 |
Change in fair value of plan assets | |||
Beginning balance at January 1 | 3,328.9 | 3,225 | |
Actual return on plan assets | (431.3) | 291.8 | |
Employer contributions | 11.4 | 62.4 | |
Participant contributions | 0 | 0 | |
Benefit payments | (281) | (250.3) | |
Ending balance at December 31 | 2,628 | 3,328.9 | 3,225 |
Funded status at December 31 | 312.1 | 192.3 | |
OPEB Benefits | |||
Change in benefit obligation | |||
Obligation at January 1 | 530.2 | 556.1 | |
Service cost | 14.3 | 15.7 | 15.2 |
Interest cost | 15.4 | 14.5 | 18.6 |
Participant contributions | 12.5 | 12.5 | |
Plan amendments | 0.2 | (3.9) | |
Actuarial gain | (127.9) | (20.3) | |
Benefit payments | (45.7) | (47.5) | |
Federal subsidy on benefits paid | 1.4 | 1.2 | |
Transfer | 1.9 | 1.9 | |
Obligation at December 31 | 402.3 | 530.2 | 556.1 |
Change in fair value of plan assets | |||
Beginning balance at January 1 | 1,000.2 | 951.4 | |
Actual return on plan assets | (135.4) | 79.9 | |
Employer contributions | 3.7 | 3.9 | |
Participant contributions | 12.5 | 12.5 | |
Benefit payments | (45.7) | (47.5) | |
Ending balance at December 31 | 835.3 | 1,000.2 | $ 951.4 |
Funded status at December 31 | $ 433 | $ 470 |
Employee Benefits - Amounts Rec
Employee Benefits - Amounts Recognized on the Balance Sheets (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Defined Benefit Plan Disclosure [Line Items] | ||
Pension and OPEB assets | $ 916.7 | $ 881.3 |
Pension and OPEB obligations | 171.6 | 219 |
Pension Benefits | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Pension and OPEB assets | 470.6 | 389 |
Pension and OPEB obligations | 158.5 | 196.7 |
Total net assets | 312.1 | 192.3 |
OPEB Benefits | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Pension and OPEB assets | 446.1 | 492.3 |
Pension and OPEB obligations | 13.1 | 22.3 |
Total net assets | $ 433 | $ 470 |
Employee Benefits - Accumulated
Employee Benefits - Accumulated Benefit Obligations (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Pension Plan | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Accumulated benefit obligation | $ 2,250.6 | $ 3,010.5 |
Information for pension or OPEB plans with an accumulated benefit obligation in excess of plan assets | ||
Accumulated benefit obligation | 185.7 | 372.4 |
Fair value of plan assets | 32.8 | 186.3 |
Information for pension plans with a projected benefit obligation in excess of plan assets | ||
Projected benefit obligation | 191.3 | 383 |
Fair value of plan assets | 32.8 | 186.3 |
OPEB Benefits | ||
Information for pension or OPEB plans with an accumulated benefit obligation in excess of plan assets | ||
Accumulated benefit obligation | 20.6 | 25.1 |
Fair value of plan assets | $ 7.4 | $ 2.8 |
Employee Benefits - Amounts Not
Employee Benefits - Amounts Not Yet Recognized in Net Periodic Benefit Cost (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Pension Benefits | ||
Pre-tax accumulated other comprehensive income (loss) | ||
Net actuarial loss (gain) | $ 12.2 | $ 7.5 |
Prior service credits | 0 | 0 |
Total | 12.2 | 7.5 |
Net regulatory assets (liabilities) | ||
Net actuarial loss (gain) | 669.2 | 798.6 |
Prior service credits | (2.1) | (0.5) |
Total | 667.1 | 798.1 |
OPEB Benefits | ||
Pre-tax accumulated other comprehensive income (loss) | ||
Net actuarial loss (gain) | (1.6) | (1.4) |
Prior service credits | 0 | (0.1) |
Total | (1.6) | (1.5) |
Net regulatory assets (liabilities) | ||
Net actuarial loss (gain) | (200.8) | (300.1) |
Prior service credits | (44.2) | (60.3) |
Total | $ (245) | $ (360.4) |
Employee Benefits - Net Periodi
Employee Benefits - Net Periodic Benefit Cost (Credit) (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Pension Benefits | |||
Components of net periodic benefit cost (credit) (including amounts capitalized to the balance sheets) | |||
Service cost | $ 50.8 | $ 54.3 | $ 50.1 |
Interest cost | 91.8 | 87.5 | 102.8 |
Expected return on plan assets | (208) | (200.9) | (190.3) |
Plan settlement | 6.2 | 3.9 | 17.9 |
Plan curtailment | 0 | 0 | 0 |
Amortization of prior service cost (credit) | 1.6 | 1.6 | 1.6 |
Amortization of net actuarial loss (gain) | 75.3 | 109.4 | 102.6 |
Net periodic benefit cost (credit) | 17.7 | 55.8 | 84.7 |
OPEB Benefits | |||
Components of net periodic benefit cost (credit) (including amounts capitalized to the balance sheets) | |||
Service cost | 14.3 | 15.7 | 15.2 |
Interest cost | 15.4 | 14.5 | 18.6 |
Expected return on plan assets | (68.9) | (66) | (60.3) |
Plan settlement | 0 | 0 | 0 |
Plan curtailment | 0 | (6.4) | 0 |
Amortization of prior service cost (credit) | (15.9) | (15.9) | (15) |
Amortization of net actuarial loss (gain) | (24.7) | (24.4) | (22.4) |
Net periodic benefit cost (credit) | $ (79.8) | $ (82.5) | $ (63.9) |
Employee Benefits - Assumptions
Employee Benefits - Assumptions (Details) | 12 Months Ended | |||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Pension Plan | Benefit obligation assumptions | ||||
Weighted average assumptions - benefit obligations | ||||
Discount rate | 5.49% | 2.96% | 2.67% | |
Rate of compensation increase | 4% | 4% | ||
Interest credit rate | 4.61% | 3.73% | ||
Pension Plan | Net periodic benefit cost assumptions | ||||
Weighted average assumptions - net periodic benefit cost | ||||
Discount rate | 3.18% | 2.71% | 3.34% | |
Expected return on plan assets | 6.88% | 6.88% | 6.87% | |
Rate of compensation increase | 4% | 4% | 4% | |
Interest credit rate | 3.78% | 3.71% | 3.70% | |
Pension Plan | Net periodic benefit cost assumptions | Subsequent event | ||||
Weighted average assumptions - net periodic benefit cost | ||||
Expected return on plan assets | 6.88% | |||
OPEB Plan | Benefit obligation assumptions | ||||
Weighted average assumptions - benefit obligations | ||||
Discount rate | 5.50% | 2.92% | ||
OPEB Plan | Benefit obligation assumptions | Pre 65 | ||||
Medical cost trend rates | ||||
Assumed medical cost trend rate | 6.50% | 5.70% | ||
Ultimate trend rate | 5% | 5% | ||
Year ultimate trend rate is reached | 2031 | 2028 | ||
OPEB Plan | Benefit obligation assumptions | Post 65 | ||||
Medical cost trend rates | ||||
Assumed medical cost trend rate | 6% | 5.67% | ||
Ultimate trend rate | 5% | 5% | ||
Year ultimate trend rate is reached | 2031 | 2028 | ||
OPEB Plan | Net periodic benefit cost assumptions | ||||
Weighted average assumptions - net periodic benefit cost | ||||
Discount rate | 2.92% | 2.66% | 3.39% | |
Expected return on plan assets | 7% | 7% | 7% | |
OPEB Plan | Net periodic benefit cost assumptions | Subsequent event | ||||
Weighted average assumptions - net periodic benefit cost | ||||
Expected return on plan assets | 7% | |||
OPEB Plan | Net periodic benefit cost assumptions | Pre 65 | ||||
Medical cost trend rates | ||||
Assumed medical cost trend rate | 5.70% | 5.85% | 6% | |
Ultimate trend rate | 5% | 5% | 5% | |
Year ultimate trend rate is reached | 2028 | 2028 | 2028 | |
OPEB Plan | Net periodic benefit cost assumptions | Post 65 | ||||
Medical cost trend rates | ||||
Assumed medical cost trend rate | 5.67% | 5.80% | 5.91% | |
Ultimate trend rate | 5% | 5% | 5% | |
Year ultimate trend rate is reached | 2028 | 2028 | 2028 |
Employee Benefits - Target Asse
Employee Benefits - Target Asset Allocations (Details) | Dec. 31, 2022 |
Pension Plan | Wisconsin Energy Corporation | Equity securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 30% |
Pension Plan | Wisconsin Energy Corporation | Fixed income securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 55% |
Pension Plan | Wisconsin Energy Corporation | Private equity and real estate | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 15% |
Pension Plan | Integrys | Equity securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 40% |
Pension Plan | Integrys | Fixed income securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 45% |
Pension Plan | Integrys | Private equity and real estate | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 15% |
OPEB Plan | Wisconsin Energy Corporation | Equity securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 50% |
OPEB Plan | Wisconsin Energy Corporation | Fixed income securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 40% |
OPEB Plan | Wisconsin Energy Corporation | Real estate investments | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 10% |
OPEB Plan | Integrys | Largest trust 1 | Equity securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 45% |
OPEB Plan | Integrys | Largest trust 1 | Fixed income securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 45% |
OPEB Plan | Integrys | Largest trust 1 | Real estate investments | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 10% |
OPEB Plan | Integrys | Largest trust 2 | Equity securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 45% |
OPEB Plan | Integrys | Largest trust 2 | Fixed income securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 45% |
OPEB Plan | Integrys | Largest trust 2 | Real estate investments | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 10% |
Employee Benefits - Plan Assets
Employee Benefits - Plan Assets (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 |
Pension Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | $ 2,628 | $ 3,328.9 | $ 3,225 |
Pension Plan | Level 1, 2, and 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 1,367.4 | 1,918 | |
Pension Plan | Level 1, 2, and 3 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 231.5 | 417.1 | |
Pension Plan | Level 1, 2, and 3 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 202.2 | 313.7 | |
Pension Plan | Level 1, 2, and 3 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 838.7 | 1,068.7 | |
Pension Plan | Level 1, 2, and 3 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 95 | 118.5 | |
Pension Plan | Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 433.7 | 730.8 | |
Pension Plan | Level 1 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 231.5 | 417.1 | |
Pension Plan | Level 1 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 202.2 | 313.7 | |
Pension Plan | Level 1 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Plan | Level 1 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Plan | Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 933.7 | 1,187.2 | |
Pension Plan | Level 2 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Plan | Level 2 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Plan | Level 2 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 838.7 | 1,068.7 | |
Pension Plan | Level 2 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 95 | 118.5 | |
Pension Plan | Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Plan | Level 3 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Plan | Level 3 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Plan | Level 3 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Plan | Level 3 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Plan | Investments measured at net asset value per share | Equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 466 | 659.2 | |
Pension Plan | Investments measured at net asset value per share | Fixed income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 101 | 127.7 | |
Pension Plan | Investments measured at net asset value per share | Other investments | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 693.6 | 624 | |
OPEB Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 835.3 | 1,000.2 | $ 951.4 |
OPEB Plan | Level 1, 2, and 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 464.7 | 617.4 | |
OPEB Plan | Level 1, 2, and 3 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 92.5 | 135.4 | |
OPEB Plan | Level 1, 2, and 3 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 83.9 | 109.1 | |
OPEB Plan | Level 1, 2, and 3 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 275.1 | 357.3 | |
OPEB Plan | Level 1, 2, and 3 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 13.2 | 15.6 | |
OPEB Plan | Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 306.2 | 409.5 | |
OPEB Plan | Level 1 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 92.5 | 135.4 | |
OPEB Plan | Level 1 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 83.9 | 109.1 | |
OPEB Plan | Level 1 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 129.8 | 165 | |
OPEB Plan | Level 1 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
OPEB Plan | Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 158.5 | 207.9 | |
OPEB Plan | Level 2 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
OPEB Plan | Level 2 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
OPEB Plan | Level 2 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 145.3 | 192.3 | |
OPEB Plan | Level 2 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 13.2 | 15.6 | |
OPEB Plan | Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
OPEB Plan | Level 3 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
OPEB Plan | Level 3 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
OPEB Plan | Level 3 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
OPEB Plan | Level 3 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
OPEB Plan | Investments measured at net asset value per share | Equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 186.6 | 224.5 | |
OPEB Plan | Investments measured at net asset value per share | Fixed income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 65.5 | 112.3 | |
OPEB Plan | Investments measured at net asset value per share | Other investments | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | $ 118.5 | $ 46 |
Employee Benefits - Cash Flows
Employee Benefits - Cash Flows (Details) $ in Millions | Dec. 31, 2022 USD ($) |
Pension Benefits | |
Defined Benefit Plan Disclosure [Line Items] | |
Expected contributions to the plans during the next year | $ 14.5 |
2023 | 209.6 |
2024 | 207.2 |
2025 | 200.1 |
2026 | 202.1 |
2027 | 193.5 |
2028 through 2032 | 866.5 |
OPEB Benefits | |
Defined Benefit Plan Disclosure [Line Items] | |
Expected contributions to the plans during the next year | 2.1 |
2023 | 34.5 |
2024 | 34.3 |
2025 | 34.2 |
2026 | 34.3 |
2027 | 34.4 |
2028 through 2032 | $ 168 |
Employee Benefits - Defined Con
Employee Benefits - Defined Contribution Benefit Plans (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Retirement Benefits [Abstract] | |||
Total costs incurred for defined contribution benefit plans | $ 54.4 | $ 51.8 | $ 49.7 |
Investment in Transmission Af_3
Investment in Transmission Affiliates - Changes to Investment in ATC (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 USD ($) member vote | Dec. 31, 2021 USD ($) | Dec. 31, 2020 USD ($) | |
Changes to investment in transmission affiliates | |||
Add: Capital contributions | $ 45.5 | $ 0 | $ 21.2 |
Transmission affiliates | |||
Changes to investment in transmission affiliates | |||
Investment in transmission affiliates, balance at beginning of period | 1,789.4 | 1,764.3 | 1,720.8 |
Add: Earnings from equity method investment | 194.7 | 158.1 | 175.8 |
Add: Capital contributions | 45.5 | 21.2 | |
Less: Distributions | 120.4 | 133 | 146.7 |
Less: Return of capital | 6.8 | ||
Investment in transmission affiliates, balance at end of period | $ 1,909.2 | 1,789.4 | 1,764.3 |
ATC | |||
Investment in transmission affiliates | |||
Equity method investment, ownership interest (as a percent) | 60% | ||
Total number of members serving on the transmission affiliate's board of directors | member | 11 | ||
Number of representatives on the transmission affiliate's board of directors | member | 1 | ||
Number of votes that can be placed by each member on the transmission affiliate's board of directors | vote | 1 | ||
Liability for potential future refunds that ATC may be required to provide | $ 39.1 | ||
Changes to investment in transmission affiliates | |||
Investment in transmission affiliates, balance at beginning of period | 1,766.9 | 1,733.5 | 1,684.7 |
Add: Earnings from equity method investment | 192.6 | 166.4 | 174.3 |
Add: Capital contributions | 45.5 | 21.2 | |
Less: Distributions | 120.4 | 133 | 146.7 |
Less: Return of capital | 0 | ||
Investment in transmission affiliates, balance at end of period | $ 1,884.6 | 1,766.9 | 1,733.5 |
ATC Holdco | |||
Investment in transmission affiliates | |||
Equity method investment, ownership interest (as a percent) | 75% | ||
Total number of members serving on the transmission affiliate's board of directors | member | 4 | ||
Number of representatives on the transmission affiliate's board of directors | member | 1 | ||
Number of votes that can be placed by each member on the transmission affiliate's board of directors | vote | 1 | ||
Changes to investment in transmission affiliates | |||
Investment in transmission affiliates, balance at beginning of period | $ 22.5 | 30.8 | 36.1 |
Add: Earnings from equity method investment | 2.1 | (8.3) | 1.5 |
Add: Capital contributions | 0 | 0 | |
Less: Distributions | 0 | 0 | 0 |
Less: Return of capital | 6.8 | ||
Investment in transmission affiliates, balance at end of period | $ 24.6 | $ 22.5 | $ 30.8 |
Investment in Transmission Af_4
Investment in Transmission Affiliates - Transactions with ATC (Details) - ATC - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Charges from ATC for network transmission services | |||
Charges to ATC for services and construction | $ 18.9 | $ 22.9 | $ 27.5 |
Charges from ATC for network transmission services | 363.7 | 361 | 350.5 |
Net refund (payment) from (to) ATC related to FERC ROE orders | (0.1) | 7.3 | $ 10.7 |
Balance sheet | |||
Accounts receivable for services provided to ATC | 1.2 | 2 | |
Accounts payable for services received from ATC | 30.4 | 30.2 | |
Amounts due from ATC for transmission infrastructure upgrades (1) | $ 26.6 | $ 13 |
Investment in Transmission Af_5
Investment in Transmission Affiliates - ATC Summarized Financial Data (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Investment in transmission affiliates | |||
Operating revenues | $ 9,597.4 | $ 8,316 | $ 7,241.7 |
Operating expenses | 7,673.2 | 6,601.1 | 5,535.6 |
Other expense, net | 191.6 | 216.1 | 276.8 |
Current assets | 3,187.7 | 2,656.7 | |
Noncurrent assets | 38,684.4 | 36,331.8 | |
Total assets | 41,872.1 | 38,988.5 | 37,028.1 |
Current liabilities | 4,611 | 3,753 | |
Long-term debt | 14,655.7 | 13,472.4 | |
Other noncurrent liabilities | 1,475.3 | 1,203.2 | |
Total liabilities and members' equity | 41,872.1 | 38,988.5 | |
ATC | |||
Investment in transmission affiliates | |||
Operating revenues | 751.2 | 754.8 | 758.1 |
Operating expenses | 381.5 | 376.2 | 372.5 |
Other expense, net | 123 | 113.9 | 110.8 |
Net income | 246.7 | 264.7 | $ 274.8 |
Current assets | 89.6 | 89.8 | |
Noncurrent assets | 5,997.8 | 5,628.1 | |
Total assets | 6,087.4 | 5,717.9 | |
Current liabilities | 511.9 | 436.9 | |
Long-term debt | 2,613 | 2,513 | |
Other noncurrent liabilities | 485.8 | 422 | |
Members' equity | 2,476.7 | 2,346 | |
Total liabilities and members' equity | $ 6,087.4 | $ 5,717.9 |
Segment Information (Details)
Segment Information (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 USD ($) segment | Dec. 31, 2021 USD ($) | Dec. 31, 2020 USD ($) | |
Segment information | |||
Number of reportable segments | segment | 6 | ||
Operating revenues | $ 9,597.4 | $ 8,316 | $ 7,241.7 |
Other operation and maintenance | 1,938 | 2,005.5 | 2,032.2 |
Depreciation and amortization | 1,122.6 | 1,074.3 | 975.9 |
Equity in earnings of transmission affiliates | 194.7 | 158.1 | 175.8 |
Interest expense | 515.1 | 471.1 | 493.7 |
Loss on debt extinguishment | 0 | 36.3 | 38.4 |
Income tax expense (benefit) | 322.9 | 200.3 | 227.9 |
Net income (loss) | 1,409.7 | 1,298.5 | 1,201.4 |
Net income (loss) attributed to common shareholders | 1,408.1 | 1,300.3 | 1,199.9 |
Capital expenditures and asset acquisitions | 2,696.9 | 2,372.7 | 2,874.3 |
Total assets | 41,872.1 | 38,988.5 | 37,028.1 |
Reconciling eliminations | |||
Segment information | |||
Other operation and maintenance | (9.1) | (9.2) | (9.2) |
Depreciation and amortization | (68.1) | (60) | (52.8) |
Equity in earnings of transmission affiliates | 0 | 0 | 0 |
Interest expense | (336.2) | (340.5) | (345.5) |
Loss on debt extinguishment | 0 | 0 | |
Income tax expense (benefit) | 0 | 0 | 0 |
Net income (loss) | 0 | 0 | 0 |
Net income (loss) attributed to common shareholders | 0 | 0 | 0 |
Capital expenditures and asset acquisitions | 0 | 0 | 0 |
Total assets | (3,256.5) | (3,264.6) | (3,361.2) |
Reconciling eliminations | WE | |||
Segment information | |||
Total assets | 1,632.9 | 1,729.9 | 1,824.5 |
Wisconsin | |||
Segment information | |||
Operating revenues | 6,960.5 | 6,037 | 5,473.5 |
Illinois | |||
Segment information | |||
Operating revenues | 1,890.9 | 1,672.8 | 1,321.9 |
Other States | |||
Segment information | |||
Operating revenues | 618.5 | 519 | 384.1 |
Electric transmission | |||
Segment information | |||
Other operation and maintenance | 0 | 0 | 0 |
Depreciation and amortization | 0 | 0 | 0 |
Equity in earnings of transmission affiliates | 194.7 | 158.1 | 175.8 |
Interest expense | 19.4 | 19.4 | 19.4 |
Loss on debt extinguishment | 0 | 0 | |
Income tax expense (benefit) | 45.8 | 32.3 | 43.7 |
Net income (loss) | 129.5 | 106.3 | 112.6 |
Net income (loss) attributed to common shareholders | 129.5 | 106.3 | 112.6 |
Capital expenditures and asset acquisitions | 0 | 0 | 0 |
Total assets | $ 1,909.4 | 1,792.7 | 1,764.7 |
Non-Utility Energy Infrastructure | |||
Segment information | |||
Natural gas storage needs provided to Wisconsin utilities | 33% | ||
Operating revenues | $ 590 | 539.5 | 508.5 |
Other operation and maintenance | 51 | 43.1 | 24.9 |
Depreciation and amortization | 139.2 | 125.3 | 98.9 |
Equity in earnings of transmission affiliates | 0 | 0 | 0 |
Interest expense | 68.9 | 71 | 60.8 |
Loss on debt extinguishment | 0 | 0 | |
Income tax expense (benefit) | (20.9) | 3.1 | 44.7 |
Net income (loss) | 324.8 | 276.2 | 261.1 |
Net income (loss) attributed to common shareholders | 324.4 | 279.2 | 260.8 |
Capital expenditures and asset acquisitions | 483.8 | 335.3 | 661.8 |
Total assets | 5,320.6 | 4,627.7 | 4,455.2 |
Corporate and other | |||
Segment information | |||
Operating revenues | 0.5 | 0.5 | 2.2 |
Other operation and maintenance | (12.9) | (7.5) | 17.4 |
Depreciation and amortization | 25 | 25.9 | 25.1 |
Equity in earnings of transmission affiliates | 0 | 0 | 0 |
Interest expense | 119.4 | 92.8 | 124 |
Loss on debt extinguishment | 36.3 | 38.4 | |
Income tax expense (benefit) | (45.7) | (45.8) | (72.4) |
Net income (loss) | (70.8) | (50.5) | (106.4) |
Net income (loss) attributed to common shareholders | (70.8) | (50.5) | (106.4) |
Capital expenditures and asset acquisitions | 16.3 | 18.1 | 33.1 |
Total assets | 774 | 785.3 | 762.2 |
Public utilities | |||
Segment information | |||
Other operation and maintenance | 1,909 | 1,979.1 | 1,999.1 |
Depreciation and amortization | 1,026.5 | 983.1 | 904.7 |
Equity in earnings of transmission affiliates | 0 | 0 | 0 |
Interest expense | 643.6 | 628.4 | 635 |
Loss on debt extinguishment | 0 | 0 | |
Income tax expense (benefit) | 343.7 | 210.7 | 211.9 |
Net income (loss) | 1,026.2 | 966.5 | 934.1 |
Net income (loss) attributed to common shareholders | 1,025 | 965.3 | 932.9 |
Capital expenditures and asset acquisitions | 2,196.8 | 2,019.3 | 2,179.4 |
Total assets | 37,124.6 | 35,047.4 | 33,407.2 |
Public utilities | Wisconsin | |||
Segment information | |||
Other operation and maintenance | 1,351.3 | 1,455.2 | 1,476.7 |
Depreciation and amortization | 754.7 | 726.9 | 674.5 |
Equity in earnings of transmission affiliates | 0 | 0 | 0 |
Interest expense | 555.9 | 555.6 | 561.3 |
Loss on debt extinguishment | 0 | 0 | |
Income tax expense (benefit) | 247.5 | 119.9 | 132.7 |
Net income (loss) | 759.6 | 707.7 | 691.6 |
Net income (loss) attributed to common shareholders | 758.4 | 706.5 | 690.4 |
Capital expenditures and asset acquisitions | 1,610.8 | 1,389.7 | 1,382.4 |
Total assets | 27,384 | 25,687.9 | 24,599.2 |
Public utilities | Illinois | |||
Segment information | |||
Other operation and maintenance | 459.2 | 433.5 | 435.4 |
Depreciation and amortization | 230.9 | 218.1 | 196.7 |
Equity in earnings of transmission affiliates | 0 | 0 | 0 |
Interest expense | 73.8 | 66.6 | 63.5 |
Loss on debt extinguishment | 0 | 0 | |
Income tax expense (benefit) | 83.1 | 79.3 | 66.1 |
Net income (loss) | 226.9 | 223 | 203.5 |
Net income (loss) attributed to common shareholders | 226.9 | 223 | 203.5 |
Capital expenditures and asset acquisitions | 484.9 | 533.7 | 652.7 |
Total assets | 8,101 | 7,853.4 | 7,471.8 |
Public utilities | Other States | |||
Segment information | |||
Other operation and maintenance | 98.5 | 90.4 | 87 |
Depreciation and amortization | 40.9 | 38.1 | 33.5 |
Equity in earnings of transmission affiliates | 0 | 0 | 0 |
Interest expense | 13.9 | 6.2 | 10.2 |
Loss on debt extinguishment | 0 | 0 | |
Income tax expense (benefit) | 13.1 | 11.5 | 13.1 |
Net income (loss) | 39.7 | 35.8 | 39 |
Net income (loss) attributed to common shareholders | 39.7 | 35.8 | 39 |
Capital expenditures and asset acquisitions | 101.1 | 95.9 | 144.3 |
Total assets | 1,639.6 | 1,506.1 | 1,336.2 |
External revenues | |||
Segment information | |||
Operating revenues | 9,597.4 | 8,316 | 7,241.7 |
External revenues | Reconciling eliminations | |||
Segment information | |||
Operating revenues | 0 | 0 | 0 |
External revenues | Electric transmission | |||
Segment information | |||
Operating revenues | 0 | 0 | 0 |
External revenues | Non-Utility Energy Infrastructure | |||
Segment information | |||
Operating revenues | 127 | 86.7 | 60 |
External revenues | Corporate and other | |||
Segment information | |||
Operating revenues | 0.5 | 0.5 | 2.2 |
External revenues | Public utilities | |||
Segment information | |||
Operating revenues | 9,469.9 | 8,228.8 | 7,179.5 |
External revenues | Public utilities | Wisconsin | |||
Segment information | |||
Operating revenues | 6,960.5 | 6,037 | 5,473.5 |
External revenues | Public utilities | Illinois | |||
Segment information | |||
Operating revenues | 1,890.9 | 1,672.8 | 1,321.9 |
External revenues | Public utilities | Other States | |||
Segment information | |||
Operating revenues | 618.5 | 519 | 384.1 |
Intersegment transactions | |||
Segment information | |||
Operating revenues | 0 | 0 | 0 |
Intersegment transactions | Reconciling eliminations | |||
Segment information | |||
Operating revenues | (463) | (452.8) | (448.5) |
Intersegment transactions | Electric transmission | |||
Segment information | |||
Operating revenues | 0 | 0 | 0 |
Intersegment transactions | Non-Utility Energy Infrastructure | |||
Segment information | |||
Operating revenues | 463 | 452.8 | 448.5 |
Intersegment transactions | Corporate and other | |||
Segment information | |||
Operating revenues | 0 | 0 | 0 |
Intersegment transactions | Public utilities | |||
Segment information | |||
Operating revenues | 0 | 0 | 0 |
Intersegment transactions | Public utilities | Wisconsin | |||
Segment information | |||
Operating revenues | 0 | 0 | 0 |
Intersegment transactions | Public utilities | Illinois | |||
Segment information | |||
Operating revenues | 0 | 0 | 0 |
Intersegment transactions | Public utilities | Other States | |||
Segment information | |||
Operating revenues | $ 0 | $ 0 | $ 0 |
ATC | |||
Segment information | |||
Equity method investment, ownership interest (as a percent) | 60% | ||
ATC | Electric transmission | |||
Segment information | |||
Equity method investment, ownership interest (as a percent) | 60% | ||
ATC Holdco | |||
Segment information | |||
Equity method investment, ownership interest (as a percent) | 75% | ||
ATC Holdco | Electric transmission | |||
Segment information | |||
Equity method investment, ownership interest (as a percent) | 75% |
Variable Interest Entities - WE
Variable Interest Entities - WEPCo Environmental Trust (Details) - USD ($) $ in Millions | 1 Months Ended | |||
Nov. 30, 2020 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Assets | ||||
Other current assets (restricted cash) | $ 25.6 | $ 19.6 | $ 0 | |
Regulatory assets | 3,264.6 | 3,264.8 | ||
Other long-term assets (restricted cash) | 127.7 | 51.6 | $ 47.8 | |
Liabilities | ||||
Current portion of long-term debt | 808.5 | 91 | ||
Long-term debt | 14,655.7 | 13,472.4 | ||
WEPCo Environmental Trust | ||||
Variable interest entities | ||||
Securitization of environmental control costs related to Pleasant Prairie power plant | $ 100 | |||
Assets | ||||
Other current assets (restricted cash) | 3 | 2.4 | ||
Regulatory assets | 92.4 | 100.7 | ||
Other long-term assets (restricted cash) | 0.6 | 0.6 | ||
Liabilities | ||||
Current portion of long-term debt | 8.9 | 8.8 | ||
Other current liabilities (accrued interest) | 0.1 | 0.1 | ||
Long-term debt | $ 94.1 | $ 102.7 |
Variable Interest Entities - In
Variable Interest Entities - Investment in Transmission Affiliates (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
ATC | ||
Variable interest entities | ||
Ownership interest (as a percent) | 60% | |
Maximum exposure to loss | $ 1,884.6 | $ 1,766.9 |
ATC Holdco | ||
Variable interest entities | ||
Ownership interest (as a percent) | 75% | |
Maximum exposure to loss | $ 24.6 | $ 22.5 |
Variable Interest Entities - Po
Variable Interest Entities - Power Purchase Commitment (Details) - Power purchase commitment $ in Millions | Dec. 31, 2022 USD ($) | May 31, 2022 MW |
Variable interest entities | ||
Firm capacity from power purchase commitment (in megawatts) | MW | 236.5 | |
Residual guarantee associated with power purchase commitment | $ | $ 0 |
Commitments and Contingencies -
Commitments and Contingencies - Unconditional Purchase Obligations (Details) $ in Millions | Dec. 31, 2022 USD ($) |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | $ 10,461 |
2023 | 1,418.4 |
2024 | 1,304.1 |
2025 | 1,145.3 |
2026 | 951.5 |
2027 | 944.2 |
Later Years | 4,697.5 |
Nuclear | Electric | |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | 6,829.1 |
2023 | 548.5 |
2024 | 600.3 |
2025 | 634.5 |
2026 | 681.6 |
2027 | 730.4 |
Later Years | 3,633.8 |
Coal supply and transportation | Electric | |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | 936.1 |
2023 | 393.3 |
2024 | 279.2 |
2025 | 207.9 |
2026 | 24.7 |
2027 | 7.6 |
Later Years | 23.4 |
Purchased power | Electric | |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | 256.2 |
2023 | 63.4 |
2024 | 54.2 |
2025 | 47.8 |
2026 | 44.2 |
2027 | 19.6 |
Later Years | 27 |
Supply and transportation | Natural gas | |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | 1,938.8 |
2023 | 382.1 |
2024 | 344.2 |
2025 | 228.4 |
2026 | 173.7 |
2027 | 158.8 |
Later Years | 651.6 |
Non-Utility Energy Infrastructure | Purchased power | Electric | |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | 495 |
2023 | 26.2 |
2024 | 26.1 |
2025 | 26.7 |
2026 | 27.3 |
2027 | 27.8 |
Later Years | 360.9 |
Non-Utility Energy Infrastructure | Natural gas storage and transportation | Natural gas | |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | 5.8 |
2023 | 4.9 |
2024 | 0.1 |
2025 | 0 |
2026 | 0 |
2027 | 0 |
Later Years | $ 0.8 |
Commitments and Contingencies_2
Commitments and Contingencies - Environmental Matters (Details) T in Millions, $ in Millions | 1 Months Ended | 12 Months Ended | 15 Months Ended | ||||
Jan. 31, 2023 micrograms | Jun. 30, 2021 area | May 31, 2021 | Dec. 31, 2020 micrograms performance_obligations | Dec. 31, 2022 USD ($) micrograms performance_obligations generating_units States MW T | Mar. 31, 2019 MW | Dec. 31, 2021 USD ($) | |
Manufactured Gas Plant Remediation | |||||||
Regulatory asset | $ | $ 3,306.9 | $ 3,367.1 | |||||
Estimated future cash expenditures for environmental remediation | $ | 499.6 | 532.6 | |||||
Environmental remediation costs | |||||||
Manufactured Gas Plant Remediation | |||||||
Regulatory asset | $ | 610.7 | 630.9 | |||||
Estimated future cash expenditures for environmental remediation | $ | $ 499.6 | ||||||
Cross State Air Pollution Rule | Electric | |||||||
Air Quality | |||||||
Number of states the EPA is proposing more stringent regulation of ozone-season NOx emissions in | States | 26 | ||||||
Cross State Air Pollution Rule | Electric | Maximum | |||||||
Air Quality | |||||||
RICE unit megawatts | MW | 25 | ||||||
National Ambient Air Quality Standards | Electric | |||||||
Air Quality | |||||||
Number of counties to have boundaries revised | area | 13 | ||||||
Number of nonattainment areas as designated by the EPA | area | 6 | ||||||
Number of revisions necessary to meet the 2012 standard for particulate matter | performance_obligations | 0 | ||||||
Current level of micrograms per cubic meter that particulate matter needs to be below | 12 | ||||||
Current level of micrograms per cubic meter under 24-hour standard that particulate matter needs to be below | 35 | ||||||
Lowest limit that will cause nonattainment | 10 | ||||||
National Ambient Air Quality Standards | Electric | Minimum | |||||||
Air Quality | |||||||
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 | ||||||
National Ambient Air Quality Standards | Electric | Minimum | Subsequent event | |||||||
Air Quality | |||||||
Proposed primary (health-based) annual standard | 9 | ||||||
National Ambient Air Quality Standards | Electric | Maximum | |||||||
Air Quality | |||||||
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 | Maximum | Subsequent event | |||||||
Air Quality | |||||||
Proposed primary (health-based) annual standard | 10 | ||||||
Climate Change | Electric | |||||||
Air Quality | |||||||
Capacity of coal generation retired since the beginning of 2018, in megawatts | MW | 1,800 | ||||||
Capacity of fossil-fueled generation to be retired by the end of 2026, in megawatts | MW | 1,600 | ||||||
Company goal for percentage carbon dioxide emission reduction goal by the end of 2025 | 60% | ||||||
Company goal for percentage of carbon dioxide emissions reduction below 2005 levels by the end of 2030 | 80% | ||||||
Carbon dioxide emissions | T | 19.5 | ||||||
Climate Change | Natural gas | |||||||
Air Quality | |||||||
Carbon dioxide emissions | T | 29.3 | ||||||
Clean Water Act Cooling Water Intake Structure Rule | Electric | |||||||
Water Quality | |||||||
Number of generating units that may be retired at OCPP | generating_units | 4 | ||||||
Steam Electric Effluent Guidelines | Electric | |||||||
Water Quality | |||||||
Number of new ELG rule requirements that affect our electric utilities | performance_obligations | 2 | ||||||
Expected capital investment to be in compliance with ELG rule | $ | $ 100 | ||||||
Manufactured Gas Plant Remediation | Natural gas | |||||||
Manufactured Gas Plant Remediation | |||||||
Estimated future cash expenditures for environmental remediation | $ | 499.6 | 532.6 | |||||
Manufactured Gas Plant Remediation | Natural gas | Environmental remediation costs | |||||||
Manufactured Gas Plant Remediation | |||||||
Regulatory asset | $ | $ 610.7 | $ 630.9 | |||||
Renewables, Efficiency, and Conservation | Electric | Wisconsin | |||||||
Renewables, Efficiency, and Conservation | |||||||
Annual state renewable portfolio requirement, as a percent | 10% | ||||||
Percent of annual operating revenues used to fund renewable program | 1.20% | ||||||
Renewables, Efficiency, and Conservation | Electric | Wisconsin | WE | |||||||
Renewables, Efficiency, and Conservation | |||||||
Required renewable energy percent achieved | 8.27% | ||||||
Renewables, Efficiency, and Conservation | Electric | Wisconsin | WPS | |||||||
Renewables, Efficiency, and Conservation | |||||||
Required renewable energy percent achieved | 9.74% | ||||||
Renewables, Efficiency, and Conservation | Electric | Michigan | |||||||
Renewables, Efficiency, and Conservation | |||||||
Annual state renewable portfolio requirement, as a percent | 12.50% | ||||||
Energy optimization target, as a percent | 1% | ||||||
Percentage renewable portfolio requirement 2021 and beyond | 15% |
Supplemental Cash Flow Inform_3
Supplemental Cash Flow Information - Supplemental Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Supplemental Cash Flow Information [Abstract] | |||
Cash paid for interest, net of amount capitalized | $ 485.2 | $ 473.8 | $ 492.9 |
Cash paid for income taxes, net | 52.4 | 33.8 | 27.9 |
Significant non-cash investing and financing transactions | |||
Accounts payable related to construction costs | 197.4 | 127.8 | 153.1 |
Increase in receivable related to insurance proceeds | 0 | 41.7 | 2.7 |
Liabilities accrued for software licensing agreement | $ 7.4 | $ 0 | $ 0 |
Supplemental Cash Flow Inform_4
Supplemental Cash Flow Information - Reconciliation of Cash, Cash Equivalents, and Restricted Cash (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 |
Supplemental Cash Flow Information [Abstract] | ||||
Cash and cash equivalents | $ 28.9 | $ 16.3 | $ 24.8 | |
Restricted cash included in other current assets | 25.6 | 19.6 | 0 | |
Restricted cash included in other long-term assets | 127.7 | 51.6 | 47.8 | |
Cash, cash equivalents, and restricted cash | $ 182.2 | $ 87.5 | $ 72.6 | $ 82.3 |
Regulatory Environment - Recove
Regulatory Environment - Recovery of Natural Gas Costs (Details) $ in Millions | 1 Months Ended | ||||||
Sep. 30, 2021 | Aug. 31, 2021 USD ($) utility | Mar. 31, 2021 USD ($) | Feb. 28, 2021 USD ($) | Dec. 31, 2022 USD ($) | Oct. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | |
Public Utilities, General Disclosures | |||||||
Amounts recoverable from customers | $ 42.3 | $ 102.3 | |||||
Total regulatory assets | 3,306.9 | 3,367.1 | |||||
Regulatory assets | 3,264.6 | 3,264.8 | |||||
Energy costs recoverable through rate adjustments | |||||||
Public Utilities, General Disclosures | |||||||
Total regulatory assets | 26.9 | 85.4 | |||||
MERC extraordinary natural gas costs | |||||||
Public Utilities, General Disclosures | |||||||
Recovery period of regulatory asset | 27 months | ||||||
Total regulatory assets | $ 35.1 | $ 59.7 | |||||
Public Service Commission of Wisconsin (PSCW) | WE | Energy costs recoverable through rate adjustments | |||||||
Public Utilities, General Disclosures | |||||||
Amounts recoverable from customers | $ 54 | ||||||
Recovery period of regulatory asset | 3 months | ||||||
Public Service Commission of Wisconsin (PSCW) | WG | Energy costs recoverable through rate adjustments | |||||||
Public Utilities, General Disclosures | |||||||
Amounts recoverable from customers | $ 24 | ||||||
Recovery period of regulatory asset | 3 months | ||||||
Public Service Commission of Wisconsin (PSCW) | WPS | Energy costs recoverable through rate adjustments | |||||||
Public Utilities, General Disclosures | |||||||
Amounts recoverable from customers | $ 28 | ||||||
Recovery period of regulatory asset | 3 months | ||||||
Illinois Commerce Commission (ICC) | PGL | Energy costs recoverable through rate adjustments | |||||||
Public Utilities, General Disclosures | |||||||
Amounts recoverable from customers | $ 131 | ||||||
Recovery period of regulatory asset | 12 months | ||||||
Illinois Commerce Commission (ICC) | NSG | Energy costs recoverable through rate adjustments | |||||||
Public Utilities, General Disclosures | |||||||
Amounts recoverable from customers | $ 10 | ||||||
Recovery period of regulatory asset | 12 months | ||||||
Minnesota Public Utilities Commission (MPUC) | MERC | |||||||
Public Utilities, General Disclosures | |||||||
Number of utilities filing a joint proposal | utility | 4 | ||||||
Minnesota Public Utilities Commission (MPUC) | MERC | Energy costs recoverable through rate adjustments | |||||||
Public Utilities, General Disclosures | |||||||
Amounts recoverable from customers | $ 10 | ||||||
Recovery period of regulatory asset | 12 months | ||||||
Total regulatory assets | $ 75 | ||||||
Minnesota Public Utilities Commission (MPUC) | MERC | MERC extraordinary natural gas costs | |||||||
Public Utilities, General Disclosures | |||||||
Recovery period of regulatory asset | 27 months | ||||||
Regulatory assets | $ 65 | $ 62 | |||||
Amount of Impairment to Carrying Amount of Regulatory Assets | $ 3 |
Regulatory Environment - COVID-
Regulatory Environment - COVID-19 (Details) $ in Millions | 1 Months Ended | ||||
Mar. 31, 2021 USD ($) | Jun. 30, 2020 USD ($) | Mar. 31, 2020 order | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | |
Public Utilities, General Disclosures | |||||
Regulatory asset | $ 3,306.9 | $ 3,367.1 | |||
Public Service Commission of Wisconsin | |||||
Public Utilities, General Disclosures | |||||
Number of orders issued in response to COVID-19 | order | 2 | ||||
Illinois Commerce Commission (ICC) | |||||
Public Utilities, General Disclosures | |||||
Additional period of time deposit requirements will be waived | 4 months | ||||
Percentage below federal poverty level for which customer disconnection is disallowed | 300% | ||||
Illinois Commerce Commission (ICC) | COVID-19 | |||||
Public Utilities, General Disclosures | |||||
Recovery period of regulatory asset | 36 months | ||||
Regulatory asset | $ 9.5 | ||||
Illinois Commerce Commission (ICC) | PGL | |||||
Public Utilities, General Disclosures | |||||
Required funding to bill payment assistance program | $ 6 | $ 12 | |||
Illinois Commerce Commission (ICC) | NSG | |||||
Public Utilities, General Disclosures | |||||
Required funding to bill payment assistance program | $ 0 | $ 1.2 |
Regulatory Environment - WI 202
Regulatory Environment - WI 2023 and 2024 Rates (Details) - Public Service Commission of Wisconsin (PSCW) - 2023 and 2024 Rates | 1 Months Ended |
Dec. 31, 2022 USD ($) | |
Public Utilities, General Disclosures | |
Percentage of first 15 basis points of additional earnings retained by the utility | 100% |
Return on equity in excess of authorized amount (as a percent) | 0.15% |
Percentage of additional earnings between 15 and 75 basis points refunded to customers | 50% |
Return on equity in excess of first 15 basis points above authorized amount (as a percent) | 0.60% |
Percentage of earnings in excess of 75 basis points refunded to customers | 100% |
Commitments to contribute to Keep Wisconsin Warm Fund | $ 4,000,000 |
WE | |
Public Utilities, General Disclosures | |
Approved return on equity (as a percent) | 9.80% |
Approved common equity component average (as a percent) | 53% |
Decrease in certain customer fixed charges | $ 1 |
WE | Electric | |
Public Utilities, General Disclosures | |
Approved rate increase | $ 283,500,000 |
Approved rate increase (as a percent) | 9.10% |
WE | Natural gas | |
Public Utilities, General Disclosures | |
Approved rate increase | $ 46,100,000 |
Approved rate increase (as a percent) | 9.60% |
WE | Steam | |
Public Utilities, General Disclosures | |
Approved rate increase | $ 7,600,000 |
Approved rate increase (as a percent) | 35.30% |
WPS | |
Public Utilities, General Disclosures | |
Approved return on equity (as a percent) | 9.80% |
Approved common equity component average (as a percent) | 53% |
Decrease in certain customer fixed charges | $ 3.33 |
WPS | Electric | |
Public Utilities, General Disclosures | |
Approved rate increase | $ 120,500,000 |
Approved rate increase (as a percent) | 9.80% |
WPS | Natural gas | |
Public Utilities, General Disclosures | |
Approved rate increase | $ 26,400,000 |
Approved rate increase (as a percent) | 7.10% |
WG | |
Public Utilities, General Disclosures | |
Approved return on equity (as a percent) | 9.80% |
Approved common equity component average (as a percent) | 53% |
WG | Natural gas | |
Public Utilities, General Disclosures | |
Approved rate increase | $ 46,500,000 |
Approved rate increase (as a percent) | 6.40% |
Regulatory Environment - WI 2_2
Regulatory Environment - WI 2022 Rates (Details) - Public Service Commission of Wisconsin (PSCW) - 2022 Rates - utility | 1 Months Ended | |
Sep. 30, 2021 | Mar. 23, 2021 | |
Public Utilities, General Disclosures | ||
Period to forego filing a rate case | 1 year | |
Number of utilities entering into agreement | 3 | |
Percentage of first 15 basis points of additional earnings retained by the utility | 100% | |
Return on equity in excess of authorized amount (as a percent) | 0.15% |
Regulatory Environment - WI 2_3
Regulatory Environment - WI 2020 and 2021 Rates (Details) $ in Millions | 1 Months Ended | ||
May 31, 2021 USD ($) | Dec. 31, 2019 USD ($) utility | Dec. 31, 2022 | |
WEPCo Environmental Trust Finance I, LLC | WEPCo Environmental Trust Bonds 1.578%, due 2035 | |||
Public Utilities, General Disclosures | |||
Interest rate | 1.58% | ||
Public Service Commission of Wisconsin (PSCW) | WEPCo Environmental Trust Finance I, LLC | Electric | WEPCo Environmental Trust Bonds 1.578%, due 2035 | |||
Public Utilities, General Disclosures | |||
Proceeds from Issuance of Debt | $ 118.8 | ||
Interest rate | 1.578% | ||
Public Service Commission of Wisconsin (PSCW) | 2020 and 2021 rates | |||
Public Utilities, General Disclosures | |||
Number of utilities filing rate request | utility | 3 | ||
Number of utilities with earnings sharing mechanism | utility | 3 | ||
Percentage of first 25 basis points of additional earnings retained by the utility | 100% | ||
Return on equity in excess of authorized amount (as a percent) | 0.25% | ||
Percentage of additional earnings between 25 and 75 basis points refunded to customers | 50% | ||
Return on equity in excess of first 25 basis points above authorized amount (as a percent) | 0.50% | ||
Percentage of earnings in excess of 75 basis points refunded to customers | 100% | ||
Public Service Commission of Wisconsin (PSCW) | 2020 and 2021 rates | Electric | Tax Cuts and Jobs Act of 2017 | |||
Public Utilities, General Disclosures | |||
Amortization period | 2 years | ||
Public Service Commission of Wisconsin (PSCW) | 2020 and 2021 rates | Natural gas | Tax Cuts and Jobs Act of 2017 | |||
Public Utilities, General Disclosures | |||
Number of utilities filing rate request | utility | 3 | ||
Amortization period | 4 years | ||
Public Service Commission of Wisconsin (PSCW) | 2020 and 2021 rates | WE | |||
Public Utilities, General Disclosures | |||
Approved return on equity (as a percent) | 10% | ||
Approved common equity component average (as a percent) | 52.50% | ||
Public Service Commission of Wisconsin (PSCW) | 2020 and 2021 rates | WE | Electric | |||
Public Utilities, General Disclosures | |||
Approved rate increase | $ 15.3 | ||
Approved rate increase (as a percent) | 0.50% | ||
Pleasant Prairie power plant's book value to be securitized | $ 100 | ||
Public Service Commission of Wisconsin (PSCW) | 2020 and 2021 rates | WE | Natural gas | |||
Public Utilities, General Disclosures | |||
Approved rate increase | $ 10.4 | ||
Approved rate increase (as a percent) | 2.80% | ||
Public Service Commission of Wisconsin (PSCW) | 2020 and 2021 rates | WE | Steam | |||
Public Utilities, General Disclosures | |||
Approved rate increase | $ 1.9 | ||
Approved rate increase (as a percent) | 8.60% | ||
Public Service Commission of Wisconsin (PSCW) | 2020 and 2021 rates | WPS | |||
Public Utilities, General Disclosures | |||
Approved return on equity (as a percent) | 10% | ||
Approved common equity component average (as a percent) | 52.50% | ||
Public Service Commission of Wisconsin (PSCW) | 2020 and 2021 rates | WPS | Electric | |||
Public Utilities, General Disclosures | |||
Approved rate increase | $ 15.8 | ||
Approved rate increase (as a percent) | 1.60% | ||
Authorized revenue requirement for ReACT | $ 275 | ||
Cost of the ReACT project, excluding AFUDC | $ 342 | ||
Public Service Commission of Wisconsin (PSCW) | 2020 and 2021 rates | WPS | Electric | ReACT | |||
Public Utilities, General Disclosures | |||
Recovery period of regulatory asset | 8 years | ||
Public Service Commission of Wisconsin (PSCW) | 2020 and 2021 rates | WPS | Electric | Earnings sharing mechanisms | |||
Public Utilities, General Disclosures | |||
Amortization period | 2 years | ||
Amortization of regulatory liabilities | $ 21 | ||
Public Service Commission of Wisconsin (PSCW) | 2020 and 2021 rates | WPS | Natural gas | |||
Public Utilities, General Disclosures | |||
Approved rate increase | $ 4.3 | ||
Approved rate increase (as a percent) | 1.40% | ||
Public Service Commission of Wisconsin (PSCW) | 2020 and 2021 rates | WG | |||
Public Utilities, General Disclosures | |||
Approved return on equity (as a percent) | 10.20% | ||
Approved common equity component average (as a percent) | 52.50% | ||
Public Service Commission of Wisconsin (PSCW) | 2020 and 2021 rates | WG | Natural gas | |||
Public Utilities, General Disclosures | |||
Approved rate increase | $ (1.5) | ||
Approved rate increase (as a percent) | (0.20%) | ||
Public Service Commission of Wisconsin (PSCW) | 2020 rates | WE | Electric | Tax Cuts and Jobs Act of 2017 | |||
Public Utilities, General Disclosures | |||
Amortization of regulatory liabilities | $ 65 | ||
Public Service Commission of Wisconsin (PSCW) | 2020 rates | WE | Natural gas | Tax Cuts and Jobs Act of 2017 | |||
Public Utilities, General Disclosures | |||
Amortization of regulatory liabilities | (5) | ||
Public Service Commission of Wisconsin (PSCW) | 2020 rates | WPS | Electric | Tax Cuts and Jobs Act of 2017 | |||
Public Utilities, General Disclosures | |||
Amortization of regulatory liabilities | 11 | ||
Public Service Commission of Wisconsin (PSCW) | 2020 rates | WPS | Natural gas | Tax Cuts and Jobs Act of 2017 | |||
Public Utilities, General Disclosures | |||
Amortization of regulatory liabilities | 5 | ||
Public Service Commission of Wisconsin (PSCW) | 2020 rates | WG | Natural gas | Tax Cuts and Jobs Act of 2017 | |||
Public Utilities, General Disclosures | |||
Amortization of regulatory liabilities | 3 | ||
Public Service Commission of Wisconsin (PSCW) | 2021 rates | WE | Electric | Tax Cuts and Jobs Act of 2017 | |||
Public Utilities, General Disclosures | |||
Amortization of regulatory liabilities | 65 | ||
Public Service Commission of Wisconsin (PSCW) | 2021 rates | WE | Natural gas | Tax Cuts and Jobs Act of 2017 | |||
Public Utilities, General Disclosures | |||
Amortization of regulatory liabilities | (5) | ||
Public Service Commission of Wisconsin (PSCW) | 2021 rates | WPS | Electric | Tax Cuts and Jobs Act of 2017 | |||
Public Utilities, General Disclosures | |||
Amortization of regulatory liabilities | 39 | ||
Public Service Commission of Wisconsin (PSCW) | 2021 rates | WPS | Natural gas | Tax Cuts and Jobs Act of 2017 | |||
Public Utilities, General Disclosures | |||
Amortization of regulatory liabilities | 5 | ||
Public Service Commission of Wisconsin (PSCW) | 2021 rates | WG | Natural gas | Tax Cuts and Jobs Act of 2017 | |||
Public Utilities, General Disclosures | |||
Amortization of regulatory liabilities | $ 3 |
Regulatory Environment - PGL an
Regulatory Environment - PGL and NSG 2023 Rate Case (Details) - Illinois Commerce Commission (ICC) - 2023 Rate Case - Subsequent event $ in Millions | Jan. 06, 2023 USD ($) |
PGL | |
Public Utilities, General Disclosures | |
Requested rate increase | $ 194.7 |
Requested rate increase (as a percent) | 13% |
Requested return on equity (as a percent) | 9.90% |
Requested equity capital structure (as a percent) | 54% |
NSG | |
Public Utilities, General Disclosures | |
Requested rate increase | $ 18.7 |
Requested rate increase (as a percent) | 7.80% |
Requested return on equity (as a percent) | 9.90% |
Requested equity capital structure (as a percent) | 54% |
Regulatory Environment - PGL TP
Regulatory Environment - PGL TPTFA Rider (Details) | 1 Months Ended |
Dec. 31, 2021 | |
Illinois Commerce Commission (ICC) | PGL | TPTFA Rider | |
Public Utilities, General Disclosures | |
Recovery period of regulatory asset | 12 months |
Regulatory Environment - NSG 20
Regulatory Environment - NSG 2021 Rate Order (Details) - Illinois Commerce Commission (ICC) - 2021 Rate order - NSG $ in Millions | 1 Months Ended |
Sep. 30, 2021 USD ($) | |
Public Utilities, General Disclosures | |
Approved rate increase | $ 4.1 |
Approved rate increase (as a percent) | 4.50% |
Approved return on equity (as a percent) | 9.67% |
Approved common equity component average (as a percent) | 51.58% |
Regulatory Environment - PGL QI
Regulatory Environment - PGL QIP Rider (Details) | Dec. 31, 2022 Assurance |
Illinois Commerce Commission (ICC) | PGL | |
Public Utilities, General Disclosures | |
Amount of assurance that PGL's QIP rider costs will be recoverable | 0 |
Regulatory Environment - MERC (
Regulatory Environment - MERC (Details) - Minnesota Public Utilities Commission (MPUC) - MERC - USD ($) $ in Millions | 1 Months Ended | |
Nov. 01, 2022 | Dec. 31, 2022 | |
Public Utilities, General Disclosures | ||
Requested rate increase | $ 40.3 | |
Requested rate increase (as a percent) | 9.90% | |
Requested return on equity (as a percent) | 10.30% | |
Requested equity capital structure (as a percent) | 53% | |
Interim rate increase | $ 37 |
Regulatory Environment - MGU (D
Regulatory Environment - MGU (Details) - MPSC - MGU - USD ($) $ in Millions | 1 Months Ended | |
Sep. 30, 2021 | Jul. 31, 2020 | |
Public Utilities, General Disclosures | ||
Depreciation and interest expense approved for deferral | $ 5 | |
Approved rate increase | $ 9.3 | |
Approved rate increase (as a percent) | 6.35% | |
Approved return on equity (as a percent) | 9.85% | |
Approved common equity component average (as a percent) | 51.50% | |
Recoverable planned capital investment | $ 31.7 |
Other Income, Net (Details)
Other Income, Net (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Non-service components of net periodic benefit costs | Other income, net | Other income, net | Other income, net |
Non-service components of net periodic benefit costs | $ 104.4 | $ 72.2 | $ 41.2 |
AFUDC - Equity | 29.4 | 18 | 20.9 |
Gains (losses) from investments held in rabbi trust | (12.6) | 18.6 | 12.7 |
Other, net | (1.7) | 4.5 | 2.3 |
Other income, net | 128.8 | 133.2 | 79.5 |
Other | |||
Equity earnings of subsidiaries | $ 9.3 | $ 19.9 | $ 2.4 |
Schedule I - Income Statements
Schedule I - Income Statements (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Income statements | |||
Other income, net | $ 128.8 | $ 133.2 | $ 79.5 |
Interest expense | 515.1 | 471.1 | 493.7 |
Loss on debt extinguishment | 0 | 36.3 | 38.4 |
Income before income taxes | 1,732.6 | 1,498.8 | 1,429.3 |
Income tax benefit | (322.9) | (200.3) | (227.9) |
Net income attributed to common shareholders | 1,408.1 | 1,300.3 | 1,199.9 |
WEC Energy Group | |||
Income statements | |||
Operating expenses (income) | (1.6) | 12 | 5.3 |
Equity earnings of subsidiaries | 1,473 | 1,367 | 1,283.8 |
Other income, net | 2.4 | 1.7 | 1.3 |
Interest expense | 109.6 | 70.2 | 96.9 |
Loss on debt extinguishment | 0 | 23.1 | 38.4 |
Income before income taxes | 1,367.4 | 1,263.4 | 1,144.5 |
Income tax benefit | 40.7 | 36.9 | 55.4 |
Net income attributed to common shareholders | $ 1,408.1 | $ 1,300.3 | $ 1,199.9 |
Schedule I - Statements of Comp
Schedule I - Statements of Comprehensive Income (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Statements of comprehensive income | |||
Net income attributed to common shareholders | $ 1,408.1 | $ 1,300.3 | $ 1,199.9 |
Other comprehensive income (loss), net of tax | (3.6) | 3.6 | (2.7) |
Comprehensive income attributed to common shareholders | 1,404.5 | 1,303.9 | 1,197.2 |
Derivatives accounted for as cash flow hedges | |||
Net derivative gain (loss), net of tax expense (benefit) of $—, $0.2, and $(1.6), respectively | 0 | 0.6 | (4.3) |
Reclassification of realized net derivative (gain) loss to net income, net of tax | (0.3) | 0.9 | 1.5 |
Defined benefit plans | |||
Pension and OPEB adjustments arising during the period, net of tax expense (benefit) of $(1.3), $0.7, and $(0.2), respectively | (3.5) | 1.7 | (0.5) |
Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax | 0.2 | 0.4 | 0.6 |
Defined benefit plans, net | (3.3) | 2.1 | 0.1 |
WEC Energy Group | |||
Statements of comprehensive income | |||
Net income attributed to common shareholders | 1,408.1 | 1,300.3 | 1,199.9 |
Other comprehensive income (loss) from subsidiaries, net of tax | (2.7) | 1.4 | 0.2 |
Other comprehensive income (loss), net of tax | (3.6) | 3.6 | (2.7) |
WEC Energy Group | Derivatives accounted for as cash flow hedges | |||
Derivatives accounted for as cash flow hedges | |||
Net derivative gain (loss), net of tax expense (benefit) of $—, $0.2, and $(1.6), respectively | 0 | 0.6 | (4.3) |
Reclassification of realized net derivative (gain) loss to net income, net of tax | (0.3) | 0.9 | 1.5 |
Cash flow hedges, net | (0.3) | 1.5 | (2.8) |
WEC Energy Group | Defined benefit plans | |||
Defined benefit plans | |||
Pension and OPEB adjustments arising during the period, net of tax expense (benefit) of $(1.3), $0.7, and $(0.2), respectively | (0.8) | 0.4 | (0.4) |
Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax | 0.2 | 0.3 | 0.3 |
Defined benefit plans, net | $ (0.6) | $ 0.7 | $ (0.1) |
Schedule I Statement of Compreh
Schedule I Statement of Comprehensive Income - Taxes (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Statements of comprehensive income | |||
Net income attributed to common shareholders | $ 1,408.1 | $ 1,300.3 | $ 1,199.9 |
WEC Energy Group | |||
Statements of comprehensive income | |||
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent | 1,404.5 | 1,303.9 | 1,197.2 |
Net income attributed to common shareholders | 1,408.1 | 1,300.3 | 1,199.9 |
WEC Energy Group | Cash flow hedges | |||
Statements of comprehensive income | |||
Other Comprehensive Income (Loss), Tax, Portion Attributable to Parent | $ 0 | $ 0.2 | $ (1.6) |
Schedule I - Balance Sheets (De
Schedule I - Balance Sheets (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 |
Assets | ||||
Cash and cash equivalents | $ 182.2 | $ 87.5 | $ 72.6 | $ 82.3 |
Current assets | ||||
Prepaid income taxes | 201.8 | 182.1 | ||
Other | 261.7 | 253.4 | ||
Current assets | 3,187.7 | 2,656.7 | ||
Long-term assets | ||||
Other | 427.3 | 361.1 | ||
Long-term assets | 38,684.4 | 36,331.8 | ||
Total assets | 41,872.1 | 38,988.5 | 37,028.1 | |
Current liabilities | ||||
Current portion of long-term debt | 808.5 | 91 | ||
Other | 884.6 | 680.9 | ||
Current liabilities | 4,611 | 3,753 | ||
Long-term liabilities | ||||
Long-term debt | 14,655.7 | 13,472.4 | ||
Other | 1,475.3 | 1,203.2 | ||
Long-term liabilities | 25,644.5 | 24,122.2 | ||
Equity | ||||
Total liabilities and equity | 41,872.1 | 38,988.5 | ||
WEC Energy Group | ||||
Assets | ||||
Cash and cash equivalents | 0 | 0.5 | $ 4 | $ 0.5 |
Current assets | ||||
Accounts receivable from related parties | 0.7 | 0.6 | ||
Notes receivable from related parties | 30.9 | 29 | ||
Prepaid income taxes | 35.4 | 56.5 | ||
Other | 0.1 | 0.1 | ||
Current assets | 67.1 | 86.7 | ||
Long-term assets | ||||
Investments in subsidiaries | 16,533.4 | 15,365.4 | ||
Other | 24.2 | 21.8 | ||
Long-term assets | 16,557.6 | 15,387.2 | ||
Total assets | 16,624.7 | 15,473.9 | ||
Current liabilities | ||||
Short-term debt | 399.7 | 736.1 | ||
Current portion of long-term debt | 700 | 0 | ||
Accounts payable to related parties | 2 | 5.5 | ||
Notes payable to related parties | 332.5 | 220.4 | ||
Other | 31.8 | 21.5 | ||
Current liabilities | 1,466 | 983.5 | ||
Long-term liabilities | ||||
Long-term debt | 3,747.2 | 3,549.8 | ||
Other | 34.6 | 27.4 | ||
Long-term liabilities | 3,781.8 | 3,577.2 | ||
Equity | ||||
Common shareholders' equity | 11,376.9 | 10,913.2 | ||
Total liabilities and equity | $ 16,624.7 | $ 15,473.9 |
Schedule I - Statements of Cash
Schedule I - Statements of Cash Flows (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Operating activities | |||
Net income attributed to common shareholders | $ 1,408.1 | $ 1,300.3 | $ 1,199.9 |
Reconciliation to cash provided by operating activities | |||
Equity income in subsidiaries, net of distributions | (74.3) | (25.1) | (29.1) |
Deferred income taxes, net | 278.5 | 111 | 182.2 |
Loss on debt extinguishment | 0 | 36.3 | 38.4 |
Change in - | |||
Other current liabilities | 126.9 | (17.2) | (41.2) |
Other, net | (169.5) | (92.5) | (29.3) |
Net cash provided by operating activities | 2,060.7 | 2,032.7 | 2,196 |
Investing activities | |||
Capital contributions to subsidiaries | (45.5) | 0 | (21.2) |
Other, net | 7.8 | 27.3 | (1.8) |
Net cash used in investing activities | (2,642.4) | (2,311.8) | (2,806.8) |
Financing activities | |||
Exercise of stock options | 33.6 | 15.7 | 43.8 |
Purchase of common stock | (69.2) | (33.1) | (99.2) |
Dividends paid on common stock | (917.9) | (854.8) | (798) |
Issuance of long-term debt | 1,999.3 | 2,383.8 | 2,373.6 |
Retirement of long-term debt | (92.1) | (1,260.4) | (1,767) |
Issuance of short-term loan | 2.7 | 0.9 | 340 |
Repayment of short-term loan | 0 | (340) | 0 |
Change in commercial paper | (252.6) | 459.2 | 606.1 |
Payments for debt extinguishment and issuance costs | (15.6) | (67.2) | (55.8) |
Other, net | (11.8) | (10.1) | (11.4) |
Net cash used in financing activities | (676.4) | (294) | (601.1) |
Net change in cash, cash equivalents, and restricted cash | 94.7 | 14.9 | (9.7) |
Cash, cash equivalents, and restricted cash at beginning of year | 87.5 | 72.6 | 82.3 |
Cash, cash equivalents, and restricted cash at end of year | 182.2 | 87.5 | 72.6 |
WEC Energy Group | |||
Operating activities | |||
Net income attributed to common shareholders | 1,408.1 | 1,300.3 | 1,199.9 |
Reconciliation to cash provided by operating activities | |||
Equity income in subsidiaries, net of distributions | (437.4) | (571.3) | (385.7) |
Deferred income taxes, net | 11.6 | (1.9) | 12.7 |
Loss on debt extinguishment | 0 | 23.1 | 38.4 |
Change in - | |||
Accounts receivable from related parties | (0.1) | 0.1 | 0 |
Prepaid income taxes | 21.1 | (2.1) | (7.9) |
Accounts payable to related parties | (3.5) | (26.2) | 29.2 |
Accrued interest | 15.4 | 0.4 | (0.9) |
Other current liabilities | (5.1) | 8.2 | (1.5) |
Other, net | 5.8 | (2.5) | 9.6 |
Net cash provided by operating activities | 1,015.9 | 728.1 | 893.8 |
Investing activities | |||
Capital contributions to subsidiaries | (1,099.7) | (734) | (1,026.1) |
Return of capital from subsidiaries | 372.9 | 196.1 | 602.8 |
Short-term notes receivable from related parties, net | (1.9) | 81.8 | (88.3) |
Other, net | (2) | (1.1) | 3.7 |
Net cash used in investing activities | (730.7) | (457.2) | (507.9) |
Financing activities | |||
Exercise of stock options | 33.6 | 15.7 | 43.8 |
Purchase of common stock | (69.2) | (33.1) | (99.2) |
Dividends paid on common stock | (917.9) | (854.8) | (798) |
Issuance of long-term debt | 900 | 1,100 | 1,650 |
Retirement of long-term debt | 0 | (300) | (1,430) |
Issuance of short-term loan | 0 | 0 | 340 |
Repayment of short-term loan | 0 | (340) | 0 |
Change in commercial paper | (336.4) | 255.7 | 145.7 |
Short-term notes payable to related parties, net | 112.1 | (82.6) | (186.3) |
Payments for debt extinguishment and issuance costs | (6.7) | (33.9) | (47.3) |
Other, net | (1.2) | (1.4) | (1.1) |
Net cash used in financing activities | 285.7 | 274.4 | 382.4 |
Net change in cash, cash equivalents, and restricted cash | (0.5) | (3.5) | 3.5 |
Cash, cash equivalents, and restricted cash at beginning of year | 0.5 | 4 | 0.5 |
Cash, cash equivalents, and restricted cash at end of year | $ 0 | $ 0.5 | $ 4 |
Schedule I - Cash Dividends Rec
Schedule I - Cash Dividends Received from Subsidiaries (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
WECI | |||
Notes to parent company financial statements | |||
Return of capital from subsidiaries | $ 363.7 | $ 164.1 | $ 583.2 |
ATC Holding LLC | |||
Notes to parent company financial statements | |||
Return of capital from subsidiaries | 32 | 19.6 | |
Wispark | |||
Notes to parent company financial statements | |||
Return of capital from subsidiaries | 9.2 | ||
WEC Energy Group | |||
Notes to parent company financial statements | |||
Cash dividends received from subsidiaries | 1,035.6 | 795.7 | 898.1 |
Return of capital from subsidiaries | 372.9 | 196.1 | 602.8 |
WEC Energy Group | WE | |||
Notes to parent company financial statements | |||
Cash dividends received from subsidiaries | 630 | 360 | 395 |
WEC Energy Group | We Power | |||
Notes to parent company financial statements | |||
Cash dividends received from subsidiaries | 158.5 | 217.9 | 240.9 |
WEC Energy Group | WECI | |||
Notes to parent company financial statements | |||
Cash dividends received from subsidiaries | 87.7 | 46.4 | 33.6 |
WEC Energy Group | ATC Holding LLC | |||
Notes to parent company financial statements | |||
Cash dividends received from subsidiaries | 74.9 | 106.4 | 112.6 |
WEC Energy Group | WG | |||
Notes to parent company financial statements | |||
Cash dividends received from subsidiaries | 60 | 30 | 70 |
WEC Energy Group | UMERC | |||
Notes to parent company financial statements | |||
Cash dividends received from subsidiaries | 17 | 0 | 46 |
WEC Energy Group | Wispark | |||
Notes to parent company financial statements | |||
Cash dividends received from subsidiaries | 7.5 | 0 | 0 |
WEC Energy Group | Bluewater | |||
Notes to parent company financial statements | |||
Cash dividends received from subsidiaries | $ 0 | $ 35 | $ 0 |
Schedule I - Long-Term Debt (De
Schedule I - Long-Term Debt (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Future maturities of long-term debt outstanding | ||
2023 | $ 808.5 | |
2024 | 1,239.6 | |
2025 | 1,685.5 | |
2026 | 126.8 | |
2027 | 1,230.7 | |
Thereafter | 10,468.7 | |
Long-term debt | 14,655.7 | $ 13,472.4 |
WEC Energy Group | ||
Future maturities of long-term debt outstanding | ||
2023 | 700 | |
2024 | 600 | |
2025 | 620 | |
2026 | 0 | |
2027 | 900 | |
Thereafter | 1,650 | |
Total | 4,470 | |
Long-term debt | 3,747.2 | $ 3,549.8 |
WEC Energy Group | WECC | Support agreement related to WECC debt | ||
Future maturities of long-term debt outstanding | ||
Long-term debt | $ 50 |
Schedule I - Fair Value Measure
Schedule I - Fair Value Measurements (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Carrying amount | ||
Notes to parent company financial statements | ||
Long-term debt, including current portion | $ 15,464.2 | $ 13,563.4 |
Fair value | ||
Notes to parent company financial statements | ||
Long-term debt, including current portion | 13,921.3 | 14,819.4 |
Long-term debt, including current portion | 15,464.2 | 13,563.4 |
WEC Energy Group | Carrying amount | ||
Notes to parent company financial statements | ||
Long-term debt, including current portion | 4,447.2 | 3,549.8 |
WEC Energy Group | Fair value | ||
Notes to parent company financial statements | ||
Long-term debt, including current portion | $ 4,095.6 | $ 3,546.9 |
Schedule 1 - Guarantees (Detail
Schedule 1 - Guarantees (Details) $ in Millions | Dec. 31, 2022 USD ($) |
Notes to parent company financial statements | |
Total guarantees | $ 159.1 |
Guarantees expiring in less than one year | 41.9 |
Guarantees expiring within one to three years | 0.3 |
Guarantees with expiration over three years | 116.9 |
Standby letters of credit (1) | |
Notes to parent company financial statements | |
Total guarantees | 115.7 |
Guarantees expiring in less than one year | 8 |
Guarantees expiring within one to three years | 0.2 |
Guarantees with expiration over three years | 107.5 |
Surety bonds (2) | |
Notes to parent company financial statements | |
Total guarantees | 34 |
Guarantees expiring in less than one year | 33.9 |
Guarantees expiring within one to three years | 0.1 |
Guarantees with expiration over three years | 0 |
Other guarantees (3) | |
Notes to parent company financial statements | |
Total guarantees | 9.4 |
Guarantees expiring in less than one year | 0 |
Guarantees expiring within one to three years | 0 |
Guarantees with expiration over three years | 9.4 |
WEC Energy Group | |
Notes to parent company financial statements | |
Total guarantees | 660.3 |
Guarantees expiring in less than one year | 469.7 |
Guarantees expiring within one to three years | 1.3 |
Guarantees with expiration over three years | 189.3 |
WEC Energy Group | WECI | |
Notes to parent company financial statements | |
Total guarantees | 532 |
WEC Energy Group | Bluewater | |
Notes to parent company financial statements | |
Total guarantees | 11.3 |
WEC Energy Group | UMERC | |
Notes to parent company financial statements | |
Total guarantees | 5.2 |
WEC Energy Group | Guarantees supporting business operations | |
Notes to parent company financial statements | |
Total guarantees | 548.5 |
Guarantees expiring in less than one year | 427.8 |
Guarantees expiring within one to three years | 1.2 |
Guarantees with expiration over three years | 119.5 |
WEC Energy Group | Standby letters of credit (1) | |
Notes to parent company financial statements | |
Total guarantees | 68.4 |
Guarantees expiring in less than one year | 8 |
Guarantees expiring within one to three years | 0 |
Guarantees with expiration over three years | 60.4 |
WEC Energy Group | Surety bonds (2) | |
Notes to parent company financial statements | |
Total guarantees | 34 |
Guarantees expiring in less than one year | 33.9 |
Guarantees expiring within one to three years | 0.1 |
Guarantees with expiration over three years | 0 |
WEC Energy Group | Other guarantees (3) | |
Notes to parent company financial statements | |
Total guarantees | 9.4 |
Guarantees expiring in less than one year | 0 |
Guarantees expiring within one to three years | 0 |
Guarantees with expiration over three years | $ 9.4 |
Schedule I - Supplemental Cash
Schedule I - Supplemental Cash Flow Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Notes to parent company financial statements | |||
Cash received for income taxes, net | $ 52.4 | $ 33.8 | $ 27.9 |
WEC Energy Group | |||
Notes to parent company financial statements | |||
Cash paid for interest | 88.1 | 70.2 | 98.5 |
Cash received for income taxes, net | $ (72.9) | $ (27.9) | $ (61.5) |
Schedule I - Short-Term Notes R
Schedule I - Short-Term Notes Receivable from Related Parties (Details) - WEC Energy Group - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Notes to parent company financial statements | ||
Short-term notes receivable from related parties | $ 30.9 | $ 29 |
UMERC | ||
Notes to parent company financial statements | ||
Short-term notes receivable from related parties | 27.1 | 22 |
Bluewater | ||
Notes to parent company financial statements | ||
Short-term notes receivable from related parties | 2.7 | 7 |
Wispark | ||
Notes to parent company financial statements | ||
Short-term notes receivable from related parties | $ 1.1 | $ 0 |
Schedule I - Short-Term Notes P
Schedule I - Short-Term Notes Payable to Related Parties (Details) - WEC Energy Group - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Notes to parent company financial statements | ||
Short-term notes payable to related parties | $ 332.5 | $ 220.4 |
Integrys | ||
Notes to parent company financial statements | ||
Short-term notes payable to related parties | 115 | 5.3 |
WBS | ||
Notes to parent company financial statements | ||
Short-term notes payable to related parties | 111 | 107.7 |
WECC | ||
Notes to parent company financial statements | ||
Short-term notes payable to related parties | $ 106.5 | $ 107.4 |
Schedule II - Valuation and Q_2
Schedule II - Valuation and Qualifying Accounts (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Valuation and qualifying accounts | |||
Balance at beginning of period | $ 198.3 | $ 220.1 | $ 140 |
Expense | 86.1 | 107.4 | 102.8 |
Deferral | 62.9 | (44.8) | 55.3 |
Net write-offs | (148) | (84.4) | (77.9) |
Sale of business | 0 | 0 | (0.1) |
Balance at end of period | $ 199.3 | $ 198.3 | $ 220.1 |