COVER PAGE
COVER PAGE | 3 Months Ended |
Mar. 31, 2021shares | |
Cover [Abstract] | |
Document type | 10-Q |
Document Quarterly Report | true |
Document period end date | Mar. 31, 2021 |
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, $.01 Par Value |
Trading Symbol | WEC |
Security Exchange Name | NYSE |
Entity Current Reporting Status | Yes |
Entity Interactive Data Current | Yes |
Entity filer category | Large Accelerated Filer |
Small company | false |
Emerging growth company | false |
Entity Shell Company | false |
Entity common stock, shares outstanding | 315,434,531 |
Entity central index key | 0000783325 |
Current fiscal year end date | --12-31 |
Document fiscal year focus | 2021 |
Document fiscal period focus | Q1 |
Amendment flag | false |
CONDENSED CONSOLIDATED INCOME S
CONDENSED CONSOLIDATED INCOME STATEMENTS - USD ($) shares in Millions, $ in Millions | 3 Months Ended | |
Mar. 31, 2021 | Mar. 31, 2020 | |
Income Statement [Abstract] | ||
Operating revenues | $ 2,691.4 | $ 2,108.6 |
Operating expenses | ||
Cost of sales | 1,265.6 | 734.7 |
Other operation and maintenance | 479.9 | 455.7 |
Depreciation and amortization | 261.4 | 239.1 |
Property and revenue taxes | 55.2 | 52.5 |
Total operating expenses | 2,062.1 | 1,482 |
Operating income | 629.3 | 626.6 |
Equity in earnings of transmission affiliates | 42.6 | 39.8 |
Other income, net | 32.8 | 5.6 |
Interest expense | 119.5 | 129.4 |
Other expense | (44.1) | (84) |
Income before income taxes | 585.2 | 542.6 |
Income tax expense (benefit) | 74.9 | 90 |
Net income | 510.3 | 452.6 |
Preferred stock dividends of subsidiary | 0.3 | 0.3 |
Net loss attributable to noncontrolling interests | (0.1) | (0.2) |
Net income attributed to common shareholders | $ 510.1 | $ 452.5 |
Earnings per share | ||
Basic (in dollars per share) | $ 1.62 | $ 1.43 |
Diluted (in dollars per share) | $ 1.61 | $ 1.43 |
Weighted average common shares outstanding | ||
Basic (in shares) | 315.4 | 315.4 |
Diluted (in shares) | 316.2 | 316.7 |
CONDENSED CONSOLIDATED STATEMEN
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2021 | Mar. 31, 2020 | |
Statement of Other Comprehensive Income [Abstract] | ||
Net income (loss) | $ 510.3 | $ 452.6 |
Derivatives accounted for as cash flow hedges | ||
Net derivative loss, net of tax benefit of $—, and $1.3, respectively | 0 | (3.4) |
Reclassification of realized net derivative loss to net income, net of tax | 1 | 0.1 |
Cash flow hedges, net | 1 | (3.3) |
Defined benefit plans | ||
Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax | 0.1 | 0.3 |
Other comprehensive income (loss), net of tax | 1.1 | (3) |
Comprehensive income | 511.4 | 449.6 |
Preferred stock dividends of subsidiary | 0.3 | 0.3 |
Comprehensive loss attributed to noncontrolling interests | 0.1 | 0.2 |
Comprehensive income attributed to common shareholders | $ 511.2 | $ 449.5 |
CONDENSED CONSOLIDATED STATEM_2
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2021 | Mar. 31, 2020 | |
Statement of Comprehensive Income [Abstract] | ||
Tax benefits on unrealized loss on derivatives | $ 0 | $ 1.3 |
CONDENSED CONSOLIDATED BALANCE
CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions | Mar. 31, 2021 | Dec. 31, 2020 |
Current assets | ||
Cash and cash equivalents | $ 26.1 | $ 24.8 |
Accounts receivable and unbilled revenues, net of reserves of $259.1 and $220.1, respectively | 1,369.9 | 1,202.8 |
Materials, supplies, and inventories | 353.5 | 528.6 |
Prepayments | 258.8 | 263.4 |
Amounts recoverable from customers | 306.7 | 20 |
Other | 40.5 | 43.4 |
Current assets | 2,355.5 | 2,083 |
Long-term assets | ||
Property, plant, and equipment, net of accumulated depreciation and amortization of $9,481.4 and $9,364.7, respectively | 25,994.4 | 25,707.4 |
Regulatory assets | 3,487.1 | 3,524.1 |
Equity investment in transmission affiliates | 1,773.6 | 1,764.3 |
Goodwill | 3,052.8 | 3,052.8 |
Other | 937.2 | 896.5 |
Long-term assets | 35,245.1 | 34,945.1 |
Total assets | 37,600.6 | 37,028.1 |
Current liabilities | ||
Short-term debt | 1,580.4 | 1,776.9 |
Current portion of long-term debt | 787 | 785.8 |
Accounts payable | 656 | 880.7 |
Accrued payroll and benefits | 123 | 174 |
Other | 568.5 | 530.7 |
Current liabilities | 3,714.9 | 4,148.1 |
Long-term liabilities | ||
Long-term debt | 12,317.7 | 11,728.1 |
Deferred income taxes | 4,214.1 | 4,059.8 |
Deferred revenue, net | 406.4 | 412.2 |
Regulatory liabilities | 3,890.8 | 3,928.1 |
Environmental remediation liabilities | 532.9 | 532.9 |
Pension and OPEB obligations | 319.9 | 327 |
Other | 1,236.3 | 1,229.4 |
Long-term liabilities | 22,918.1 | 22,217.5 |
Commitments and contingencies (Note 20) | ||
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 | 4,143.6 | 4,143.7 |
Retained earnings | 6,626 | 6,329.6 |
Accumulated other comprehensive loss | (5.7) | (6.8) |
Common shareholders' equity | 10,767.1 | 10,469.7 |
Preferred stock of subsidiary | 30.4 | 30.4 |
Noncontrolling interests | 170.1 | 162.4 |
Total liabilities and equity | $ 37,600.6 | $ 37,028.1 |
CONDENSED CONSOLIDATED BALANC_2
CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions | Mar. 31, 2021 | Dec. 31, 2020 |
Statement of Financial Position [Abstract] | ||
Accounts receivable and unbilled revenues, reserves | $ 259.1 | $ 220.1 |
Property, plant, and equipment, accumulated depreciation and amortization | $ 9,481.4 | $ 9,364.7 |
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 325,000,000 | 325,000,000 |
Common stock, shares outstanding | 315,434,531 | 315,434,531 |
CONDENSED CONSOLIDATED STATEM_3
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2021 | Mar. 31, 2020 | |
Operating activities | ||
Net income (loss) | $ 510.3 | $ 452.6 |
Reconciliation to cash provided by operating activities | ||
Depreciation and amortization | 261.4 | 239.1 |
Deferred income taxes and ITCs, net | 129.6 | 92.1 |
Contributions and payments related to pension and OPEB plans | (4.1) | (3.7) |
Equity income in transmission affiliates, net of distributions | (9.2) | 0.8 |
Change in – | ||
Accounts receivable and unbilled revenues, net | (150.4) | (3.5) |
Materials, supplies, and inventories | 175.1 | 158.7 |
Amounts recoverable from customers | (286.7) | 8.1 |
Other current assets | 20.2 | 57.3 |
Accounts payable | (181.5) | (250.1) |
Other current liabilities | (2.3) | (27.7) |
Other, net | (67.2) | (33.2) |
Net cash provided by operating activities | 395.2 | 690.5 |
Investing activities | ||
Capital expenditures | (470.6) | (496.1) |
Acquisition of Jayhawk | (119.4) | 0 |
Capital contributions to transmission affiliates | 0 | (3) |
Proceeds from the sale of assets | 11.3 | 1.3 |
Proceeds from the sale of investments held in rabbi trust | 12.7 | 17 |
Other, net | 24.7 | 17.8 |
Net cash used in investing activities | (541.3) | (463) |
Financing activities | ||
Exercise of stock options | 1.2 | 16 |
Purchase of common stock | (6.6) | (40.4) |
Dividends paid on common stock | (213.7) | (199.5) |
Issuance of long-term debt | 600 | 0 |
Retirement of long-term debt | (14.7) | (14) |
Issuance of short-term loan | 0 | 340 |
Repayment of short-term loan | (340) | 0 |
Change in other short-term debt | 143.5 | (343.6) |
Other, net | (6.6) | (2.6) |
Net cash provided by (used in) financing activities | 163.1 | (244.1) |
Net change in cash, cash equivalents, and restricted cash | 17 | (16.6) |
Cash, cash equivalents, and restricted cash at beginning of period | 72.6 | 82.3 |
Cash, cash equivalents, and restricted cash at end of period | $ 89.6 | $ 65.7 |
CONDENSED CONSOLIDATED STATEM_4
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY - USD ($) $ in Millions | Total | Total common shareholders' equity | Common stock | Additional paid in capital | Retained earnings | Accumulated other comprehensive 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 |
Statements of equity | ||||||||
Net income attributed to common shareholders | 452.5 | 452.5 | 0 | 0 | 452.5 | 0 | 0 | 0 |
Net loss attributable to noncontrolling interests | (0.2) | 0 | 0 | 0 | 0 | 0 | 0 | (0.2) |
Other comprehensive income (loss) | (3) | (3) | 0 | 0 | 0 | (3) | 0 | 0 |
Common stock dividends | (199.5) | (199.5) | 0 | 0 | (199.5) | 0 | 0 | 0 |
Exercise of stock options | 16 | 16 | 0 | 16 | 0 | 0 | 0 | 0 |
Purchase of common stock | (40.4) | (40.4) | 0 | (40.4) | 0 | 0 | 0 | 0 |
Distributions to noncontrolling interests | (0.5) | 0 | 0 | 0 | 0 | 0 | 0 | (0.5) |
Stock-based compensation and other | 5.1 | 5.1 | 0 | 5.1 | 0 | 0 | 0 | 0 |
Balance at Mar. 31, 2020 | 10,484.6 | 10,344.1 | 3.2 | 4,167.3 | 6,180.7 | (7.1) | 30.4 | 110.1 |
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 |
Statements of equity | ||||||||
Net income attributed to common shareholders | 510.1 | 510.1 | 0 | 0 | 510.1 | 0 | 0 | 0 |
Net loss attributable to noncontrolling interests | (0.1) | 0 | 0 | 0 | 0 | 0 | 0 | (0.1) |
Other comprehensive income (loss) | 1.1 | 1.1 | 0 | 0 | 0 | 1.1 | 0 | 0 |
Common stock dividends | (213.7) | (213.7) | 0 | 0 | (213.7) | 0 | 0 | 0 |
Exercise of stock options | 1.2 | 1.2 | 0 | 1.2 | 0 | 0 | 0 | 0 |
Purchase of common stock | (6.6) | (6.6) | 0 | (6.6) | 0 | 0 | 0 | 0 |
Acquisition of a noncontrolling interest | 6.2 | 0 | 0 | 0 | 0 | 0 | 0 | 6.2 |
Capital contributions from noncontrolling interest | 2 | 0 | 0 | 0 | 0 | 0 | 0 | 2 |
Distributions to noncontrolling interests | (0.4) | 0 | 0 | 0 | 0 | 0 | 0 | (0.4) |
Stock-based compensation and other | 5.3 | 5.3 | 0 | 5.3 | 0 | 0 | 0 | 0 |
Balance at Mar. 31, 2021 | $ 10,967.6 | $ 10,767.1 | $ 3.2 | $ 4,143.6 | $ 6,626 | $ (5.7) | $ 30.4 | $ 170.1 |
CONDENSED CONSOLIDATED STATEM_5
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (Parenthetical) - $ / shares | 3 Months Ended | |
Mar. 31, 2021 | Mar. 31, 2020 | |
Statement of Stockholders' Equity [Abstract] | ||
Common stock dividend declared (in dollars per share) | $ 0.6775 | $ 0.6325 |
GENERAL INFORMATION
GENERAL INFORMATION | 3 Months Ended |
Mar. 31, 2021 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
GENERAL INFORMATION | GENERAL INFORMATION 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 business. As used in these notes, the term "financial statements" refers to the condensed 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. In this report, when we refer to "the Company," "us," "we," "our," or "ours," we are referring to WEC Energy Group and all of its subsidiaries. On our financial statements, we consolidate our majority-owned subsidiaries which we control and 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 sheets related to the minority interests at Bishop Hill III, Blooming Grove, Coyote Ridge, Jayhawk, Tatanka Ridge, and Upstream held by third parties. We use the equity method to account for investments in companies we do not control but over which we exercise significant influence regarding their operating and financial policies. As a result of our limited voting rights, we account for ATC and ATC Holdco as equity method investments. See Note 17, Investment in Transmission Affiliates, for more information. We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2020. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three months ended March 31, 2021, are not necessarily indicative of expected results for 2021 due to seasonal variations and other factors, including any continuing financial impacts from the COVID-19 pandemic. In management's opinion, we have included all adjustments, normal and recurring in nature, necessary for a fair presentation of our financial results. |
ACQUISITIONS
ACQUISITIONS | 3 Months Ended |
Mar. 31, 2021 | |
Business Combinations [Abstract] | |
ACQUISITIONS | ACQUISITIONS The purchase price of certain acquisitions below includes intangibles recorded as long-term liabilities related to PPAs and interconnection agreements. See Note 16, Goodwill and Intangibles, for more information. Acquisition of a Wind Energy Generation Facility in Kansas In February 2021, WECI completed the acquisition of a 90% ownership interest in Jayhawk, a 190 MW wind generating facility under construction in Bourbon and Crawford counties, Kansas, for $119.4 million, which included transaction costs, and was allocated primarily to property, plant, and equipment. In March 2021, WECI incurred an additional $37.9 million of capital expenditures for the project for a total investment of $157.3 million. Upon completion, we expect WECI's total investment to be approximately $302 million. The project has an offtake agreement with an unaffiliated third party for all of the energy to be produced by the facility for a period of 10 years. Under the Tax Legislation, WECI's investment in Jayhawk is expected to qualify 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 we will be entitled to tax benefits equal to our ownership interest. Commercial operation is expected to begin by the end of 2021. Jayhawk is included in the non-utility energy infrastructure segment. Acquisition of a Wind Energy 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 $240.1 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. Under the Tax Legislation, WECI's investment in 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 we will be entitled to tax benefits equal to our ownership interest. Tatanka Ridge is included in the non-utility energy infrastructure segment. Acquisition of Wind Generation Facilities in Nebraska In August 2019, WECI signed an agreement to acquire an 80% ownership interest in Thunderhead, a 300 MW wind generating facility under construction in Antelope and Wheeler counties in Nebraska, for a total investment of approximately $338 million. In February 2020, WECI agreed to acquire an additional 10% ownership interest in Thunderhead for $43 million. The project has an offtake agreement with an unaffiliated third party for all of the energy to be produced by the facility for 12 years. Under the Tax Legislation, WECI's investment in Thunderhead is expected to qualify for PTCs. The transaction was approved by FERC in April 2020, and commercial operation was initially expected to begin by the end of 2020. However, due to a delay in construction of the required substation, Thunderhead is now expected to begin commercial operation by the end of 2021. The transaction is expected to close upon commercial operation. Thunderhead will be included in the non-utility energy infrastructure segment. |
OPERATING REVENUES
OPERATING REVENUES | 3 Months Ended |
Mar. 31, 2021 | |
Revenue from Contract with Customer [Abstract] | |
OPERATING REVENUES | OPERATING REVENUES For more information about our operating revenues, see Note 1(d), Operating Revenues, in our 2020 Annual Report on Form 10-K. 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 have 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 Three Months Ended March 31, 2021 Electric $ 1,095.0 $ — $ — $ 1,095.0 $ — $ — $ — $ 1,095.0 Natural gas 627.3 693.5 225.6 1,546.4 14.6 — (13.3) 1,547.7 Total regulated revenues 1,722.3 693.5 225.6 2,641.4 14.6 — (13.3) 2,642.7 Other non-utility revenues — — 4.7 4.7 23.2 — (1.6) 26.3 Total revenues from contracts with customers 1,722.3 693.5 230.3 2,646.1 37.8 — (14.9) 2,669.0 Other operating revenues 9.4 9.9 3.0 22.3 99.8 0.1 (99.8) (1) 22.4 Total operating revenues $ 1,731.7 $ 703.4 $ 233.3 $ 2,668.4 $ 137.6 $ 0.1 $ (114.7) $ 2,691.4 (in millions) Wisconsin Illinois Other States Total Utility Non-Utility Energy Infrastructure Corporate Reconciling WEC Energy Group Consolidated Three Months Ended March 31, 2020 Electric $ 1,034.6 $ — $ — $ 1,034.6 $ — $ — $ — $ 1,034.6 Natural gas 458.9 433.6 139.8 1,032.3 14.5 — (14.1) 1,032.7 Total regulated revenues 1,493.5 433.6 139.8 2,066.9 14.5 — (14.1) 2,067.3 Other non-utility revenues — — 4.4 4.4 16.4 0.4 (1.6) 19.6 Total revenues from contracts with customers 1,493.5 433.6 144.2 2,071.3 30.9 0.4 (15.7) 2,086.9 Other operating revenues 5.4 14.0 2.2 21.6 98.7 0.1 (98.7) (1) 21.7 Total operating revenues $ 1,498.9 $ 447.6 $ 146.4 $ 2,092.9 $ 129.6 $ 0.5 $ (114.4) $ 2,108.6 (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 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: Electric Utility Operating Revenues Three Months Ended March 31 (in millions) 2021 2020 Residential $ 423.7 $ 404.9 Small commercial and industrial 331.4 323.6 Large commercial and industrial 209.5 194.6 Other 7.8 7.3 Total retail revenues 972.4 930.4 Wholesale 39.7 42.1 Resale 62.7 45.2 Steam 14.8 8.4 Other utility revenues 5.4 8.5 Total electric utility operating revenues $ 1,095.0 $ 1,034.6 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 Three Months Ended March 31, 2021 Residential $ 347.6 $ 333.9 $ 87.9 $ 769.4 Commercial and industrial 176.4 102.7 43.9 323.0 Total retail revenues 524.0 436.6 131.8 1,092.4 Transport 24.4 74.2 11.0 109.6 Other utility revenues (1) 78.9 182.7 82.8 344.4 Total natural gas utility operating revenues $ 627.3 $ 693.5 $ 225.6 $ 1,546.4 (in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues Three Months Ended March 31, 2020 Residential $ 313.1 $ 282.9 $ 95.3 $ 691.3 Commercial and industrial 151.3 91.4 51.7 294.4 Total retail revenues 464.4 374.3 147.0 985.7 Transport 24.1 72.7 10.5 107.3 Other utility revenues (1) (29.6) (13.4) (17.7) (60.7) Total natural gas utility operating revenues $ 458.9 $ 433.6 $ 139.8 $ 1,032.3 (1) Includes revenues subject to collection from (refund to) customers for purchased gas adjustment costs. 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: Three Months Ended March 31 (in millions) 2021 2020 Wind generation revenues $ 15.8 $ 9.3 We Power revenues (1) 5.8 5.5 Appliance service revenues 4.7 4.4 Distributed renewable solar project revenues — 0.4 Total other non-utility operating revenues $ 26.3 $ 19.6 (1) 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, and we continually amortize the deferred carrying costs to revenues over the related lease term that We Power has with WE. During the three months ended March 31, 2021 and 2020, we recorded $5.8 million and $5.5 million, respectively, of revenues related to these deferred carrying costs. These contract liabilities are presented as deferred revenue, net on our balance sheets. Other Operating Revenues Other operating revenues consist primarily of the following: Three Months Ended March 31 (in millions) 2021 2020 Late payment charges $ 15.0 $ 12.1 Alternative revenues 6.2 8.5 Other 1.2 1.1 Total other operating revenues $ 22.4 $ 21.7 |
CREDIT LOSSES
CREDIT LOSSES | 3 Months Ended |
Mar. 31, 2021 | |
Credit Loss [Abstract] | |
CREDIT LOSSES | CREDIT LOSSES 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. See Note 22, Regulatory Environment, for information on certain regulatory actions that were and/or are being taken for the purpose of ensuring that essential utility services are available to our customers during the COVID-19 pandemic. We have included tables below that show our gross third-party receivable balances and the related allowance for credit losses at March 31, 2021 and December 31, 2020, by reportable segment. (in millions) Wisconsin Illinois Other States Total Utility Non-Utility Energy Infrastructure Corporate WEC Energy Group Consolidated March 31, 2021 Accounts receivable and unbilled revenues $ 1,056.9 $ 465.8 $ 77.5 $ 1,600.2 $ 24.9 $ 3.9 $ 1,629.0 Allowance for credit losses 129.5 122.0 7.6 259.1 — — 259.1 Accounts receivable and unbilled revenues, net (1) $ 927.4 $ 343.8 $ 69.9 $ 1,341.1 $ 24.9 $ 3.9 $ 1,369.9 Total accounts receivable, net – past due greater than 90 days (1) $ 68.8 $ 38.4 $ 3.8 $ 111.0 $ — $ — $ 111.0 Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1) 97.5 % 100.0 % — % 95.0 % — % — % 95.0 % (in millions) Wisconsin Illinois Other States Total Utility Non-Utility Energy Infrastructure Corporate WEC Energy Group Consolidated December 31, 2020 Accounts receivable and unbilled revenues $ 899.8 $ 393.9 $ 79.8 $ 1,373.5 $ 45.0 $ 4.4 $ 1,422.9 Allowance for credit losses 102.1 111.6 6.4 220.1 — — 220.1 Accounts receivable and unbilled revenues, net (1) $ 797.7 $ 282.3 $ 73.4 $ 1,153.4 $ 45.0 $ 4.4 $ 1,202.8 Total accounts receivable, net – past due greater than 90 days (1) $ 84.8 $ 34.5 $ 3.5 $ 122.8 $ — $ — $ 122.8 Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1) 97.6 % 100.0 % — % 95.5 % — % — % 95.5 % (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 March 31, 2021, $742.0 million, or 54.2%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses. In addition, we have received specific orders related to the deferral of certain costs (including credit losses) incurred as a result of the COVID-19 pandemic. The additional protections related to our accounts receivable and unbilled revenue balances provided by these orders are subject to prudency reviews and are still being assessed. They are not reflected in the percentages in the above table or this note. See Note 22, Regulatory Environment, for more information on these orders. A rollforward of the allowance for credit losses by reportable segment for the three months ended March 31, 2021 and 2020 is included below: (in millions) Wisconsin Illinois Other States Total Utility Corporate WEC Energy Group Consolidated Balance at December 31, 2020 $ 102.1 $ 111.6 $ 6.4 $ 220.1 $ — $ 220.1 Provision for credit losses 13.7 7.1 1.3 22.1 — 22.1 Provision for credit losses deferred for future recovery or refund 22.3 3.1 — 25.4 — 25.4 Write-offs charged against the allowance (18.5) (2.8) (0.5) (21.8) — (21.8) Recoveries of amounts previously written off 9.9 3.0 0.4 13.3 — 13.3 Balance at March 31, 2021 $ 129.5 $ 122.0 $ 7.6 $ 259.1 $ — $ 259.1 The increase in the allowance for credit losses at March 31, 2021, compared to December 31, 2020, was 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 the continued economic disruptions caused by the COVID-19 pandemic, including continued high unemployment rates. Also, as a result of the winter moratorium rules, which are discussed in more detail below, and the COVID-19 pandemic and related regulatory orders we have received, we have been unable to disconnect any of our Wisconsin and Illinois residential customers since the fourth quarter of 2019. See Note 22, Regulatory Environment, for more information. (in millions) Wisconsin Illinois Other States Total Utility Corporate WEC Energy Group Consolidated Balance at December 31, 2019 $ 59.9 $ 75.9 $ 4.1 $ 139.9 $ 0.1 $ 140.0 Provision for credit losses 13.7 14.4 0.7 28.8 — 28.8 Provision for credit losses deferred for future recovery or refund 3.3 29.5 — 32.8 — 32.8 Write-offs charged against the allowance (19.7) (31.6) (1.3) (52.6) — (52.6) Recoveries of amounts previously written off 10.5 4.9 0.4 15.8 — 15.8 Balance at March 31, 2020 $ 67.7 $ 93.1 $ 3.9 $ 164.7 $ 0.1 $ 164.8 |
REGULATORY ASSETS AND LIABILITI
REGULATORY ASSETS AND LIABILITIES | 3 Months Ended |
Mar. 31, 2021 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
REGULATORY ASSETS AND LIABILITIES | REGULATORY ASSETS AND LIABILITIES The following regulatory assets and liabilities were reflected on our balance sheets at March 31, 2021 and December 31, 2020. For more information on our regulatory assets and liabilities, see Note 6, Regulatory Assets and Liabilities, in our 2020 Annual Report on Form 10-K. (in millions) March 31, 2021 December 31, 2020 Regulatory assets Pension and OPEB costs $ 1,073.9 $ 1,101.6 Plant retirements 733.1 740.8 Environmental remediation costs 623.1 638.2 Income tax related items 459.3 454.6 Energy costs recoverable through rate adjustments (1) 301.6 1.1 Asset retirement obligations 186.0 181.3 SSR 134.6 135.6 Securitization 106.9 105.2 Uncollectible expense 73.0 82.0 Derivatives 9.6 26.5 Other, net 92.7 77.2 Total regulatory assets $ 3,793.8 $ 3,544.1 Balance sheet presentation Amounts recoverable from customers (1) $ 306.7 $ 20.0 Regulatory assets 3,487.1 3,524.1 Total regulatory assets $ 3,793.8 $ 3,544.1 (1) The increase in these regulatory assets primarily relates to the high natural gas costs that were incurred as a result of the extreme winter weather conditions in February 2021. See Note 22, Regulatory Environment, for more information. (in millions) March 31, 2021 December 31, 2020 Regulatory liabilities Income tax related items $ 2,111.0 $ 2,137.7 Removal costs 1,234.6 1,221.1 Pension and OPEB benefits 373.1 378.1 Electric transmission costs 75.9 78.5 Earnings sharing mechanisms 30.8 36.9 Energy costs refundable through rate adjustments 24.7 59.9 Derivatives 17.4 16.4 Energy efficiency programs 11.0 9.9 Uncollectible expense 3.2 25.5 Other, net 21.6 15.1 Total regulatory liabilities $ 3,903.3 $ 3,979.1 Balance sheet presentation Other current liabilities $ 12.5 $ 51.0 Regulatory liabilities 3,890.8 3,928.1 Total regulatory liabilities $ 3,903.3 $ 3,979.1 |
PROPERTY, PLANT, AND EQUIPMENT
PROPERTY, PLANT, AND EQUIPMENT | 3 Months Ended |
Mar. 31, 2021 | |
Property, Plant and Equipment [Abstract] | |
PROPERTY, PLANT, AND EQUIPMENT | PROPERTY, PLANT, AND EQUIPMENTDuring a significant rain event in May 2020, an underground steam tunnel in downtown Milwaukee flooded and steam vented into WE’s Public Service Building. The damage to the building from the flooding and steam was extensive and will require significant repairs and restorations. As of March 31, 2021, WE had incurred $49.3 million of costs related to these repairs and restorations. WE received $20.0 million of insurance proceeds in 2020 to cover a portion of these costs and $16.8 million was recorded as a receivable for future insurance recoveries as of March 31, 2021. The remaining $12.5 million of costs were included in other operation and maintenance expense in 2020. We anticipate that the majority of future capital expenditures required to restore the Public Service Building will either be covered by insurance or recovery will be requested from the PSCW. As such, we do not currently expect a significant impact to our future results of operations, and although we may experience differences between periods in the timing of cash flows, we also do not currently expect a significant impact to our long-term cash flows from this event. |
COMMON EQUITY
COMMON EQUITY | 3 Months Ended |
Mar. 31, 2021 | |
Equity [Abstract] | |
COMMON EQUITY | COMMON EQUITY Stock-Based Compensation During the three months ended March 31, 2021, the Compensation Committee of our Board of Directors awarded the following stock-based compensation awards to our directors, officers, and certain other key employees: Award Type Number of Awards Stock options (1) 530,612 Restricted shares (2) 69,681 Performance units 152,382 (1) Stock options awarded had a weighted-average exercise price of $91.06 and a weighted-average grant date fair value of $13.20 per option. (2) Restricted shares awarded had a weighted-average grant date fair value of $91.06 per share. 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 Gas Storage, LLC; ATC Holding LLC, which holds our ownership interest in ATC; 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. See Note 11, Common Equity, in our 2020 Annual Report on Form 10-K for additional information on these and other restrictions. We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future. Common Stock Dividends On April 15, 2021, our Board of Directors declared a quarterly cash dividend of $0.6775 per share, payable on June 1, 2021, to shareholders of record on May 14, 2021. |
SHORT-TERM DEBT AND LINES OF CR
SHORT-TERM DEBT AND LINES OF CREDIT | 3 Months Ended |
Mar. 31, 2021 | |
Short-term Debt [Abstract] | |
SHORT-TERM DEBT AND LINES OF CREDIT | SHORT-TERM DEBT AND LINES OF CREDIT The following table shows our short-term borrowings and their corresponding weighted-average interest rates: (in millions, except percentages) March 31, 2021 December 31, 2020 Commercial paper Amount outstanding $ 1,580.4 $ 1,436.9 Weighted-average interest rate on amounts outstanding 0.19 % 0.21 % Term loan Amount outstanding $ — $ 340.0 Weighted-average interest rate on amounts outstanding n/a 0.99 % Our average amount of commercial paper borrowings based on daily outstanding balances during the three months ended March 31, 2021 was $1,445.3 million with a weighted-average interest rate during the period of 0.18%. 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. The weighted-average interest rate on the term loan during the three months ended March 31, 2021 was 0.99%. In March 2021, we repaid the term loan using the net proceeds from the issuance of our 0.80% Senior Notes. See Note 9, Long-Term Debt, for more information. 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: (in millions) Maturity March 31, 2021 WEC Energy Group October 2022 1,200.0 WE October 2022 500.0 WPS October 2022 400.0 WG October 2022 350.0 PGL October 2022 350.0 Total short-term credit capacity $ 2,800.0 Less: Letters of credit issued inside credit facilities $ 2.3 Commercial paper outstanding 1,580.4 Available capacity under existing agreements $ 1,217.3 |
LONG-TERM DEBT
LONG-TERM DEBT | 3 Months Ended |
Mar. 31, 2021 | |
Long-term Debt, Unclassified [Abstract] | |
LONG-TERM DEBT | LONG-TERM DEBT WEC Energy Group, Inc. In March 2021, we issued $600.0 million of 0.80% Senior Notes due March 15, 2024, and used the net proceeds to repay the $340.0 million 364-day term loan entered into in March 2020 and for general corporate purposes. |
MATERIALS, SUPPLIES, AND INVENT
MATERIALS, SUPPLIES, AND INVENTORIES | 3 Months Ended |
Mar. 31, 2021 | |
Inventory Disclosure [Abstract] | |
MATERIALS, SUPPLIES, AND INVENTORIES | MATERIALS, SUPPLIES, AND INVENTORIES Our inventory consisted of: (in millions) March 31, 2021 December 31, 2020 Materials and supplies $ 218.3 $ 218.1 Natural gas in storage 68.3 224.9 Fossil fuel 66.9 85.6 Total $ 353.5 $ 528.6 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. For interim periods, the difference between current projected replacement cost and the LIFO cost for quantities of natural gas temporarily withdrawn from storage is recorded as a temporary LIFO liquidation debit or credit. At March 31, 2021, we had a temporary LIFO liquidation credit of $66.3 million recorded within other current liabilities on our balance sheet. Due to seasonality requirements, PGL and NSG expect these interim reductions in LIFO layers to be replenished by year end. Substantially all other materials and supplies, natural gas in storage, and fossil fuel inventories are recorded using the weighted-average cost method of accounting. |
INCOME TAXES
INCOME TAXES | 3 Months Ended |
Mar. 31, 2021 | |
Income Tax Disclosure [Abstract] | |
INCOME TAXES | INCOME TAXES The provision for income taxes differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes as a result of the following: Three Months Ended March 31, 2021 Three Months Ended March 31, 2020 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Statutory federal income tax $ 122.8 21.0 % $ 113.9 21.0 % State income taxes net of federal tax benefit 36.9 6.3 % 34.0 6.3 % PTCs (34.0) (5.8) % (18.4) (3.4) % Federal excess deferred tax amortization – Wisconsin unprotected (30.3) (5.2) % (22.1) (4.1) % Federal excess deferred tax amortization (14.6) (2.5) % (13.0) (2.4) % Uncertain tax positions (8.2) (1.4) % — — % Other 2.3 0.4 % (4.4) (0.8) % Total income tax expense $ 74.9 12.8 % $ 90.0 16.6 % The effective tax rates of 12.8% and 16.6% for the three months ended March 31, 2021 and 2020, respectively, differ from the United States statutory federal income tax rate of 21%, primarily due to PTCs generated from ownership interests in wind generation facilities in our non-utility energy infrastructure segment and the recognition of certain unprotected deferred tax benefits created as a result of the Tax Legislation. In accordance with the rate order received from the PSCW in December 2019, our Wisconsin utilities are amortizing the unprotected deferred tax benefits over periods ranging from two years to four years, to reduce near-term rate impacts to their customers. In addition, the impact of the protected benefits associated with the Tax Legislation, as discussed in more detail below, drove a decrease in the effective tax rate, which was partially offset by state income taxes. 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 (see federal excess deferred tax amortization line above). See Note 22, Regulatory Environment, for more information on unprotected tax credits. |
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS | 3 Months Ended |
Mar. 31, 2021 | |
Fair Value Disclosures [Abstract] | |
FAIR VALUE MEASUREMENTS | FAIR VALUE MEASUREMENTSFair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods. Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. When possible, we base the valuations of our derivative assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally-developed inputs. The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy: March 31, 2021 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 12.3 $ 1.6 $ — $ 13.9 FTRs — — 0.9 0.9 Coal contracts — 2.6 — 2.6 Total derivative assets $ 12.3 $ 4.2 $ 0.9 $ 17.4 Investments held in rabbi trust $ 71.6 $ — $ — $ 71.6 Derivative liabilities Natural gas contracts $ 3.1 $ 1.0 $ — $ 4.1 Coal contracts — 0.3 — 0.3 Interest rate swaps — 5.1 — 5.1 Total derivative liabilities $ 3.1 $ 6.4 $ — $ 9.5 December 31, 2020 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 11.7 $ 2.0 $ — $ 13.7 FTRs — — 2.4 2.4 Coal contracts — 1.8 — 1.8 Total derivative assets $ 11.7 $ 3.8 $ 2.4 $ 17.9 Investments held in rabbi trust $ 79.6 $ — $ — $ 79.6 Derivative liabilities Natural gas contracts $ 7.7 $ 6.4 $ — $ 14.1 Coal contracts — 1.2 — 1.2 Interest rate swaps — 6.8 — 6.8 Total derivative liabilities $ 7.7 $ 14.4 $ — $ 22.1 The derivative assets and liabilities listed in the tables above include options, swaps, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices and interest rates. They also include FTRs, which are used to manage electric transmission congestion costs in the MISO Energy and Operating Reserves Markets. 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. During the three months ended March 31, 2021, we recorded $4.0 million of net unrealized gains in earnings related to the investments held at the end of the period, compared with $14.2 million of net unrealized losses recorded during the same quarter in 2020. The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy: Three Months Ended March 31 (in millions) 2021 2020 Balance at the beginning of the period $ 2.4 $ 3.1 Purchases 0.1 — Settlements (1.6) (2.2) Balance at the end of the period $ 0.9 $ 0.9 Fair Value of Financial Instruments The following table shows the financial instruments included on our balance sheets that were not recorded at fair value: March 31, 2021 December 31, 2020 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock of subsidiary $ 30.4 $ 29.9 $ 30.4 $ 32.3 Long-term debt, including current portion (1) 13,041.8 14,139.0 12,450.5 14,343.2 (1) The carrying amount of long-term debt excludes finance lease obligations of $62.9 million and $63.4 million at March 31, 2021 and December 31, 2020, 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 | 3 Months Ended |
Mar. 31, 2021 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
DERIVATIVE INSTRUMENTS | DERIVATIVE INSTRUMENTS We use derivatives as part of our risk management program to manage the risks associated with the price volatility of 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 an asset or liability measured at fair value unless they qualify for the normal purchases and sales exception and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities. None of our derivatives are designated as hedging instruments, with the exception of our interest rate swaps, which have been designated as cash flow hedges. The following table shows our derivative assets and derivative liabilities, along with their classification on our balance sheets. March 31, 2021 December 31, 2020 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Other current Natural gas contracts $ 13.4 $ 3.6 $ 13.0 $ 12.9 FTRs 0.9 — 2.4 — Coal contracts 2.4 0.1 1.6 0.8 Interest rate swaps — 5.1 — 6.8 Total other current (1) 16.7 8.8 17.0 20.5 Other long-term Natural gas contracts 0.5 0.5 0.7 1.2 Coal contracts 0.2 0.2 0.2 0.4 Total other long-term (1) 0.7 0.7 0.9 1.6 Total $ 17.4 $ 9.5 $ 17.9 $ 22.1 (1) On our balance sheets, we classify derivative assets and liabilities as other current or other long-term based on the maturities of the underlying contracts. Realized gains (losses) on derivatives not designated as hedging instruments are primarily recorded in cost of sales on the income statements. Our estimated notional sales volumes and realized gains (losses) were as follows: Three Months Ended March 31, 2021 Three Months Ended March 31, 2020 (in millions) Volumes Gains (Losses) Volumes Gains (Losses) Natural gas contracts 59.8 Dth $ (7.5) 58.4 Dth $ (24.7) FTRs 8.4 MWh 2.1 7.2 MWh 1.4 Total $ (5.4) $ (23.3) On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At March 31, 2021 and December 31, 2020, we had posted cash collateral of $5.6 million and $18.9 million, respectively, in our margin accounts. These amounts were recorded on our balance sheets in other current assets. The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets: March 31, 2021 December 31, 2020 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 17.4 $ 9.5 $ 17.9 $ 22.1 Gross amount not offset on the balance sheet (3.1) (3.1) (6.9) (7.7) (1) Net amount $ 14.3 $ 6.4 $ 11.0 $ 14.4 (1) Includes cash collateral posted of $0.8 million. Cash Flow Hedges As of March 31, 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 provide a fixed interest rate of 4.9765% on $250.0 million of the $500.0 million of outstanding 2007 Junior Notes through November 15, 2021. As these swaps qualify for cash flow hedge accounting treatment, the related gains and losses are being deferred in accumulated other comprehensive loss and are being amortized to interest expense as interest is 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: Three Months Ended March 31 (in millions) 2021 2020 Derivative loss recognized in other comprehensive loss $ — $ (4.7) Net derivative loss reclassified from accumulated other comprehensive loss to interest expense (1.4) (0.1) Total interest expense line item on the income statements 119.5 129.4 We estimate that during the next twelve months $3.8 million will be reclassified from accumulated other comprehensive loss as an increase to interest expense. |
GUARANTEES
GUARANTEES | 3 Months Ended |
Mar. 31, 2021 | |
Guarantees [Abstract] | |
GUARANTEES | GUARANTEES The following table shows our outstanding guarantees: Expiration (in millions) Total Amounts Committed at March 31, 2021 Less Than 1 Year 1 to 3 Years Over 3 Years Guarantees supporting transactions of subsidiaries (1) $ 138.5 $ 53.5 $ 1.5 $ 83.5 Standby letters of credit (2) 73.3 5.1 — 68.2 Surety bonds (3) 12.4 12.3 0.1 — Other guarantees (4) 10.0 — — 10.0 Total guarantees $ 234.2 $ 70.9 $ 1.6 $ 161.7 (1) Consists of $4.2 million, $8.2 million, and $126.1 million to support the business operations of UMERC, Bluewater, and WECI, respectively. (2) 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. (3) Primarily for workers compensation self-insurance programs and obtaining various licenses, permits, and rights-of-way. These amounts are not reflected on our balance sheets. (4) Consists of $10.0 million related to workers compensation coverage for which a liability was recorded on our balance sheets. |
EMPLOYEE BENEFITS
EMPLOYEE BENEFITS | 3 Months Ended |
Mar. 31, 2021 | |
Retirement Benefits [Abstract] | |
EMPLOYEE BENEFITS | EMPLOYEE BENEFITS The following tables show the components of net periodic benefit cost (credit) for our benefit plans. Pension Benefits Three Months Ended March 31 (in millions) 2021 2020 Service cost $ 13.9 $ 13.1 Interest cost 21.9 26.1 Expected return on plan assets (50.6) (47.9) Loss on plan settlement 0.1 0.3 Amortization of prior service cost 0.4 0.4 Amortization of net actuarial loss 27.4 24.2 Net periodic benefit cost $ 13.1 $ 16.2 OPEB Benefits Three Months Ended March 31 (in millions) 2021 2020 Service cost $ 4.2 $ 4.1 Interest cost 3.6 4.7 Expected return on plan assets (16.4) (15.1) Amortization of prior service credit (4.0) (3.7) Amortization of net actuarial gain (5.7) (5.4) Net periodic benefit credit $ (18.3) $ (15.4) During the three months ended March 31, 2021, we made contributions and payments of $3.6 million related to our pension plans and $0.5 million related to our OPEB plans. We expect to make contributions and payments of $7.9 million related to our pension plans and $1.6 million related to our OPEB plans during the remainder of 2021, dependent upon various factors affecting us, including our liquidity position and possible tax law changes. |
GOODWILL AND INTANGIBLES
GOODWILL AND INTANGIBLES | 3 Months Ended |
Mar. 31, 2021 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
GOODWILL | 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 March 31, 2021. We had no changes to the carrying amount of goodwill during the three months ended March 31, 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 March 31, 2021. Intangible Assets At March 31, 2021 , we had $5.7 million of indefinite-lived intangible assets primarily related to a MGU trade name obtained through an acquisition, which is included in other long-term assets on our balance sheets. We had no changes to the carrying amount of these intangible assets during the three months ended March 31, 2021. 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. See Note 2, Acquisitions, for more information. March 31, 2021 December 31, 2020 (in millions) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Gross Carrying Amount Accumulated Amortization Net Carrying Amount PPAs (1) $ 84.6 $ (1.6) $ 83.0 $ 76.1 $ — $ 76.1 Proxy revenue swap (2) 7.2 (1.5) 5.7 7.2 (1.3) 5.9 Interconnection agreements (3) 5.1 (0.4) 4.7 5.1 (0.3) 4.8 Total intangible liabilities $ 96.9 $ (3.5) $ 93.4 $ 88.4 $ (1.6) $ 86.8 (1) Represents PPAs related to the acquisition of Blooming Grove, Tatanka Ridge, and Jayhawk expiring between 2030 and 2032. The weighted-average remaining useful life of the PPAs is approximately 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 approximately eight 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 approximately 20 years. Amortization related to these intangibles for the three months ended March 31, 2021 and 2020, was not significant. Amortization for the next five years is estimated to be: For the Years Ending December 31 (in millions) 2022 2023 2024 2025 2026 Amortization to be recorded in operating revenues $ 8.1 $ 8.1 $ 8.1 $ 8.1 $ 8.1 Amortization to be recorded in other operation and maintenance 0.2 0.2 0.2 0.2 0.2 |
INVESTMENT IN TRANSMISSION AFFI
INVESTMENT IN TRANSMISSION AFFILIATES | 3 Months Ended |
Mar. 31, 2021 | |
Equity Method Investments and Joint Ventures [Abstract] | |
INVESTMENT IN TRANSMISSION AFFILIATES | 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. The following tables provide a reconciliation of the changes in our investments in ATC and ATC Holdco: Three Months Ended March 31, 2021 (in millions) ATC ATC Holdco Total Balance at beginning of period $ 1,733.5 $ 30.8 $ 1,764.3 Add: Earnings from equity method investment 41.7 0.9 42.6 Less: Distributions 33.4 — 33.4 Add: Other 0.1 — 0.1 Balance at end of period $ 1,741.9 $ 31.7 $ 1,773.6 Three Months Ended March 31, 2020 (in millions) ATC ATC Holdco Total Balance at beginning of period $ 1,684.7 $ 36.1 $ 1,720.8 Add: Earnings from equity method investment 39.6 0.2 39.8 Add: Capital contributions 3.0 — 3.0 Less: Distributions 40.6 — 40.6 Less: Return of capital — 5.3 5.3 Balance at end of period $ 1,686.7 $ 31.0 $ 1,717.7 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: Three Months Ended March 31 (in millions) 2021 2020 Charges to ATC for services and construction $ 6.0 $ 6.0 Charges from ATC for network transmission services 92.6 86.9 Our balance sheets included the following receivables and payables for services provided to or received from ATC: (in millions) March 31, 2021 December 31, 2020 Accounts receivable for services provided to ATC $ 2.4 $ 3.7 Accounts payable for services received from ATC 30.3 29.3 Amounts due from ATC for transmission infrastructure upgrades (1) 5.3 4.6 (1) The transmission infrastructure upgrades were primarily related to WE's and WPS's construction of their new solar projects, Badger Hollow II and Badger Hollow I, respectively. Summarized financial data for ATC is included in the tables below: Three Months Ended March 31 (in millions) 2021 2020 Income statement data Operating revenues $ 188.7 $ 186.8 Operating expenses 95.1 95.2 Other expense, net 28.5 28.5 Net income $ 65.1 $ 63.1 (in millions) March 31, 2021 December 31, 2020 Balance sheet data Current assets $ 90.0 $ 92.7 Noncurrent assets 5,431.8 5,400.6 Total assets $ 5,521.8 $ 5,493.3 Current liabilities $ 420.1 $ 310.8 Long-term debt 2,412.5 2,512.2 Other noncurrent liabilities 385.0 378.2 Members' equity 2,304.2 2,292.1 Total liabilities and members' equity $ 5,521.8 $ 5,493.3 |
SEGMENT INFORMATION
SEGMENT INFORMATION | 3 Months Ended |
Mar. 31, 2021 | |
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 March 31, 2021, 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 holds our ownership interests in the following wind generating facilities: ▪ 90% ownership interest in Bishop Hill III, located in Henry County, Illinois, ▪ 80% ownership interest in Coyote Ridge, located in Brookings County, South Dakota, ▪ 90% ownership interest in Upstream, located in Antelope County, Nebraska, ▪ 90% ownership interest in Blooming Grove, located in McLean County, Illinois, ▪ 85% ownership interest in Tatanka Ridge, located in Deuel County, South Dakota, and ▪ 90% ownership interest in Jayhawk, located in Bourbon and Crawford counties, Kansas. See Note 2, Acquisitions, for more information on Tatanka Ridge and Jayhawk. • The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, the Peoples Energy, LLC holding company, Wispark LLC, Wisvest LLC, Wisconsin Energy Capital Corporation, WEC Business Services LLC, and also included the operations of WPS Power Development, LLC during the first quarter of 2020 prior to the sale of its remaining solar facilities in the fourth quarter of 2020. All of our operations are located within the United States. The following tables show summarized financial information related to our reportable segments for the three months ended March 31, 2021 and 2020: Utility Operations (in millions) Wisconsin Illinois Other States Total Utility Operations Electric Transmission Non-Utility Energy Infrastructure Corporate and Other Reconciling Eliminations WEC Energy Group Consolidated Three Months Ended March 31, 2021 External revenues $ 1,731.7 $ 703.4 $ 233.3 $ 2,668.4 $ — $ 22.9 $ 0.1 $ — $ 2,691.4 Intersegment revenues — — — — — 114.7 — (114.7) — Other operation and maintenance 341.9 109.3 23.2 474.4 — 8.9 (1.8) (1.6) 479.9 Depreciation and amortization 176.2 52.7 9.2 238.1 — 31.0 6.6 (14.3) 261.4 Equity in earnings of transmission affiliates — — — — 42.6 — — — 42.6 Interest expense 140.1 16.5 1.5 158.1 4.9 18.0 24.2 (85.7) 119.5 Income tax expense (benefit) 48.1 41.4 8.4 97.9 9.8 0.1 (32.9) — 74.9 Net income 256.6 112.1 24.7 393.4 28.0 71.3 17.6 — 510.3 Net income attributed to common shareholders 256.3 112.1 24.7 393.1 28.0 71.4 17.6 — 510.1 Utility Operations (in millions) Wisconsin Illinois Other States Total Utility Operations Electric Transmission Non-Utility Energy Infrastructure Corporate and Other Reconciling Eliminations WEC Energy Group Consolidated Three Months Ended March 31, 2020 External revenues $ 1,498.9 $ 447.6 $ 146.4 $ 2,092.9 $ — $ 15.2 $ 0.5 $ — $ 2,108.6 Intersegment revenues — — — — — 114.4 — (114.4) — Other operation and maintenance 330.8 104.1 21.7 456.6 — 5.2 (1.6) (4.5) 455.7 Depreciation and amortization 165.4 47.5 7.8 220.7 — 24.5 6.1 (12.2) 239.1 Equity in earnings of transmission affiliates — — — — 39.8 — — — 39.8 Interest expense 143.1 16.0 2.2 161.3 4.8 15.3 35.1 (87.1) 129.4 Income tax expense (benefit) 51.2 39.5 8.9 99.6 9.9 11.2 (30.7) — 90.0 Net income (loss) 247.0 107.3 26.3 380.6 25.0 65.3 (18.3) — 452.6 Net income (loss) attributed to common shareholders 246.7 107.3 26.3 380.3 25.0 65.5 (18.3) — 452.5 |
VARIABLE INTEREST ENTITIES
VARIABLE INTEREST ENTITIES | 3 Months Ended |
Mar. 31, 2021 | |
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Determination Methodology and Factors [Abstract] | |
VARIABLE INTEREST ENTITIES | VARIABLE INTEREST ENTITIES The primary beneficiary of a variable interest entity must consolidate the entity's assets and liabilities. In addition, certain disclosures are required for significant interest holders in variable interest entities. We assess our relationships with potential variable interest entities, such as our coal suppliers, natural gas suppliers, coal transporters, natural gas transporters, and other counterparties related to PPAs, investments, and joint ventures. In making this assessment, we consider, along with other factors, the potential that our contracts or other arrangements provide subordinated financial support, the obligation to absorb the entity's losses, the right to receive residual returns of the entity, and the power to direct the activities that most significantly impact the entity's economic performance. 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 variable interest entity 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 March 31, 2021 and December 31, 2020, our equity investment in ATC was $1,741.9 million and $1,733.5 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 variable interest entity 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 March 31, 2021 and December 31, 2020, our equity investment in ATC Holdco was $31.7 million and $30.8 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC Holdco. See Note 17, 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 Agreement We have a PPA that represents a variable interest. This agreement is for 236 MWs of firm capacity from a natural gas-fired cogeneration facility, and we account for it as a finance lease. The agreement includes no minimum energy requirements over the remaining term of approximately one year. We have examined the risks of the entity, including operations, maintenance, dispatch, financing, fuel costs, and other factors, and have determined that we are not the primary beneficiary of the entity. We do not hold an equity or debt interest in the entity, and there is no residual guarantee associated with the PPA. We have $11.2 million of required capacity payments over the remaining term of this agreement. We believe that the required capacity payments under this contract will continue to be recoverable in rates, and our maximum exposure to loss is limited to these capacity payments. |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 3 Months Ended |
Mar. 31, 2021 | |
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 wind 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 wind generating facilities. Our minimum future commitments related to these purchase obligations as of March 31, 2021, including those of our subsidiaries, were approximately $11.1 billion. Environmental Matters Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as sulfur dioxide, NOx, fine particulates, mercury, and GHGs; water intake and discharges; management of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites. Air Quality National Ambient Air Quality Standards After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, creating a more stringent standard than the 2008 NAAQS. The 2015 ozone standard lowered the 8-hour limit for ground-level ozone. In December 2020, the EPA completed its 5-year review of the ozone standard and issued a final decision to retain, without any changes, the existing 2015 standard. Under Executive Order 13990, the Biden Administration ordered that all agencies review existing regulations, orders, guidance documents, policies, and similar actions promulgated, issued or adopted between January 20, 2017 and January 20, 2021. Consequently, the December 2020 decision to retain the 2015 ozone standards with no changes is currently under review by the EPA. The EPA issued final nonattainment area designations for the 2015 ozone standard in April 2018. The following counties within our Wisconsin service territories were designated as partial nonattainment: Door, Kenosha, Sheboygan, Manitowoc, and Northern Milwaukee/Ozaukee. This re-designation was challenged in the D.C. Circuit Court of Appeals in Clean Wisconsin et al. v. U.S. Environmental Protection Agency. A decision was issued in July 2020 remanding the rule to the EPA for further evaluation. Based on the 2017 to 2019 data, the EPA re-designated Door County as attainment/maintenance in June 2020. In February 2021, the Wisconsin Department of Natural Resources proposed draft revisions to the Wisconsin Administrative Code to adopt the 2015 ozone standard and incorporate by reference the federal air pollution monitoring requirements related to the NAAQS. The comment period for the proposed rule revisions ended April 15, 2021. 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 associated state or federal rules. In addition to the 2015 ozone standard, in December 2020, the EPA completed its 5-year review of the 2012 standard for particulate matter, including fine particulate matter. The EPA determined that no revisions were necessary to the current standard. All counties within our service territories are in attainment with the 2012 standards. This determination is also subject to review under Executive Order 13990. Climate Change The ACE rule, effective since September 2019, was vacated by the D.C. Circuit Court of Appeals in January 2021. The ACE rule replaced the Clean Power Plan and provided existing coal-fired generating units with standards for achieving GHG emission reductions. In a memorandum issued to the EPA regional administrators in February 2021, the EPA stated that the D.C. Circuit Court decision meant no existing rule regulates GHG emissions from electric generating units. The EPA is currently reviewing its options for such regulations. In January 2021, the EPA finalized a rule to revise the New Source Performance Standards for GHG emissions from new, modified, and reconstructed fossil-fueled power plants. The rule became effective March 14, 2021; however, on March 17, 2021 the EPA asked the D.C. Circuit Court of Appeals to vacate and remand the final rule. Despite this uncertainty, we continue to move forward on the ESG Progress Plan, which is heavily focused on reducing GHG emissions. 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 by 2025. By the end of 2020, we were able to reduce CO 2 emissions from our electric generation fleet by more than 50% below 2005 levels. As a result, we announced new goals in May 2021. We are committing to a 60% reduction in carbon emissions from our electric generation fleet by 2025 and an 80% reduction 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 carbon emissions by 2050. We have already retired more than 1,800 MW of coal-fired generation since the beginning of 2018. As part of the ESG Progress Plan, we expect to retire approximately 1,800 MW of additional fossil-fueled generation by 2025, which includes the planned retirements in 2023-2024 of OCPP Units 5-8 and the jointly-owned Columbia Units 1-2. We continue to reduce methane emissions by improving our natural gas distribution system. Our initial 2030 goal called for a 30% reduction in methane emissions from a 2011 baseline. Given advancements with renewable natural gas, we are setting a new target across our natural gas distribution operations to achieve net-zero methane emissions by the end of 2030. We are required to report our CO 2 equivalent emissions from the electric generating facilities we operate under the EPA Greenhouse Gases Reporting Program. We reported CO 2 equivalent emissions of 20.1 million metric tonnes to the EPA for 2020. The level of CO 2 and other GHG emissions varies from year to year and is dependent on the level of electric generation and mix of fuel sources, which is determined primarily by demand, the availability of the generating units, the unit cost of fuel consumed, and how our units are dispatched by MISO. We are also required to report CO 2 equivalent amounts related to the natural gas that our natural gas utilities distribute and sell. We reported aggregated CO 2 equivalent emissions of 27.0 million metric tonnes to the EPA for 2020. Cross-State Air Pollution Rule Update Rule Revision In 2015, the EPA determined that several upwind states had failed to submit state implementation plans that addressed their "Good Neighbor" obligations (i.e., the states projected NOx emissions significantly contribute to a continuing downwind nonattainment and/or maintenance problem); therefore, by statute, the EPA was required to issue a federal implementation plan. In March 2021, the EPA finalized a CSAPR update rule revision that keeps nine of the 21 CSAPR affected states (including Wisconsin) as a Group 2 NOx ozone season trading program source and found that the prior CSAPR update is sufficient to meet its "Good Neighbor" obligations. No further NOx reductions would be needed within these nine states. This rule becomes effective June 29, 2021. We do not expect that the final rule will have a material impact on our financial condition or results of operations. Water Quality Clean Water Act Cooling Water Intake Structure Rule In August 2014, the EPA issued a final regulation under Section 316(b) of the Clean Water Act that requires the location, design, construction, and capacity of cooling water intake structures at existing power plants to reflect the BTA for minimizing adverse environmental impacts. The rule became effective in October 2014 and applies to all of our existing generating facilities with cooling water intake structures, except for the ERGS units, which were permitted under the rules governing new facilities. We have received BTA determinations for OC 5 through OC 8, Weston Units 2, 3, and 4, and Valley power plant. Although we currently believe that existing technology at the Port Washington Generating Station satisfies the BTA requirements, final determinations will not be made until the discharge permit is renewed for this facility, which is expected to be in 2021. We anticipate that the permit renewal will include a final BTA determination to address all of the Section 316(b) rule requirements. As a result of past capital investments completed to address Section 316(b) compliance 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 systems at Weston Unit 3 and OC 7 and OC 8. Wastewater treatment system modifications also will be required for wet FGD discharges and site wastewater from the OCPP and ERGS units. Based on engineering cost estimates, we expect that compliance with the ELG rule will require approximately $110 million in capital investment. 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: (in millions) March 31, 2021 December 31, 2020 Regulatory assets $ 623.1 $ 638.2 Reserves for future environmental remediation 532.9 532.9 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. We are working with the EPA on a closeout process for the Consent Decree. 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, 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, and WE, entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Western District of Wisconsin in June 2013. As a result of the continued implementation of the Consent Decree related to the jointly owned Columbia and Edgewater plants, the Edgewater 4 generating unit was retired in September 2018. Wisconsin Power and Light Company has started the process to close out this Consent Decree. |
SUPPLEMENTAL CASH FLOW INFORMAT
SUPPLEMENTAL CASH FLOW INFORMATION | 3 Months Ended |
Mar. 31, 2021 | |
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract] | |
SUPPLEMENTAL CASH FLOW INFORMATION | SUPPLEMENTAL CASH FLOW INFORMATION Three Months Ended March 31 (in millions) 2021 2020 Cash paid for interest, net of amount capitalized $ 76.8 $ 85.8 Cash received for income taxes, net (2.5) (11.2) Significant non-cash investing and financing transactions: Accounts payable related to construction costs 97.8 102.5 Receivable related to insurance proceeds for property damage (1) 2.7 — (1) See Note 6, Property, Plant, and Equipment, for information about a steam incident at WE's Public Service Building. The statements of cash flows include our activity related to cash, cash equivalents, and restricted cash. Our restricted cash primarily consists of the 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. Our restricted cash also includes the restricted 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 these wind generation facilities. The following table reconciles the cash, cash equivalents, and restricted cash amounts reported within the balance sheets to the total of these amounts shown on the statements of cash flows: (in millions) March 31, 2021 December 31, 2020 Cash and cash equivalents $ 26.1 $ 24.8 Restricted cash included in other current assets 10.6 — Restricted cash included in other long term assets 52.9 47.8 Cash, cash equivalents, and restricted cash $ 89.6 $ 72.6 |
REGULATORY ENVIRONMENT
REGULATORY ENVIRONMENT | 3 Months Ended |
Mar. 31, 2021 | |
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. On March 23, 2021, WE and WG requested 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. On March 30, 2021, the PSCW approved the requests to recover the costs over a period of three months, beginning in April 2021. On March 30, 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 is authorized to recover 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 are being recovered over a period of 12 months, which started on April 1, 2021. PGL's and NSG's natural gas costs will be reviewed for prudency by the ICC as part of their annual natural gas cost reconciliation, which will be filed with the ICC in April 2022. In February 2021, MERC incurred approximately $75 million of natural gas costs in excess of the benchmark set in its GCRM. MERC expects to file for recovery of these additional costs with the MPUC in September 2021 and expects to recover them over a period of 12 months. Natural gas costs incurred at MGU and UMERC in excess of the amount included in their respective rates were not significant. Coronavirus Disease – 2019 The global outbreak of COVID-19 was declared a pandemic by the WHO and the CDC. COVID-19 has spread globally, including throughout the United States and, in turn, our service territories. Each of the states in which our regulated utilities operate declared a public health emergency and issued shelter-in-place orders in response to the COVID-19 pandemic. All of the shelter-in-place orders have since expired or been lifted. The PSCW, the ICC, the MPUC, and the MPSC have all issued written orders requiring certain actions to ensure that essential utility services were, and continue to be, 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. The PSCW has affirmed that this authorization for deferral includes the incremental increase in uncollectible expense above what is currently being recovered in rates. As WE, WPS, and WG already have a cost recovery mechanism in place to recover uncollectible expense for residential customers, this new deferral only impacts the recovery of uncollectible expense for their commercial and industrial customers. See Note 4, Credit Losses, for information regarding changes to our allowance for credit losses. As of March 31, 2021, the total amount deferred at our Wisconsin utilities related to the COVID-19 pandemic was not significant. The PSCW will review the recoverability and examine the prudency of any deferred amounts in future rate proceedings. 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 began on November 1, 2020 and ended on April 15, 2021. 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. Utilities are required to offer a deferred payment arrangement to low-income residential customers prior to disconnecting service. The order also allows 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. 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 established 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 the recovery of incremental direct costs resulting from COVID-19, foregone late fees and reconnection charges, and the costs associated with their 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 March 31, 2021, PGL's and NSG's regulatory assets related to the COVID-19 pandemic were $20.0 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 began on December 1, 2020 and ended on March 31, 2021. The ICC issued a written order on March 18, 2021 approving a second settlement agreement negotiated by Illinois utilities, ICC staff, and certain intervenors. The key terms of this new settlement agreement are as follows: • Utilities could start sending disconnection notices, on a staggered basis, as of April 1, 2021. Disconnections will follow a staggered schedule based on customer arrears and income levels (e.g. low income versus non-low income customers). Utilities are not allowed to disconnect customers for non-payment prior to June 30, 2021 if the customer's household income is below 300% of the federal poverty level and the customer is on a deferred payment plan. • Utilities will continue to offer flexible deferred payment arrangements with reduced down payment requirements to residential customers through June 30, 2021. Deferred payment arrangements will vary based on income level. • Reconnection fees will be 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 will 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. During April 2021, PGL's bill payment assistance program ended as all $18.0 million of funds were exhausted. NSG's bill payment assistance program is ongoing as funds remain available. • Costs related to the provisions in the settlement agreement, including costs related to the bill payment assistance programs, will be 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. The MPUC will review the recoverability and examine the prudency of any deferred amounts in future rate proceedings. As of March 31, 2021, amounts deferred at MERC related to the COVID-19 pandemic were not significant. 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. The order was to remain in effect until 60 days after Minnesota's declared peacetime emergency expired. 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 upon the earlier of an Executive Secretary finding the transition plan was complete, or 90 days following the expiration of Minnesota's declared peacetime emergency. MERC filed its transition plan in April 2021. In accordance with the transition plan, and upon it being subsequently deemed complete by the Executive Secretary, MERC will resume 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 will continue to offer flexible deferred payment arrangements to residential customers. For customers who enter, or are complying with, a payment arrangement, MERC will not impose any service deposits, down payments, interest, late payment fees, or reconnections fees through April 30, 2022. Currently, Minnesota's peacetime emergency is set to expire on May 14, 2021, but this date is subject to change. The annual winter moratorium in Minnesota that generally prohibits MERC from disconnecting residential customers for non-payment began on October 15, 2020 and ended on April 15, 2021. 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 include the suspension of disconnections, late payment fees, deposits, and reconnection fees for certain vulnerable customers. In addition, utilities are required to extend access to and enhance the flexibility of payment plans to customers financially impacted by COVID-19. The order will remain in effect until further notice from the MPSC. 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 provide protections to more customers than required by the MPSC order, and include suspending disconnections for all residential customers, waiving deposit requirements for new service, suspending the assessment of late fees for customers that have 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 exceeds the amounts being recovered in rates. In July 2020, the MPSC issued an order denying Michigan utilities' ability to defer additional COVID-19 related expenses and certain foregone revenues. The MPSC indicated that utilities can still seek recovery of these costs and foregone revenues by filing additional information on the specifics of their request. MGU and UMERC filed comments with the MPSC in November 2020 indicating that they have not experienced any material additional COVID-19 related expenses or foregone revenues, but that they will continue to monitor them and will notify the MPSC if they become material. At March 31, 2021, our Michigan utilities had not recorded any deferrals related to the COVID-19 pandemic. Wisconsin Electric Power Company, Wisconsin Public Service Corporation, and Wisconsin Gas LLC 2022 Rates On March 30, 2021, WE, WPS, and WG filed an application with the PSCW for the approval of certain accounting treatments which, if approved, would allow them to maintain their current 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 support the application, and the utilities expect to file their next rate cases by no later than May 1, 2022. The application filed with the PSCW includes the following key proposals: • WE, WPS, and WG would amortize, in 2022, certain previously deferred balances to offset approximately half of their forecasted revenue deficiencies. • WG would defer 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 would be allowed to defer any increases in tax expense due to changes in tax law that occur in 2021 and/or 2022. • WE, WPS, and WG would maintain their earnings sharing mechanisms for 2022, with modification. The earnings sharing mechanisms would be modified to authorize the utility to retain 100% of the first 15 basis points of earnings above its currently authorized ROE. This modification would expire on December 31, 2022. The earnings sharing mechanisms would otherwise remain as currently authorized. We expect the PSCW to review and consider the application during the second quarter of 2021. 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 became effective January 1, 2020. The final orders reflect 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 reflect 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 will be amortized in each of 2020 and 2021. For WPS, approximately $11 million of tax benefits were amortized in 2020 and approximately $39 million are being 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 is net of $21 million of refunds related to its 2018 earnings sharing mechanism. These refunds are being made to customers evenly over two years, with half returned in 2020 and the remainder being 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 reflect 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 will be amortized each year. For WPS and WG, approximately $5 million and $3 million, respectively, of previously deferred tax benefits will be 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 related fees. In November 2020, the PSCW issued a written order approving the application. The securitization is expected to reduce the carrying costs for the $100 million, benefiting customers. The WPS rate order allows WPS to collect the previously deferred revenue requirement for ReACT™ costs above the authorized $275.0 million level. The total cost of the ReACT™ project was $342 million. This regulatory asset will be collected from customers over eight years. All three Wisconsin utilities will continue having an earnings sharing mechanism through 2021. The earnings sharing mechanism was modified from its previous structure to one that is consistent with other Wisconsin investor-owned utilities. Under this earnings sharing mechanism, if the utility earns above its authorized ROE: (i) the utility retains 100.0% of earnings for the first 25 basis points above the authorized ROE; (ii) 50.0% of the next 50 basis points is refunded to customers; and (iii) 100.0% of any remaining excess earnings is refunded to customers. In addition, the rate orders also require 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 North Shore Gas Company 2021 Rate Case On October 15, 2020, NSG filed a request with the ICC to increase its natural gas rates. NSG's request is targeting a rate increase of $7.6 million (8.5%) and reflects a 10.0% ROE and a common equity component average of 52.5%. The proposed natural gas rate increase is 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 1, 2015. New rates are expected to be effective in September 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's QIP rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. In March 2021, PGL filed its 2020 reconciliation with the ICC, which, along with the 2019, 2018, 2017, and 2016 reconciliations, are still pending. As of March 31, 2021, there can be no assurance that all costs incurred under PGL's QIP rider during the open reconciliation years will be deemed recoverable by the ICC. Michigan Gas Utilities Corporation 2021 Rate Application 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 will help to mitigate the impacts from delaying the filing of the rate case. On March 22, 2021, MGU filed a request with the MPSC to increase its natural gas rates. MGU's request is targeting a rate increase of $15.1 million (10.7%) and reflects a 10.2% ROE and a common equity component of 52.5%. The proposed natural gas rate |
NEW ACCOUNTING PRONOUNCEMENTS
NEW ACCOUNTING PRONOUNCEMENTS | 3 Months Ended |
Mar. 31, 2021 | |
Accounting Standards Update and Change in Accounting Principle [Abstract] | |
NEW ACCOUNTING PRONOUNCEMENTS | NEW ACCOUNTING PRONOUNCEMENTS Simplifying the Accounting for Income Taxes In December 2019, the FASB issued ASU 2019-12, Simplifying the Accounting for Income Taxes. The new standard removes certain exceptions for performing intraperiod allocation and calculating income taxes in interim periods and also adds guidance to reduce complexity in certain areas, including recognizing deferred taxes for tax goodwill and allocating taxes to members of a consolidated group. The guidance was effective for annual and interim periods beginning after December 15, 2020. The adoption of ASU 2019-12, effective January 1, 2021, did not have a significant impact on our financial statements and related disclosures. Reference Rate Reform In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met. The amendments apply only to contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform. The amendments are effective for all entities as of March 12, 2020 through December 31, 2022. We are currently evaluating the impact this guidance may have on our financial statements and related disclosures. |
GENERAL INFORMATION (Policies)
GENERAL INFORMATION (Policies) | 3 Months Ended |
Mar. 31, 2021 | |
Accounting Policies [Abstract] | |
Consolidation | As used in these notes, the term "financial statements" refers to the condensed 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. In this report, when we refer to "the Company," "us," "we," "our," or "ours," we are referring to WEC Energy Group and all of its subsidiaries.On our financial statements, we consolidate our majority-owned subsidiaries which we control and 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 sheets related to the minority interests at Bishop Hill III, Blooming Grove, Coyote Ridge, Jayhawk, Tatanka Ridge, and Upstream held by third parties |
Basis of accounting | We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2020. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three months ended March 31, 2021, are not necessarily indicative of expected results for 2021 due to seasonal variations and other factors, including any continuing financial impacts from the COVID-19 pandemic. In management's opinion, we have included all adjustments, normal and recurring in nature, necessary for a fair presentation of our financial results. |
Credit losses | Our exposure to credit losses is related to our accounts receivable and unbilled revenue balances, which are 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 |
Fair value measurement | Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods. Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. When possible, we base the valuations of our derivative assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally-developed inputs. |
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 an asset or liability measured at fair value unless they qualify for the normal purchases and sales exception and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities. |
New accounting pronouncements | Simplifying the Accounting for Income Taxes In December 2019, the FASB issued ASU 2019-12, Simplifying the Accounting for Income Taxes. The new standard removes certain exceptions for performing intraperiod allocation and calculating income taxes in interim periods and also adds guidance to reduce complexity in certain areas, including recognizing deferred taxes for tax goodwill and allocating taxes to members of a consolidated group. The guidance was effective for annual and interim periods beginning after December 15, 2020. The adoption of ASU 2019-12, effective January 1, 2021, did not have a significant impact on our financial statements and related disclosures. Reference Rate Reform In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met. The amendments apply only to contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform. The amendments are effective for all entities as of March 12, 2020 through December 31, 2022. We are currently evaluating the impact this guidance may have on our financial statements and related disclosures. |
Other non-utility revenues | |
Disaggregation of Operating Revenues | |
Revenue Recognition | 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, and we continually amortize the deferred carrying costs to revenues over the related lease term that We Power has with WE. During the three months ended March 31, 2021 and 2020, we recorded $5.8 million and $5.5 million, respectively, of revenues related to these deferred carrying costs. These contract liabilities are presented as deferred revenue, net on our balance sheets. |
OPERATING REVENUES (Tables)
OPERATING REVENUES (Tables) | 3 Months Ended |
Mar. 31, 2021 | |
Disaggregation of Operating Revenues | |
Operating revenues disaggregated by revenue source | 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 have 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 Three Months Ended March 31, 2021 Electric $ 1,095.0 $ — $ — $ 1,095.0 $ — $ — $ — $ 1,095.0 Natural gas 627.3 693.5 225.6 1,546.4 14.6 — (13.3) 1,547.7 Total regulated revenues 1,722.3 693.5 225.6 2,641.4 14.6 — (13.3) 2,642.7 Other non-utility revenues — — 4.7 4.7 23.2 — (1.6) 26.3 Total revenues from contracts with customers 1,722.3 693.5 230.3 2,646.1 37.8 — (14.9) 2,669.0 Other operating revenues 9.4 9.9 3.0 22.3 99.8 0.1 (99.8) (1) 22.4 Total operating revenues $ 1,731.7 $ 703.4 $ 233.3 $ 2,668.4 $ 137.6 $ 0.1 $ (114.7) $ 2,691.4 (in millions) Wisconsin Illinois Other States Total Utility Non-Utility Energy Infrastructure Corporate Reconciling WEC Energy Group Consolidated Three Months Ended March 31, 2020 Electric $ 1,034.6 $ — $ — $ 1,034.6 $ — $ — $ — $ 1,034.6 Natural gas 458.9 433.6 139.8 1,032.3 14.5 — (14.1) 1,032.7 Total regulated revenues 1,493.5 433.6 139.8 2,066.9 14.5 — (14.1) 2,067.3 Other non-utility revenues — — 4.4 4.4 16.4 0.4 (1.6) 19.6 Total revenues from contracts with customers 1,493.5 433.6 144.2 2,071.3 30.9 0.4 (15.7) 2,086.9 Other operating revenues 5.4 14.0 2.2 21.6 98.7 0.1 (98.7) (1) 21.7 Total operating revenues $ 1,498.9 $ 447.6 $ 146.4 $ 2,092.9 $ 129.6 $ 0.5 $ (114.4) $ 2,108.6 |
Revenues from contracts with customers | Electric | |
Disaggregation of Operating Revenues | |
Operating revenues disaggregated by revenue source | The following table disaggregates electric utility operating revenues into customer class: Electric Utility Operating Revenues Three Months Ended March 31 (in millions) 2021 2020 Residential $ 423.7 $ 404.9 Small commercial and industrial 331.4 323.6 Large commercial and industrial 209.5 194.6 Other 7.8 7.3 Total retail revenues 972.4 930.4 Wholesale 39.7 42.1 Resale 62.7 45.2 Steam 14.8 8.4 Other utility revenues 5.4 8.5 Total electric utility operating revenues $ 1,095.0 $ 1,034.6 |
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 Three Months Ended March 31, 2021 Residential $ 347.6 $ 333.9 $ 87.9 $ 769.4 Commercial and industrial 176.4 102.7 43.9 323.0 Total retail revenues 524.0 436.6 131.8 1,092.4 Transport 24.4 74.2 11.0 109.6 Other utility revenues (1) 78.9 182.7 82.8 344.4 Total natural gas utility operating revenues $ 627.3 $ 693.5 $ 225.6 $ 1,546.4 (in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues Three Months Ended March 31, 2020 Residential $ 313.1 $ 282.9 $ 95.3 $ 691.3 Commercial and industrial 151.3 91.4 51.7 294.4 Total retail revenues 464.4 374.3 147.0 985.7 Transport 24.1 72.7 10.5 107.3 Other utility revenues (1) (29.6) (13.4) (17.7) (60.7) Total natural gas utility operating revenues $ 458.9 $ 433.6 $ 139.8 $ 1,032.3 (1) Includes revenues subject to collection from (refund to) customers for purchased gas adjustment costs. |
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: Three Months Ended March 31 (in millions) 2021 2020 Wind generation revenues $ 15.8 $ 9.3 We Power revenues (1) 5.8 5.5 Appliance service revenues 4.7 4.4 Distributed renewable solar project revenues — 0.4 Total other non-utility operating revenues $ 26.3 $ 19.6 |
Other operating revenues | |
Disaggregation of Operating Revenues | |
Operating revenues disaggregated by revenue source | Other operating revenues consist primarily of the following: Three Months Ended March 31 (in millions) 2021 2020 Late payment charges $ 15.0 $ 12.1 Alternative revenues 6.2 8.5 Other 1.2 1.1 Total other operating revenues $ 22.4 $ 21.7 |
CREDIT LOSSES (Tables)
CREDIT LOSSES (Tables) | 3 Months Ended |
Mar. 31, 2021 | |
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 March 31, 2021 and December 31, 2020, by reportable segment. (in millions) Wisconsin Illinois Other States Total Utility Non-Utility Energy Infrastructure Corporate WEC Energy Group Consolidated March 31, 2021 Accounts receivable and unbilled revenues $ 1,056.9 $ 465.8 $ 77.5 $ 1,600.2 $ 24.9 $ 3.9 $ 1,629.0 Allowance for credit losses 129.5 122.0 7.6 259.1 — — 259.1 Accounts receivable and unbilled revenues, net (1) $ 927.4 $ 343.8 $ 69.9 $ 1,341.1 $ 24.9 $ 3.9 $ 1,369.9 Total accounts receivable, net – past due greater than 90 days (1) $ 68.8 $ 38.4 $ 3.8 $ 111.0 $ — $ — $ 111.0 Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1) 97.5 % 100.0 % — % 95.0 % — % — % 95.0 % (in millions) Wisconsin Illinois Other States Total Utility Non-Utility Energy Infrastructure Corporate WEC Energy Group Consolidated December 31, 2020 Accounts receivable and unbilled revenues $ 899.8 $ 393.9 $ 79.8 $ 1,373.5 $ 45.0 $ 4.4 $ 1,422.9 Allowance for credit losses 102.1 111.6 6.4 220.1 — — 220.1 Accounts receivable and unbilled revenues, net (1) $ 797.7 $ 282.3 $ 73.4 $ 1,153.4 $ 45.0 $ 4.4 $ 1,202.8 Total accounts receivable, net – past due greater than 90 days (1) $ 84.8 $ 34.5 $ 3.5 $ 122.8 $ — $ — $ 122.8 Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1) 97.6 % 100.0 % — % 95.5 % — % — % 95.5 % (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 March 31, 2021, $742.0 million, or 54.2%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses. In addition, we have received specific orders related to the deferral of certain costs (including credit losses) incurred as a result of the COVID-19 pandemic. The additional protections related to our accounts receivable and unbilled revenue balances provided by these orders are subject to prudency reviews and are still being assessed. They are not reflected in the percentages in the above table or this note. See Note 22, Regulatory Environment, for more information on these orders. |
Rollforward of the allowances for credit losses by reportable segment | A rollforward of the allowance for credit losses by reportable segment for the three months ended March 31, 2021 and 2020 is included below: (in millions) Wisconsin Illinois Other States Total Utility Corporate WEC Energy Group Consolidated Balance at December 31, 2020 $ 102.1 $ 111.6 $ 6.4 $ 220.1 $ — $ 220.1 Provision for credit losses 13.7 7.1 1.3 22.1 — 22.1 Provision for credit losses deferred for future recovery or refund 22.3 3.1 — 25.4 — 25.4 Write-offs charged against the allowance (18.5) (2.8) (0.5) (21.8) — (21.8) Recoveries of amounts previously written off 9.9 3.0 0.4 13.3 — 13.3 Balance at March 31, 2021 $ 129.5 $ 122.0 $ 7.6 $ 259.1 $ — $ 259.1 The increase in the allowance for credit losses at March 31, 2021, compared to December 31, 2020, was 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 the continued economic disruptions caused by the COVID-19 pandemic, including continued high unemployment rates. Also, as a result of the winter moratorium rules, which are discussed in more detail below, and the COVID-19 pandemic and related regulatory orders we have received, we have been unable to disconnect any of our Wisconsin and Illinois residential customers since the fourth quarter of 2019. See Note 22, Regulatory Environment, for more information. (in millions) Wisconsin Illinois Other States Total Utility Corporate WEC Energy Group Consolidated Balance at December 31, 2019 $ 59.9 $ 75.9 $ 4.1 $ 139.9 $ 0.1 $ 140.0 Provision for credit losses 13.7 14.4 0.7 28.8 — 28.8 Provision for credit losses deferred for future recovery or refund 3.3 29.5 — 32.8 — 32.8 Write-offs charged against the allowance (19.7) (31.6) (1.3) (52.6) — (52.6) Recoveries of amounts previously written off 10.5 4.9 0.4 15.8 — 15.8 Balance at March 31, 2020 $ 67.7 $ 93.1 $ 3.9 $ 164.7 $ 0.1 $ 164.8 |
REGULATORY ASSETS AND LIABILI_2
REGULATORY ASSETS AND LIABILITIES (Tables) | 3 Months Ended |
Mar. 31, 2021 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Schedule of regulatory assets | (in millions) March 31, 2021 December 31, 2020 Regulatory assets Pension and OPEB costs $ 1,073.9 $ 1,101.6 Plant retirements 733.1 740.8 Environmental remediation costs 623.1 638.2 Income tax related items 459.3 454.6 Energy costs recoverable through rate adjustments (1) 301.6 1.1 Asset retirement obligations 186.0 181.3 SSR 134.6 135.6 Securitization 106.9 105.2 Uncollectible expense 73.0 82.0 Derivatives 9.6 26.5 Other, net 92.7 77.2 Total regulatory assets $ 3,793.8 $ 3,544.1 Balance sheet presentation Amounts recoverable from customers (1) $ 306.7 $ 20.0 Regulatory assets 3,487.1 3,524.1 Total regulatory assets $ 3,793.8 $ 3,544.1 (1) The increase in these regulatory assets primarily relates to the high natural gas costs that were incurred as a result of the extreme winter weather conditions in February 2021. See Note 22, Regulatory Environment, for more information. |
Schedule of regulatory liabilities | (in millions) March 31, 2021 December 31, 2020 Regulatory liabilities Income tax related items $ 2,111.0 $ 2,137.7 Removal costs 1,234.6 1,221.1 Pension and OPEB benefits 373.1 378.1 Electric transmission costs 75.9 78.5 Earnings sharing mechanisms 30.8 36.9 Energy costs refundable through rate adjustments 24.7 59.9 Derivatives 17.4 16.4 Energy efficiency programs 11.0 9.9 Uncollectible expense 3.2 25.5 Other, net 21.6 15.1 Total regulatory liabilities $ 3,903.3 $ 3,979.1 Balance sheet presentation Other current liabilities $ 12.5 $ 51.0 Regulatory liabilities 3,890.8 3,928.1 Total regulatory liabilities $ 3,903.3 $ 3,979.1 |
COMMON EQUITY (Tables)
COMMON EQUITY (Tables) | 3 Months Ended |
Mar. 31, 2021 | |
Equity [Abstract] | |
Schedule of stock-based compensation awards granted | During the three months ended March 31, 2021, the Compensation Committee of our Board of Directors awarded the following stock-based compensation awards to our directors, officers, and certain other key employees: Award Type Number of Awards Stock options (1) 530,612 Restricted shares (2) 69,681 Performance units 152,382 (1) Stock options awarded had a weighted-average exercise price of $91.06 and a weighted-average grant date fair value of $13.20 per option. (2) Restricted shares awarded had a weighted-average grant date fair value of $91.06 per share. |
SHORT-TERM DEBT AND LINES OF _2
SHORT-TERM DEBT AND LINES OF CREDIT (Tables) | 3 Months Ended |
Mar. 31, 2021 | |
Short-term Debt [Abstract] | |
Schedule of short-term borrowings and weighted-average interest rates | The following table shows our short-term borrowings and their corresponding weighted-average interest rates: (in millions, except percentages) March 31, 2021 December 31, 2020 Commercial paper Amount outstanding $ 1,580.4 $ 1,436.9 Weighted-average interest rate on amounts outstanding 0.19 % 0.21 % Term loan Amount outstanding $ — $ 340.0 Weighted-average interest rate on amounts outstanding n/a 0.99 % |
Schedule of credit agreements and remaining available capacity | 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: (in millions) Maturity March 31, 2021 WEC Energy Group October 2022 1,200.0 WE October 2022 500.0 WPS October 2022 400.0 WG October 2022 350.0 PGL October 2022 350.0 Total short-term credit capacity $ 2,800.0 Less: Letters of credit issued inside credit facilities $ 2.3 Commercial paper outstanding 1,580.4 Available capacity under existing agreements $ 1,217.3 |
MATERIALS, SUPPLIES, AND INVE_2
MATERIALS, SUPPLIES, AND INVENTORIES (Tables) | 3 Months Ended |
Mar. 31, 2021 | |
Inventory Disclosure [Abstract] | |
Schedule of inventory | Our inventory consisted of: (in millions) March 31, 2021 December 31, 2020 Materials and supplies $ 218.3 $ 218.1 Natural gas in storage 68.3 224.9 Fossil fuel 66.9 85.6 Total $ 353.5 $ 528.6 |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 3 Months Ended |
Mar. 31, 2021 | |
Income Tax Disclosure [Abstract] | |
Schedule of effective income tax rate reconciliation | The provision for income taxes differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes as a result of the following: Three Months Ended March 31, 2021 Three Months Ended March 31, 2020 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Statutory federal income tax $ 122.8 21.0 % $ 113.9 21.0 % State income taxes net of federal tax benefit 36.9 6.3 % 34.0 6.3 % PTCs (34.0) (5.8) % (18.4) (3.4) % Federal excess deferred tax amortization – Wisconsin unprotected (30.3) (5.2) % (22.1) (4.1) % Federal excess deferred tax amortization (14.6) (2.5) % (13.0) (2.4) % Uncertain tax positions (8.2) (1.4) % — — % Other 2.3 0.4 % (4.4) (0.8) % Total income tax expense $ 74.9 12.8 % $ 90.0 16.6 % |
FAIR VALUE MEASUREMENTS (Tables
FAIR VALUE MEASUREMENTS (Tables) | 3 Months Ended |
Mar. 31, 2021 | |
Fair Value Disclosures [Abstract] | |
Schedule of fair value of assets and liabilities measured on a recurring basis categorized by level within the fair value hierarchy | The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy: March 31, 2021 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 12.3 $ 1.6 $ — $ 13.9 FTRs — — 0.9 0.9 Coal contracts — 2.6 — 2.6 Total derivative assets $ 12.3 $ 4.2 $ 0.9 $ 17.4 Investments held in rabbi trust $ 71.6 $ — $ — $ 71.6 Derivative liabilities Natural gas contracts $ 3.1 $ 1.0 $ — $ 4.1 Coal contracts — 0.3 — 0.3 Interest rate swaps — 5.1 — 5.1 Total derivative liabilities $ 3.1 $ 6.4 $ — $ 9.5 December 31, 2020 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 11.7 $ 2.0 $ — $ 13.7 FTRs — — 2.4 2.4 Coal contracts — 1.8 — 1.8 Total derivative assets $ 11.7 $ 3.8 $ 2.4 $ 17.9 Investments held in rabbi trust $ 79.6 $ — $ — $ 79.6 Derivative liabilities Natural gas contracts $ 7.7 $ 6.4 $ — $ 14.1 Coal contracts — 1.2 — 1.2 Interest rate swaps — 6.8 — 6.8 Total derivative liabilities $ 7.7 $ 14.4 $ — $ 22.1 |
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: Three Months Ended March 31 (in millions) 2021 2020 Balance at the beginning of the period $ 2.4 $ 3.1 Purchases 0.1 — Settlements (1.6) (2.2) Balance at the end of the period $ 0.9 $ 0.9 |
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 were not recorded at fair value: March 31, 2021 December 31, 2020 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock of subsidiary $ 30.4 $ 29.9 $ 30.4 $ 32.3 Long-term debt, including current portion (1) 13,041.8 14,139.0 12,450.5 14,343.2 (1) The carrying amount of long-term debt excludes finance lease obligations of $62.9 million and $63.4 million at March 31, 2021 and December 31, 2020, respectively. |
DERIVATIVE INSTRUMENTS (Tables)
DERIVATIVE INSTRUMENTS (Tables) | 3 Months Ended |
Mar. 31, 2021 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of derivative assets and liabilities | The following table shows our derivative assets and derivative liabilities, along with their classification on our balance sheets. March 31, 2021 December 31, 2020 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Other current Natural gas contracts $ 13.4 $ 3.6 $ 13.0 $ 12.9 FTRs 0.9 — 2.4 — Coal contracts 2.4 0.1 1.6 0.8 Interest rate swaps — 5.1 — 6.8 Total other current (1) 16.7 8.8 17.0 20.5 Other long-term Natural gas contracts 0.5 0.5 0.7 1.2 Coal contracts 0.2 0.2 0.2 0.4 Total other long-term (1) 0.7 0.7 0.9 1.6 Total $ 17.4 $ 9.5 $ 17.9 $ 22.1 (1) On our balance sheets, we classify derivative assets and liabilities as other current or other long-term based on the maturities of the underlying contracts. |
Schedule of estimated notional sales volumes and realized gains (losses) | Our estimated notional sales volumes and realized gains (losses) were as follows: Three Months Ended March 31, 2021 Three Months Ended March 31, 2020 (in millions) Volumes Gains (Losses) Volumes Gains (Losses) Natural gas contracts 59.8 Dth $ (7.5) 58.4 Dth $ (24.7) FTRs 8.4 MWh 2.1 7.2 MWh 1.4 Total $ (5.4) $ (23.3) |
Schedule of net derivative instruments | The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets: March 31, 2021 December 31, 2020 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 17.4 $ 9.5 $ 17.9 $ 22.1 Gross amount not offset on the balance sheet (3.1) (3.1) (6.9) (7.7) (1) Net amount $ 14.3 $ 6.4 $ 11.0 $ 14.4 (1) Includes cash collateral posted of $0.8 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: Three Months Ended March 31 (in millions) 2021 2020 Derivative loss recognized in other comprehensive loss $ — $ (4.7) Net derivative loss reclassified from accumulated other comprehensive loss to interest expense (1.4) (0.1) Total interest expense line item on the income statements 119.5 129.4 |
GUARANTEES (Tables)
GUARANTEES (Tables) | 3 Months Ended |
Mar. 31, 2021 | |
Guarantees [Abstract] | |
Schedule of outstanding guarantees | The following table shows our outstanding guarantees: Expiration (in millions) Total Amounts Committed at March 31, 2021 Less Than 1 Year 1 to 3 Years Over 3 Years Guarantees supporting transactions of subsidiaries (1) $ 138.5 $ 53.5 $ 1.5 $ 83.5 Standby letters of credit (2) 73.3 5.1 — 68.2 Surety bonds (3) 12.4 12.3 0.1 — Other guarantees (4) 10.0 — — 10.0 Total guarantees $ 234.2 $ 70.9 $ 1.6 $ 161.7 (1) Consists of $4.2 million, $8.2 million, and $126.1 million to support the business operations of UMERC, Bluewater, and WECI, respectively. (2) 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. (3) Primarily for workers compensation self-insurance programs and obtaining various licenses, permits, and rights-of-way. These amounts are not reflected on our balance sheets. (4) Consists of $10.0 million related to workers compensation coverage for which a liability was recorded on our balance sheets. |
EMPLOYEE BENEFITS (Tables)
EMPLOYEE BENEFITS (Tables) | 3 Months Ended |
Mar. 31, 2021 | |
Retirement Benefits [Abstract] | |
Schedule of net benefit cost (credit) | The following tables show the components of net periodic benefit cost (credit) for our benefit plans. Pension Benefits Three Months Ended March 31 (in millions) 2021 2020 Service cost $ 13.9 $ 13.1 Interest cost 21.9 26.1 Expected return on plan assets (50.6) (47.9) Loss on plan settlement 0.1 0.3 Amortization of prior service cost 0.4 0.4 Amortization of net actuarial loss 27.4 24.2 Net periodic benefit cost $ 13.1 $ 16.2 OPEB Benefits Three Months Ended March 31 (in millions) 2021 2020 Service cost $ 4.2 $ 4.1 Interest cost 3.6 4.7 Expected return on plan assets (16.4) (15.1) Amortization of prior service credit (4.0) (3.7) Amortization of net actuarial gain (5.7) (5.4) Net periodic benefit credit $ (18.3) $ (15.4) |
GOODWILL AND INTANGIBLES (Table
GOODWILL AND INTANGIBLES (Tables) | 3 Months Ended |
Mar. 31, 2021 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Schedule of changes to our goodwill balances by segment | The table below shows our goodwill balances by segment at March 31, 2021. We had no changes to the carrying amount of goodwill during the three months ended March 31, 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 March 31, 2021. |
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. See Note 2, Acquisitions, for more information. March 31, 2021 December 31, 2020 (in millions) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Gross Carrying Amount Accumulated Amortization Net Carrying Amount PPAs (1) $ 84.6 $ (1.6) $ 83.0 $ 76.1 $ — $ 76.1 Proxy revenue swap (2) 7.2 (1.5) 5.7 7.2 (1.3) 5.9 Interconnection agreements (3) 5.1 (0.4) 4.7 5.1 (0.3) 4.8 Total intangible liabilities $ 96.9 $ (3.5) $ 93.4 $ 88.4 $ (1.6) $ 86.8 (1) Represents PPAs related to the acquisition of Blooming Grove, Tatanka Ridge, and Jayhawk expiring between 2030 and 2032. The weighted-average remaining useful life of the PPAs is approximately 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 approximately eight 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 approximately 20 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) 2022 2023 2024 2025 2026 Amortization to be recorded in operating revenues $ 8.1 $ 8.1 $ 8.1 $ 8.1 $ 8.1 Amortization to be recorded in other operation and maintenance 0.2 0.2 0.2 0.2 0.2 |
INVESTMENT IN TRANSMISSION AF_2
INVESTMENT IN TRANSMISSION AFFILIATES (Tables) | 3 Months Ended |
Mar. 31, 2021 | |
Investment in transmission affiliates | |
Schedule of changes to our investments in transmission affiliates | The following tables provide a reconciliation of the changes in our investments in ATC and ATC Holdco: Three Months Ended March 31, 2021 (in millions) ATC ATC Holdco Total Balance at beginning of period $ 1,733.5 $ 30.8 $ 1,764.3 Add: Earnings from equity method investment 41.7 0.9 42.6 Less: Distributions 33.4 — 33.4 Add: Other 0.1 — 0.1 Balance at end of period $ 1,741.9 $ 31.7 $ 1,773.6 Three Months Ended March 31, 2020 (in millions) ATC ATC Holdco Total Balance at beginning of period $ 1,684.7 $ 36.1 $ 1,720.8 Add: Earnings from equity method investment 39.6 0.2 39.8 Add: Capital contributions 3.0 — 3.0 Less: Distributions 40.6 — 40.6 Less: Return of capital — 5.3 5.3 Balance at end of period $ 1,686.7 $ 31.0 $ 1,717.7 |
ATC | |
Investment in transmission affiliates | |
Schedule of significant related party transactions with ATC | The following table summarizes our significant related party transactions with ATC: Three Months Ended March 31 (in millions) 2021 2020 Charges to ATC for services and construction $ 6.0 $ 6.0 Charges from ATC for network transmission services 92.6 86.9 |
Schedule of receivables and payables with ATC | Our balance sheets included the following receivables and payables for services provided to or received from ATC: (in millions) March 31, 2021 December 31, 2020 Accounts receivable for services provided to ATC $ 2.4 $ 3.7 Accounts payable for services received from ATC 30.3 29.3 Amounts due from ATC for transmission infrastructure upgrades (1) 5.3 4.6 |
Schedule of summarized income statement data for ATC | Summarized financial data for ATC is included in the tables below: Three Months Ended March 31 (in millions) 2021 2020 Income statement data Operating revenues $ 188.7 $ 186.8 Operating expenses 95.1 95.2 Other expense, net 28.5 28.5 Net income $ 65.1 $ 63.1 |
Schedule of summarized balance sheet data for ATC | (in millions) March 31, 2021 December 31, 2020 Balance sheet data Current assets $ 90.0 $ 92.7 Noncurrent assets 5,431.8 5,400.6 Total assets $ 5,521.8 $ 5,493.3 Current liabilities $ 420.1 $ 310.8 Long-term debt 2,412.5 2,512.2 Other noncurrent liabilities 385.0 378.2 Members' equity 2,304.2 2,292.1 Total liabilities and members' equity $ 5,521.8 $ 5,493.3 |
SEGMENT INFORMATION (Tables)
SEGMENT INFORMATION (Tables) | 3 Months Ended |
Mar. 31, 2021 | |
Segment Reporting [Abstract] | |
Financial information of reportable segments | The following tables show summarized financial information related to our reportable segments for the three months ended March 31, 2021 and 2020: Utility Operations (in millions) Wisconsin Illinois Other States Total Utility Operations Electric Transmission Non-Utility Energy Infrastructure Corporate and Other Reconciling Eliminations WEC Energy Group Consolidated Three Months Ended March 31, 2021 External revenues $ 1,731.7 $ 703.4 $ 233.3 $ 2,668.4 $ — $ 22.9 $ 0.1 $ — $ 2,691.4 Intersegment revenues — — — — — 114.7 — (114.7) — Other operation and maintenance 341.9 109.3 23.2 474.4 — 8.9 (1.8) (1.6) 479.9 Depreciation and amortization 176.2 52.7 9.2 238.1 — 31.0 6.6 (14.3) 261.4 Equity in earnings of transmission affiliates — — — — 42.6 — — — 42.6 Interest expense 140.1 16.5 1.5 158.1 4.9 18.0 24.2 (85.7) 119.5 Income tax expense (benefit) 48.1 41.4 8.4 97.9 9.8 0.1 (32.9) — 74.9 Net income 256.6 112.1 24.7 393.4 28.0 71.3 17.6 — 510.3 Net income attributed to common shareholders 256.3 112.1 24.7 393.1 28.0 71.4 17.6 — 510.1 Utility Operations (in millions) Wisconsin Illinois Other States Total Utility Operations Electric Transmission Non-Utility Energy Infrastructure Corporate and Other Reconciling Eliminations WEC Energy Group Consolidated Three Months Ended March 31, 2020 External revenues $ 1,498.9 $ 447.6 $ 146.4 $ 2,092.9 $ — $ 15.2 $ 0.5 $ — $ 2,108.6 Intersegment revenues — — — — — 114.4 — (114.4) — Other operation and maintenance 330.8 104.1 21.7 456.6 — 5.2 (1.6) (4.5) 455.7 Depreciation and amortization 165.4 47.5 7.8 220.7 — 24.5 6.1 (12.2) 239.1 Equity in earnings of transmission affiliates — — — — 39.8 — — — 39.8 Interest expense 143.1 16.0 2.2 161.3 4.8 15.3 35.1 (87.1) 129.4 Income tax expense (benefit) 51.2 39.5 8.9 99.6 9.9 11.2 (30.7) — 90.0 Net income (loss) 247.0 107.3 26.3 380.6 25.0 65.3 (18.3) — 452.6 Net income (loss) attributed to common shareholders 246.7 107.3 26.3 380.3 25.0 65.5 (18.3) — 452.5 |
COMMITMENTS AND CONTINGENCIES (
COMMITMENTS AND CONTINGENCIES (Tables) | 3 Months Ended |
Mar. 31, 2021 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of regulatory assets and reserves related to manufactured gas plant sites | We have established the following regulatory assets and reserves for manufactured gas plant sites: (in millions) March 31, 2021 December 31, 2020 Regulatory assets $ 623.1 $ 638.2 Reserves for future environmental remediation 532.9 532.9 |
SUPPLEMENTAL CASH FLOW INFORM_2
SUPPLEMENTAL CASH FLOW INFORMATION (Tables) | 3 Months Ended |
Mar. 31, 2021 | |
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract] | |
Schedule of supplemental cash flow information | Three Months Ended March 31 (in millions) 2021 2020 Cash paid for interest, net of amount capitalized $ 76.8 $ 85.8 Cash received for income taxes, net (2.5) (11.2) Significant non-cash investing and financing transactions: Accounts payable related to construction costs 97.8 102.5 Receivable related to insurance proceeds for property damage (1) 2.7 — (1) See Note 6, Property, Plant, and Equipment, for information about a steam incident at WE's Public Service Building. |
Reconciliation of cash and cash equivalents and restricted cash | The following table reconciles the cash, cash equivalents, and restricted cash amounts reported within the balance sheets to the total of these amounts shown on the statements of cash flows: (in millions) March 31, 2021 December 31, 2020 Cash and cash equivalents $ 26.1 $ 24.8 Restricted cash included in other current assets 10.6 — Restricted cash included in other long term assets 52.9 47.8 Cash, cash equivalents, and restricted cash $ 89.6 $ 72.6 |
REGULATORY ENVIRONMENT (Tables)
REGULATORY ENVIRONMENT (Tables) | 3 Months Ended |
Mar. 31, 2021 | |
Regulated Operations [Abstract] | |
Schedule of decisions in regulatory proceedings | The final orders reflect 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 reflect 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 will be amortized in each of 2020 and 2021. For WPS, approximately $11 million of tax benefits were amortized in 2020 and approximately $39 million are being 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 is net of $21 million of refunds related to its 2018 earnings sharing mechanism. These refunds are being made to customers evenly over two years, with half returned in 2020 and the remainder being 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 reflect all of the unprotected deferred tax expense and benefits from the Tax Legislation being amortized evenly over four years. For WE, approximately |
GENERAL INFORMATION - GENERAL (
GENERAL INFORMATION - GENERAL (Details) customer in Millions | Mar. 31, 2021customer |
Electric | |
Product information [Line Items] | |
Number Of Customers | 1.6 |
Natural gas | |
Product information [Line Items] | |
Number Of Customers | 3 |
GENERAL INFORMATION - INVESTMEN
GENERAL INFORMATION - INVESTMENTS (Details) | Mar. 31, 2021 |
ATC | |
Schedule of Investments [Line Items] | |
Equity method investment, ownership interest (as a percent) | 60.00% |
ACQUISITIONS - JAYHAWK (Details
ACQUISITIONS - JAYHAWK (Details) - Jayhawk - WECI $ in Millions | 1 Months Ended | |
Mar. 31, 2021USD ($) | Feb. 26, 2021USD ($)MW | |
Business Acquisition [Line Items] | ||
Ownership interest of wind generating facility acquired | 90.00% | |
Capacity of generation unit | MW | 190 | |
Acquisition purchase price | $ 119.4 | |
Additional capital expenditures | $ 37.9 | |
Current project investment | 157.3 | |
Total expected investment | $ 302 | |
Duration of offtake agreement for the sale of energy produced | 10 years | |
Percentage of tax benefits entitled to | 99.00% | |
Duration of receiving tax benefits | 10 years |
ACQUISITIONS - TATANKA RIDGE (D
ACQUISITIONS - TATANKA RIDGE (Details) - Tatanka Ridge - WECI $ in Millions | 1 Months Ended |
Dec. 31, 2020USD ($)MW | |
Business Acquisition [Line Items] | |
Ownership interest of wind generating facility acquired | 85.00% |
Capacity of generation unit | MW | 155 |
Acquisition purchase price | $ | $ 240.1 |
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 |
Percentage of tax benefits entitled to | 99.00% |
Duration of receiving tax benefits | 11 years |
ACQUISITIONS - THUNDERHEAD (Det
ACQUISITIONS - THUNDERHEAD (Details) - Thunderhead - WECI $ in Millions | 1 Months Ended | |
Aug. 31, 2019USD ($)MW | Feb. 19, 2020USD ($) | |
Business Acquisition [Line Items] | ||
Ownership interest of wind generating facility acquired | 80.00% | |
Capacity of generation unit | MW | 300 | |
Acquisition purchase price | $ | $ 338 | $ 43 |
Additional ownership interest acquired | 10.00% | |
Duration of offtake agreement for the sale of energy produced | 12 years |
OPERATING REVENUES - DISAGGREGA
OPERATING REVENUES - DISAGGREGATION OF OPERATING REVENUES BY SEGMENT (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2021 | Mar. 31, 2020 | |
Disaggregation of Operating Revenues | ||
Total operating revenues | $ 2,691.4 | $ 2,108.6 |
Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 2,669 | 2,086.9 |
Other operating revenues | ||
Disaggregation of Operating Revenues | ||
Other operating revenues | 22.4 | 21.7 |
Total regulated revenues | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 2,642.7 | 2,067.3 |
Electric | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 1,095 | 1,034.6 |
Natural gas | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 1,547.7 | 1,032.7 |
Other non-utility revenues | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 26.3 | 19.6 |
Reconciling Eliminations | ||
Disaggregation of Operating Revenues | ||
Total operating revenues | (114.7) | (114.4) |
Reconciling Eliminations | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | (14.9) | (15.7) |
Reconciling Eliminations | Other operating revenues | ||
Disaggregation of Operating Revenues | ||
Other operating revenues | (99.8) | (98.7) |
Reconciling Eliminations | Total regulated revenues | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | (13.3) | (14.1) |
Reconciling Eliminations | Electric | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 0 | 0 |
Reconciling Eliminations | Natural gas | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | (13.3) | (14.1) |
Reconciling Eliminations | Other non-utility revenues | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | (1.6) | (1.6) |
Total Utility Operations | ||
Disaggregation of Operating Revenues | ||
Total operating revenues | 2,668.4 | 2,092.9 |
Total Utility Operations | Other operating revenues | ||
Disaggregation of Operating Revenues | ||
Other operating revenues | 22.3 | 21.6 |
Total Utility Operations | Transferred over time | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 2,646.1 | 2,071.3 |
Total Utility Operations | Total regulated revenues | Transferred over time | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 2,641.4 | 2,066.9 |
Total Utility Operations | Electric | Transferred over time | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 1,095 | 1,034.6 |
Total Utility Operations | Natural gas | Transferred over time | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 1,546.4 | 1,032.3 |
Total Utility Operations | Other non-utility revenues | Transferred over time | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 4.7 | 4.4 |
Wisconsin | ||
Disaggregation of Operating Revenues | ||
Total operating revenues | 1,731.7 | 1,498.9 |
Wisconsin | Other operating revenues | ||
Disaggregation of Operating Revenues | ||
Other operating revenues | 9.4 | 5.4 |
Wisconsin | Transferred over time | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 1,722.3 | 1,493.5 |
Wisconsin | Total regulated revenues | Transferred over time | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 1,722.3 | 1,493.5 |
Wisconsin | Electric | Transferred over time | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 1,095 | 1,034.6 |
Wisconsin | Natural gas | Transferred over time | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 627.3 | 458.9 |
Wisconsin | Other non-utility revenues | Transferred over time | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 0 | 0 |
Illinois | ||
Disaggregation of Operating Revenues | ||
Total operating revenues | 703.4 | 447.6 |
Illinois | Other operating revenues | ||
Disaggregation of Operating Revenues | ||
Other operating revenues | 9.9 | 14 |
Illinois | Transferred over time | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 693.5 | 433.6 |
Illinois | Total regulated revenues | Transferred over time | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 693.5 | 433.6 |
Illinois | Electric | Transferred over time | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 0 | 0 |
Illinois | Natural gas | Transferred over time | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 693.5 | 433.6 |
Illinois | Other non-utility revenues | Transferred over time | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 0 | 0 |
Other States | ||
Disaggregation of Operating Revenues | ||
Total operating revenues | 233.3 | 146.4 |
Other States | Other operating revenues | ||
Disaggregation of Operating Revenues | ||
Other operating revenues | 3 | 2.2 |
Other States | Transferred over time | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 230.3 | 144.2 |
Other States | Total regulated revenues | Transferred over time | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 225.6 | 139.8 |
Other States | Electric | Transferred over time | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 0 | 0 |
Other States | Natural gas | Transferred over time | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 225.6 | 139.8 |
Other States | Other non-utility revenues | Transferred over time | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 4.7 | 4.4 |
Non-Utility Energy Infrastructure | ||
Disaggregation of Operating Revenues | ||
Total operating revenues | 137.6 | 129.6 |
Non-Utility Energy Infrastructure | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 37.8 | 30.9 |
Non-Utility Energy Infrastructure | Other operating revenues | ||
Disaggregation of Operating Revenues | ||
Other operating revenues | 99.8 | 98.7 |
Non-Utility Energy Infrastructure | Total regulated revenues | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 14.6 | 14.5 |
Non-Utility Energy Infrastructure | Electric | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 0 | 0 |
Non-Utility Energy Infrastructure | Natural gas | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 14.6 | 14.5 |
Non-Utility Energy Infrastructure | Other non-utility revenues | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 23.2 | 16.4 |
Corporate and Other | ||
Disaggregation of Operating Revenues | ||
Total operating revenues | 0.1 | 0.5 |
Corporate and Other | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 0 | 0.4 |
Corporate and Other | Other operating revenues | ||
Disaggregation of Operating Revenues | ||
Other operating revenues | 0.1 | 0.1 |
Corporate and Other | Total regulated revenues | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 0 | 0 |
Corporate and Other | Electric | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 0 | 0 |
Corporate and Other | Natural gas | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 0 | 0 |
Corporate and Other | Other non-utility revenues | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | $ 0 | $ 0.4 |
OPERATING REVENUES - DISAGGRE_2
OPERATING REVENUES - DISAGGREGATION OF ELECTRIC UTILITY OPERATING REVENUES BY CUSTOMER CLASS (Details) - Revenues from contracts with customers - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2021 | Mar. 31, 2020 | |
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | $ 2,669 | $ 2,086.9 |
Electric | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 1,095 | 1,034.6 |
Wisconsin | Transferred over time | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 1,722.3 | 1,493.5 |
Wisconsin | Electric | Transferred over time | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 1,095 | 1,034.6 |
Wisconsin | Electric | Transferred over time | Total retail revenues | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 972.4 | 930.4 |
Wisconsin | Electric | Transferred over time | Residential | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 423.7 | 404.9 |
Wisconsin | Electric | Transferred over time | Small commercial and industrial | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 331.4 | 323.6 |
Wisconsin | Electric | Transferred over time | Large commercial and industrial | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 209.5 | 194.6 |
Wisconsin | Electric | Transferred over time | Other | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 7.8 | 7.3 |
Wisconsin | Electric | Transferred over time | Wholesale | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 39.7 | 42.1 |
Wisconsin | Electric | Transferred over time | Resale | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 62.7 | 45.2 |
Wisconsin | Electric | Transferred over time | Steam | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 14.8 | 8.4 |
Wisconsin | Electric | Transferred over time | Other utility revenues | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | $ 5.4 | $ 8.5 |
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 | 3 Months Ended | |
Mar. 31, 2021 | Mar. 31, 2020 | |
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | $ 2,669 | $ 2,086.9 |
Natural gas | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 1,547.7 | 1,032.7 |
Total Utility Operations | Transferred over time | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 2,646.1 | 2,071.3 |
Total Utility Operations | Natural gas | Transferred over time | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 1,546.4 | 1,032.3 |
Total Utility Operations | Natural gas | Transferred over time | Total retail revenues | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 1,092.4 | 985.7 |
Total Utility Operations | Natural gas | Transferred over time | Residential | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 769.4 | 691.3 |
Total Utility Operations | Natural gas | Transferred over time | Commercial and industrial | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 323 | 294.4 |
Total Utility Operations | Natural gas | Transferred over time | Transportation | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 109.6 | 107.3 |
Total Utility Operations | Natural gas | Transferred over time | Other utility revenues | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 344.4 | (60.7) |
Wisconsin | Transferred over time | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 1,722.3 | 1,493.5 |
Wisconsin | Natural gas | Transferred over time | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 627.3 | 458.9 |
Wisconsin | Natural gas | Transferred over time | Total retail revenues | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 524 | 464.4 |
Wisconsin | Natural gas | Transferred over time | Residential | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 347.6 | 313.1 |
Wisconsin | Natural gas | Transferred over time | Commercial and industrial | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 176.4 | 151.3 |
Wisconsin | Natural gas | Transferred over time | Transportation | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 24.4 | 24.1 |
Wisconsin | Natural gas | Transferred over time | Other utility revenues | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 78.9 | (29.6) |
Illinois | Transferred over time | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 693.5 | 433.6 |
Illinois | Natural gas | Transferred over time | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 693.5 | 433.6 |
Illinois | Natural gas | Transferred over time | Total retail revenues | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 436.6 | 374.3 |
Illinois | Natural gas | Transferred over time | Residential | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 333.9 | 282.9 |
Illinois | Natural gas | Transferred over time | Commercial and industrial | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 102.7 | 91.4 |
Illinois | Natural gas | Transferred over time | Transportation | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 74.2 | 72.7 |
Illinois | Natural gas | Transferred over time | Other utility revenues | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 182.7 | (13.4) |
Other States | Transferred over time | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 230.3 | 144.2 |
Other States | Natural gas | Transferred over time | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 225.6 | 139.8 |
Other States | Natural gas | Transferred over time | Total retail revenues | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 131.8 | 147 |
Other States | Natural gas | Transferred over time | Residential | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 87.9 | 95.3 |
Other States | Natural gas | Transferred over time | Commercial and industrial | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 43.9 | 51.7 |
Other States | Natural gas | Transferred over time | Transportation | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 11 | 10.5 |
Other States | Natural gas | Transferred over time | Other utility revenues | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | $ 82.8 | $ (17.7) |
OPERATING REVENUES - OTHER NON-
OPERATING REVENUES - OTHER NON-UTILITY OPERATING REVENUES (Details) - Revenues from contracts with customers - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2021 | Mar. 31, 2020 | |
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | $ 2,669 | $ 2,086.9 |
We Power revenues | ||
Disaggregation of Operating Revenues | ||
Revenues amortized from deferred revenue during the period | 5.8 | 5.5 |
Other non-utility revenues | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 26.3 | 19.6 |
Other non-utility revenues | We Power revenues | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 5.8 | 5.5 |
Other non-utility revenues | Distributed renewable solar project revenues | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 0 | 0.4 |
Transferred over time | Other non-utility revenues | Wind generation revenues | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 15.8 | 9.3 |
Transferred over time | Other non-utility revenues | Appliance service repairs | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | $ 4.7 | $ 4.4 |
OPERATING REVENUES - OTHER OPER
OPERATING REVENUES - OTHER OPERATING REVENUES (Details) - Other operating revenues - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2021 | Mar. 31, 2020 | |
Disaggregation of Operating Revenues | ||
Other operating revenues | $ 22.4 | $ 21.7 |
Late payment charges | ||
Disaggregation of Operating Revenues | ||
Other operating revenues | 15 | 12.1 |
Alternative revenues | ||
Disaggregation of Operating Revenues | ||
Other operating revenues | 6.2 | 8.5 |
Other | ||
Disaggregation of Operating Revenues | ||
Other operating revenues | $ 1.2 | $ 1.1 |
CREDIT LOSSES - GROSS RECEIVABL
CREDIT LOSSES - GROSS RECEIVABLES AND RELATED ALLOWANCES (Details) - USD ($) $ in Millions | Mar. 31, 2021 | Dec. 31, 2020 | Mar. 31, 2020 | Dec. 31, 2019 |
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable and unbilled revenues | $ 1,629 | $ 1,422.9 | ||
Allowance for credit losses | 259.1 | 220.1 | $ 164.8 | $ 140 |
Accounts receivable and unbilled revenues, net | 1,369.9 | 1,202.8 | ||
Total accounts receivable, net - past due greater than 90 days | $ 111 | $ 122.8 | ||
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms | 95.00% | 95.50% | ||
Amount of net accounts receivable with regulatory protections | $ 742 | |||
Percent of net accounts receivable with regulatory protections | 54.20% | |||
Utility Operations | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable and unbilled revenues | $ 1,600.2 | $ 1,373.5 | ||
Allowance for credit losses | 259.1 | 220.1 | 164.7 | 139.9 |
Accounts receivable and unbilled revenues, net | 1,341.1 | 1,153.4 | ||
Total accounts receivable, net - past due greater than 90 days | $ 111 | $ 122.8 | ||
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms | 95.00% | 95.50% | ||
Wisconsin | Utility Operations | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable and unbilled revenues | $ 1,056.9 | $ 899.8 | ||
Allowance for credit losses | 129.5 | 102.1 | 67.7 | 59.9 |
Accounts receivable and unbilled revenues, net | 927.4 | 797.7 | ||
Total accounts receivable, net - past due greater than 90 days | $ 68.8 | $ 84.8 | ||
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms | 97.50% | 97.60% | ||
Illinois | Utility Operations | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable and unbilled revenues | $ 465.8 | $ 393.9 | ||
Allowance for credit losses | 122 | 111.6 | 93.1 | 75.9 |
Accounts receivable and unbilled revenues, net | 343.8 | 282.3 | ||
Total accounts receivable, net - past due greater than 90 days | $ 38.4 | $ 34.5 | ||
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms | 100.00% | 100.00% | ||
Other States | Utility Operations | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable and unbilled revenues | $ 77.5 | $ 79.8 | ||
Allowance for credit losses | 7.6 | 6.4 | 3.9 | 4.1 |
Accounts receivable and unbilled revenues, net | 69.9 | 73.4 | ||
Total accounts receivable, net - past due greater than 90 days | $ 3.8 | $ 3.5 | ||
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms | 0.00% | 0.00% | ||
Non-Utility Energy Infrastructure | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable and unbilled revenues | $ 24.9 | $ 45 | ||
Allowance for credit losses | 0 | 0 | ||
Accounts receivable and unbilled revenues, net | 24.9 | 45 | ||
Total accounts receivable, net - past due greater than 90 days | $ 0 | $ 0 | ||
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms | 0.00% | 0.00% | ||
Corporate and Other | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable and unbilled revenues | $ 3.9 | $ 4.4 | ||
Allowance for credit losses | 0 | 0 | $ 0.1 | $ 0.1 |
Accounts receivable and unbilled revenues, net | 3.9 | 4.4 | ||
Total accounts receivable, net - past due greater than 90 days | $ 0 | $ 0 | ||
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms | 0.00% | 0.00% |
CREDIT LOSSES - ROLLFORWARD OF
CREDIT LOSSES - ROLLFORWARD OF ALLOWANCES (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2021 | Mar. 31, 2020 | |
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | ||
Balance at Beginning of Period | $ 220.1 | $ 140 |
Provision for credit losses | 22.1 | 28.8 |
Write-offs charged against the allowance | (21.8) | (52.6) |
Recovery of amounts previously written off | 13.3 | 15.8 |
Balance at End of Period | 259.1 | 164.8 |
Uncollectible expense | ||
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | ||
Provision for credit losses deferred for future recovery or refund | 25.4 | 32.8 |
Utility Operations | ||
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | ||
Balance at Beginning of Period | 220.1 | 139.9 |
Provision for credit losses | 22.1 | 28.8 |
Write-offs charged against the allowance | (21.8) | (52.6) |
Recovery of amounts previously written off | 13.3 | 15.8 |
Balance at End of Period | 259.1 | 164.7 |
Utility Operations | Uncollectible expense | ||
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | ||
Provision for credit losses deferred for future recovery or refund | 25.4 | 32.8 |
Wisconsin | Utility Operations | ||
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | ||
Balance at Beginning of Period | 102.1 | 59.9 |
Provision for credit losses | 13.7 | 13.7 |
Write-offs charged against the allowance | (18.5) | (19.7) |
Recovery of amounts previously written off | 9.9 | 10.5 |
Balance at End of Period | 129.5 | 67.7 |
Wisconsin | Utility Operations | Uncollectible expense | ||
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | ||
Provision for credit losses deferred for future recovery or refund | 22.3 | 3.3 |
Illinois | Utility Operations | ||
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | ||
Balance at Beginning of Period | 111.6 | 75.9 |
Provision for credit losses | 7.1 | 14.4 |
Write-offs charged against the allowance | (2.8) | (31.6) |
Recovery of amounts previously written off | 3 | 4.9 |
Balance at End of Period | 122 | 93.1 |
Illinois | Utility Operations | Uncollectible expense | ||
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | ||
Provision for credit losses deferred for future recovery or refund | 3.1 | 29.5 |
Other States | Utility Operations | ||
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | ||
Balance at Beginning of Period | 6.4 | 4.1 |
Provision for credit losses | 1.3 | 0.7 |
Write-offs charged against the allowance | (0.5) | (1.3) |
Recovery of amounts previously written off | 0.4 | 0.4 |
Balance at End of Period | 7.6 | 3.9 |
Other States | Utility Operations | Uncollectible expense | ||
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | ||
Provision for credit losses deferred for future recovery or refund | 0 | 0 |
Corporate and Other | ||
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | ||
Balance at Beginning of Period | 0 | 0.1 |
Provision for credit losses | 0 | 0 |
Write-offs charged against the allowance | 0 | 0 |
Recovery of amounts previously written off | 0 | 0 |
Balance at End of Period | 0 | 0.1 |
Corporate and Other | Uncollectible expense | ||
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | ||
Provision for credit losses deferred for future recovery or refund | $ 0 | $ 0 |
REGULATORY ASSETS AND LIABILI_3
REGULATORY ASSETS AND LIABILITIES - REGULATORY ASSETS (Details) - USD ($) $ in Millions | Mar. 31, 2021 | Dec. 31, 2020 |
Regulatory assets | ||
Amounts recoverable from customers | $ 306.7 | $ 20 |
Regulatory assets | 3,487.1 | 3,524.1 |
Total regulatory assets | 3,793.8 | 3,544.1 |
Pension and OPEB costs | ||
Regulatory assets | ||
Total regulatory assets | 1,073.9 | 1,101.6 |
Plant retirements | ||
Regulatory assets | ||
Total regulatory assets | 733.1 | 740.8 |
Environmental remediation costs | ||
Regulatory assets | ||
Total regulatory assets | 623.1 | 638.2 |
Income tax related items | ||
Regulatory assets | ||
Total regulatory assets | 459.3 | 454.6 |
Energy costs recoverable through rate adjustments | ||
Regulatory assets | ||
Total regulatory assets | 301.6 | 1.1 |
Asset retirement obligations | ||
Regulatory assets | ||
Total regulatory assets | 186 | 181.3 |
SSR | ||
Regulatory assets | ||
Total regulatory assets | 134.6 | 135.6 |
Securitization | ||
Regulatory assets | ||
Total regulatory assets | 106.9 | 105.2 |
Uncollectible expense | ||
Regulatory assets | ||
Total regulatory assets | 73 | 82 |
Derivatives | ||
Regulatory assets | ||
Total regulatory assets | 9.6 | 26.5 |
Other, net | ||
Regulatory assets | ||
Total regulatory assets | $ 92.7 | $ 77.2 |
REGULATORY ASSETS AND LIABILI_4
REGULATORY ASSETS AND LIABILITIES - REGULATORY LIABILITIES (Details) - USD ($) $ in Millions | Mar. 31, 2021 | Dec. 31, 2020 |
Regulatory liabilities | ||
Other current liabilities | $ 12.5 | $ 51 |
Regulatory liabilities | 3,890.8 | 3,928.1 |
Total regulatory liabilities | 3,903.3 | 3,979.1 |
Income tax related items | ||
Regulatory liabilities | ||
Total regulatory liabilities | 2,111 | 2,137.7 |
Removal costs | ||
Regulatory liabilities | ||
Total regulatory liabilities | 1,234.6 | 1,221.1 |
Pension and OPEB benefits | ||
Regulatory liabilities | ||
Total regulatory liabilities | 373.1 | 378.1 |
Electric transmission costs | ||
Regulatory liabilities | ||
Total regulatory liabilities | 75.9 | 78.5 |
Earnings sharing mechanisms | ||
Regulatory liabilities | ||
Total regulatory liabilities | 30.8 | 36.9 |
Energy costs refundable through rate adjustments | ||
Regulatory liabilities | ||
Total regulatory liabilities | 24.7 | 59.9 |
Derivatives | ||
Regulatory liabilities | ||
Total regulatory liabilities | 17.4 | 16.4 |
Energy efficiency programs | ||
Regulatory liabilities | ||
Total regulatory liabilities | 11 | 9.9 |
Uncollectible expense | ||
Regulatory liabilities | ||
Total regulatory liabilities | 3.2 | 25.5 |
Other, net | ||
Regulatory liabilities | ||
Total regulatory liabilities | $ 21.6 | $ 15.1 |
PROPERTY, PLANT, AND EQUIPMENT
PROPERTY, PLANT, AND EQUIPMENT (Details) - Public Service Building - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2020 | Mar. 31, 2021 | |
Property, plant, and equipment | ||
Costs incurred for repairs and restorations | $ 49.3 | |
Insurance proceeds received | $ 20 | |
Receivable for future insurance recoveries | $ 16.8 | |
Costs included in other operation and maintenance | $ 12.5 |
COMMON EQUITY - STOCK-BASED COM
COMMON EQUITY - STOCK-BASED COMPENSATION AWARDS GRANTED (Details) | 3 Months Ended |
Mar. 31, 2021$ / sharesshares | |
Stock options | |
Stock-based compensation | |
Stock options granted | shares | 530,612 |
Stock options granted, weighted average exercise price | $ / shares | $ 91.06 |
Stock options granted, weighted-average grant date fair value | $ / shares | $ 13.20 |
Restricted shares | |
Stock-based compensation | |
Awards granted | shares | 69,681 |
Restricted shares granted, weighted-average grant date fair value | $ / shares | $ 91.06 |
Performance units | |
Stock-based compensation | |
Awards granted | shares | 152,382 |
COMMON EQUITY - COMMON STOCK DI
COMMON EQUITY - COMMON STOCK DIVIDENDS (Details) - $ / shares | 3 Months Ended | ||
Jun. 30, 2021 | Mar. 31, 2021 | Mar. 31, 2020 | |
Dividends payable | |||
Common stock dividend declared (in dollars per share) | $ 0.6775 | $ 0.6325 | |
Subsequent event | |||
Dividends payable | |||
Common stock dividend declared (in dollars per share) | $ 0.6775 |
SHORT-TERM DEBT AND LINES OF _3
SHORT-TERM DEBT AND LINES OF CREDIT - SHORT-TERM BORROWINGS (Details) - USD ($) $ in Millions | Mar. 30, 2020 | Mar. 31, 2021 | Mar. 31, 2020 | Dec. 31, 2020 |
Short-term borrowings | ||||
Issuance of term loan | $ 0 | $ 340 | ||
WEC Senior Notes 0.80% due 2024 | WEC Energy Group | ||||
Short-term borrowings | ||||
Debt instrument stated interest rate percentage | 0.80% | |||
Commercial paper | ||||
Short-term borrowings | ||||
Commercial paper outstanding | $ 1,580.4 | $ 1,436.9 | ||
Weighted-average interest rate on amounts outstanding | 0.19% | 0.21% | ||
Average amount outstanding during the period | $ 1,445.3 | |||
Weighted-average interest rate during the period | 0.18% | |||
Term loan | WEC Energy Group | ||||
Short-term borrowings | ||||
Term loan outstanding | $ 0 | $ 340 | ||
Weighted-average interest rate on amounts outstanding | 0.99% | |||
Weighted-average interest rate during the period | 0.99% | |||
Issuance of term loan | $ 340 | |||
Length of term loan | 364 days |
SHORT-TERM DEBT AND LINES OF _4
SHORT-TERM DEBT AND LINES OF CREDIT - REVOLVING CREDIT FACILITIES (Details) - USD ($) $ in Millions | Mar. 31, 2021 | Dec. 31, 2020 |
Revolving credit facilities | ||
Short-term credit capacity | $ 2,800 | |
Available capacity under existing credit facility | 1,217.3 | |
Commercial paper | ||
Revolving credit facilities | ||
Commercial paper outstanding | 1,580.4 | $ 1,436.9 |
Letter of credit | ||
Revolving credit facilities | ||
Letters of credit issued inside credit facilities | 2.3 | |
WE | Credit facility maturing October 2022 | ||
Revolving credit facilities | ||
Short-term credit capacity | 500 | |
WPS | Credit facility maturing October 2022 | ||
Revolving credit facilities | ||
Short-term credit capacity | 400 | |
WG | Credit facility maturing October 2022 | ||
Revolving credit facilities | ||
Short-term credit capacity | 350 | |
PGL | Credit facility maturing October 2022 | ||
Revolving credit facilities | ||
Short-term credit capacity | 350 | |
WEC Energy Group | Credit facility maturing October 2022 | ||
Revolving credit facilities | ||
Short-term credit capacity | $ 1,200 |
LONG-TERM DEBT (Details)
LONG-TERM DEBT (Details) - USD ($) $ in Millions | Mar. 30, 2020 | Mar. 31, 2021 | Mar. 31, 2020 |
Debt Instrument [Line Items] | |||
Issuance of short-term loan | $ 0 | $ 340 | |
WEC Energy Group | Term loan | |||
Debt Instrument [Line Items] | |||
Issuance of short-term loan | $ 340 | ||
Length of term loan | 364 days | ||
WEC Energy Group | WEC Senior Notes 0.80% due 2024 | |||
Debt Instrument [Line Items] | |||
Proceeds from issuance of debt | $ 600 | ||
Debt instrument stated interest rate percentage | 0.80% |
MATERIALS, SUPPLIES, AND INVE_3
MATERIALS, SUPPLIES, AND INVENTORIES (Details) - USD ($) $ in Millions | Mar. 31, 2021 | Dec. 31, 2020 |
Energy Related Inventory | ||
Materials and supplies | $ 218.3 | $ 218.1 |
Natural gas in storage | 68.3 | 224.9 |
Fossil fuel | 66.9 | 85.6 |
Total | 353.5 | $ 528.6 |
LIFO Method Related Items | ||
LIFO liquidation credit | $ 66.3 |
INCOME TAXES (Details)
INCOME TAXES (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2021 | Mar. 31, 2020 | |
Effective Income Tax Rate Reconciliation, Amount | ||
Statutory federal income tax, amount | $ 122.8 | $ 113.9 |
State income taxes net of federal tax benefit, amount | 36.9 | 34 |
Wind production tax credits, amount | (34) | (18.4) |
Federal excess deferred tax amortization - Wisconsin unprotected, amount | (30.3) | (22.1) |
Federal excess deferred tax amortization, amount | (14.6) | (13) |
Uncertain tax positions, amount | (8.2) | 0 |
Other, amount | 2.3 | (4.4) |
Total income tax expense, amount | $ 74.9 | $ 90 |
Effective Income Tax Rate Reconciliation, Percent | ||
Statutory federal income tax, percentage | 21.00% | 21.00% |
State income taxes net of federal tax benefit, percentage | 6.30% | 6.30% |
Wind production tax credits, percentage | (5.80%) | (3.40%) |
Federal excess deferred tax amortization - Wisconsin unprotected, percentage | (5.20%) | (4.10%) |
Federal excess deferred tax amortization, percentage | (2.50%) | (2.40%) |
Uncertain tax position, percentage | (1.40%) | 0.00% |
Other, percentage | 0.40% | (0.80%) |
Total income tax expense, percentage | 12.80% | 16.60% |
INCOME TAXES - WI 2020 and 2021
INCOME TAXES - WI 2020 and 2021 RATES (Details) - Tax Cuts and Jobs Act of 2017 - Public Service Commission of Wisconsin (PSCW) - 2020 and 2021 rates | 1 Months Ended |
Dec. 31, 2019 | |
Electric rates | |
Income Taxes [Line Items] | |
Amortization period | 2 years |
Natural gas rates | |
Income Taxes [Line Items] | |
Amortization period | 4 years |
FAIR VALUE MEASUREMENTS - ASSET
FAIR VALUE MEASUREMENTS - ASSETS AND LIABILITIES MEASURED ON A RECURRING BASIS (Details) - USD ($) $ in Millions | Mar. 31, 2021 | Dec. 31, 2020 |
Assets | ||
Derivative assets | $ 17.4 | $ 17.9 |
Liabilities | ||
Derivative liabilities | 9.5 | 22.1 |
Fair value measurements on a recurring basis | ||
Assets | ||
Derivative assets | 17.4 | 17.9 |
Investments held in rabbi trust | 71.6 | 79.6 |
Liabilities | ||
Derivative liabilities | 9.5 | 22.1 |
Fair value measurements on a recurring basis | Level 1 | ||
Assets | ||
Derivative assets | 12.3 | 11.7 |
Investments held in rabbi trust | 71.6 | 79.6 |
Liabilities | ||
Derivative liabilities | 3.1 | 7.7 |
Fair value measurements on a recurring basis | Level 2 | ||
Assets | ||
Derivative assets | 4.2 | 3.8 |
Investments held in rabbi trust | 0 | 0 |
Liabilities | ||
Derivative liabilities | 6.4 | 14.4 |
Fair value measurements on a recurring basis | Level 3 | ||
Assets | ||
Derivative assets | 0.9 | 2.4 |
Investments held in rabbi trust | 0 | 0 |
Liabilities | ||
Derivative liabilities | 0 | 0 |
Fair value measurements on a recurring basis | Natural gas contracts | ||
Assets | ||
Derivative assets | 13.9 | 13.7 |
Liabilities | ||
Derivative liabilities | 4.1 | 14.1 |
Fair value measurements on a recurring basis | Natural gas contracts | Level 1 | ||
Assets | ||
Derivative assets | 12.3 | 11.7 |
Liabilities | ||
Derivative liabilities | 3.1 | 7.7 |
Fair value measurements on a recurring basis | Natural gas contracts | Level 2 | ||
Assets | ||
Derivative assets | 1.6 | 2 |
Liabilities | ||
Derivative liabilities | 1 | 6.4 |
Fair value measurements on a recurring basis | Natural gas contracts | Level 3 | ||
Assets | ||
Derivative assets | 0 | 0 |
Liabilities | ||
Derivative liabilities | 0 | 0 |
Fair value measurements on a recurring basis | FTRs | ||
Assets | ||
Derivative assets | 0.9 | 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 | 0.9 | 2.4 |
Fair value measurements on a recurring basis | Coal contracts | ||
Assets | ||
Derivative assets | 2.6 | 1.8 |
Liabilities | ||
Derivative liabilities | 0.3 | 1.2 |
Fair value measurements on a recurring basis | Coal contracts | Level 1 | ||
Assets | ||
Derivative assets | 0 | 0 |
Liabilities | ||
Derivative liabilities | 0 | 0 |
Fair value measurements on a recurring basis | Coal contracts | Level 2 | ||
Assets | ||
Derivative assets | 2.6 | 1.8 |
Liabilities | ||
Derivative liabilities | 0.3 | 1.2 |
Fair value measurements on a recurring basis | Coal contracts | Level 3 | ||
Assets | ||
Derivative assets | 0 | 0 |
Liabilities | ||
Derivative liabilities | 0 | 0 |
Fair value measurements on a recurring basis | Interest rate swaps | ||
Liabilities | ||
Derivative liabilities | 5.1 | 6.8 |
Fair value measurements on a recurring basis | Interest rate swaps | Level 1 | ||
Liabilities | ||
Derivative liabilities | 0 | 0 |
Fair value measurements on a recurring basis | Interest rate swaps | Level 2 | ||
Liabilities | ||
Derivative liabilities | 5.1 | 6.8 |
Fair value measurements on a recurring basis | Interest rate swaps | Level 3 | ||
Liabilities | ||
Derivative liabilities | $ 0 | $ 0 |
FAIR VALUE MEASUREMENTS - UNREA
FAIR VALUE MEASUREMENTS - UNREALIZED GAIN (LOSS) ON INVESTMENTS (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2021 | Mar. 31, 2020 | |
Fair Value Disclosures [Abstract] | ||
Net unrealized gains included in earnings related to investments held at end of period | $ 4 | |
Net unrealized losses included in earnings related to investments held at end of period | $ 14.2 |
FAIR VALUE MEASUREMENTS - LEVEL
FAIR VALUE MEASUREMENTS - LEVEL 3 RECONCILIATION (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2021 | Mar. 31, 2020 | |
Level 3 rollforward | ||
Balance at the beginning of the period | $ 2.4 | $ 3.1 |
Purchases | 0.1 | 0 |
Settlements | (1.6) | (2.2) |
Balance at the end of the period | $ 0.9 | $ 0.9 |
FAIR VALUE MEASUREMENTS - FINAN
FAIR VALUE MEASUREMENTS - FINANCIAL INSTRUMENTS (Details) - USD ($) $ in Millions | Mar. 31, 2021 | Dec. 31, 2020 |
Financial instruments | ||
Preferred stock of subsidiary | $ 30.4 | $ 30.4 |
Carrying amount | ||
Financial instruments | ||
Preferred stock of subsidiary | 30.4 | 30.4 |
Long-term debt, including current portion | 13,041.8 | 12,450.5 |
Finance lease obligations | 62.9 | 63.4 |
Fair value | ||
Financial instruments | ||
Preferred stock of subsidiary | 29.9 | 32.3 |
Long-term debt, including current portion | $ 14,139 | $ 14,343.2 |
DERIVATIVE INSTRUMENTS - DERIVA
DERIVATIVE INSTRUMENTS - DERIVATIVE ASSETS AND LIABILITIES (Details) - USD ($) $ in Millions | Mar. 31, 2021 | Dec. 31, 2020 |
Derivative assets | ||
Other current derivative assets | $ 16.7 | $ 17 |
Other long-term derivative assets | 0.7 | 0.9 |
Total derivative assets | 17.4 | 17.9 |
Derivative liabilities | ||
Other current derivative liabilities | 8.8 | 20.5 |
Other long-term derivative liabilities | 0.7 | 1.6 |
Total derivative liabilities | 9.5 | 22.1 |
Natural gas contracts | ||
Derivative assets | ||
Other current derivative assets | 13.4 | 13 |
Other long-term derivative assets | 0.5 | 0.7 |
Derivative liabilities | ||
Other current derivative liabilities | 3.6 | 12.9 |
Other long-term derivative liabilities | 0.5 | 1.2 |
FTRs | ||
Derivative assets | ||
Other current derivative assets | 0.9 | 2.4 |
Derivative liabilities | ||
Other current derivative liabilities | 0 | 0 |
Coal contracts | ||
Derivative assets | ||
Other current derivative assets | 2.4 | 1.6 |
Other long-term derivative assets | 0.2 | 0.2 |
Derivative liabilities | ||
Other current derivative liabilities | 0.1 | 0.8 |
Other long-term derivative liabilities | 0.2 | 0.4 |
Interest rate swaps | ||
Derivative assets | ||
Other current derivative assets | 0 | 0 |
Derivative liabilities | ||
Other current derivative liabilities | $ 5.1 | $ 6.8 |
DERIVATIVE INSTRUMENTS - GAINS
DERIVATIVE INSTRUMENTS - GAINS (LOSSES) AND NOTIONAL VOLUMES (Details) MWh in Millions, MMBTU in Millions, $ in Millions | 3 Months Ended | |
Mar. 31, 2021USD ($)MMBTUMWh | Mar. 31, 2020USD ($)MMBTUMWh | |
Realized gains (losses) | ||
Gains (losses) | $ (5.4) | $ (23.3) |
Natural gas contracts | ||
Realized gains (losses) | ||
Gains (losses) | $ (7.5) | $ (24.7) |
Notional sales volumes | ||
Notional sales volumes | MMBTU | 59.8 | 58.4 |
FTRs | ||
Realized gains (losses) | ||
Gains (losses) | $ 2.1 | $ 1.4 |
Notional sales volumes | ||
Notional sales volumes | MWh | 8.4 | 7.2 |
DERIVATIVE INSTRUMENTS - BALANC
DERIVATIVE INSTRUMENTS - BALANCE SHEET OFFSETTING (Details) - USD ($) $ in Millions | Mar. 31, 2021 | Dec. 31, 2020 |
Cash collateral | ||
Cash collateral posted in margin accounts | $ 5.6 | $ 18.9 |
Offsetting derivative assets | ||
Gross amount recognized on the balance sheet | 17.4 | 17.9 |
Gross amount not offset on the balance sheet | (3.1) | (6.9) |
Net amount | 14.3 | 11 |
Offsetting derivative liabilities | ||
Gross amount recognized on the balance sheet | 9.5 | 22.1 |
Gross amount not offset on the balance sheet | (3.1) | (7.7) |
Net amount | $ 6.4 | 14.4 |
Collateral posted | $ 0.8 |
DERIVATIVE INSTRUMENTS - CASH F
DERIVATIVE INSTRUMENTS - CASH FLOW HEDGES (Details) $ in Millions | 3 Months Ended | |
Mar. 31, 2021USD ($)number_of_interest_rate_swaps | Mar. 31, 2020USD ($) | |
Derivative instruments | ||
Interest expense | $ 119.5 | $ 129.4 |
WEC Energy Group | WEC Energy Group's junior subordinated notes due in 2067 | ||
Derivative instruments | ||
Long-term debt outstanding | $ 500 | |
WEC Energy Group | Interest rate swaps | ||
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 loss recognized in other comprehensive loss | $ 0 | (4.7) |
Net derivative loss reclassified from accumulated other comprehensive loss to interest expense | (1.4) | $ (0.1) |
Amount to be reclassified from accumulated other comprehensive loss to interest expense | $ 3.8 |
GUARANTEES (Details)
GUARANTEES (Details) $ in Millions | Mar. 31, 2021USD ($) |
Guarantees | |
Total guarantees | $ 234.2 |
Guarantees expiring in less than 1 year | 70.9 |
Guarantees expiring within 1 to 3 years | 1.6 |
Guarantees with expiration over 3 years | 161.7 |
Guarantees supporting commodity transactions of subsidiaries | |
Guarantees | |
Total guarantees | 138.5 |
Guarantees expiring in less than 1 year | 53.5 |
Guarantees expiring within 1 to 3 years | 1.5 |
Guarantees with expiration over 3 years | 83.5 |
Standby letters of credit | |
Guarantees | |
Total guarantees | 73.3 |
Guarantees expiring in less than 1 year | 5.1 |
Guarantees expiring within 1 to 3 years | 0 |
Guarantees with expiration over 3 years | 68.2 |
Surety bonds | |
Guarantees | |
Total guarantees | 12.4 |
Guarantees expiring in less than 1 year | 12.3 |
Guarantees expiring within 1 to 3 years | 0.1 |
Guarantees with expiration over 3 years | 0 |
Other guarantees | |
Guarantees | |
Total guarantees | 10 |
Guarantees expiring in less than 1 year | 0 |
Guarantees expiring within 1 to 3 years | 0 |
Guarantees with expiration over 3 years | 10 |
Other indemnifications | |
Guarantees | |
Liability related to workers compensation coverage | 10 |
UMERC | Guarantees supporting commodity transactions of subsidiaries | |
Guarantees | |
Total guarantees | 4.2 |
Bluewater | Guarantees supporting commodity transactions of subsidiaries | |
Guarantees | |
Total guarantees | 8.2 |
WECI | Guarantees supporting commodity transactions of subsidiaries | |
Guarantees | |
Total guarantees | $ 126.1 |
EMPLOYEE BENEFITS-COSTS AND CON
EMPLOYEE BENEFITS-COSTS AND CONTRIBUTIONS (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2021 | Mar. 31, 2020 | |
Components of net periodic benefit cost | ||
Contributions and payments related to pension and OPEB plans | $ 4.1 | $ 3.7 |
Pension Benefits | ||
Components of net periodic benefit cost | ||
Service cost | 13.9 | 13.1 |
Interest cost | 21.9 | 26.1 |
Expected return on plan assets | (50.6) | (47.9) |
Loss on plan settlement | 0.1 | 0.3 |
Amortization of prior service (credit) cost | 0.4 | 0.4 |
Amortization of net actuarial (gain) loss | 27.4 | 24.2 |
Net periodic benefit (credit) cost | 13.1 | 16.2 |
Contributions and payments related to pension and OPEB plans | 3.6 | |
Estimated future employer contributions for the remainder of the year | 7.9 | |
Other Postretirement Benefits | ||
Components of net periodic benefit cost | ||
Service cost | 4.2 | 4.1 |
Interest cost | 3.6 | 4.7 |
Expected return on plan assets | (16.4) | (15.1) |
Amortization of prior service (credit) cost | (4) | (3.7) |
Amortization of net actuarial (gain) loss | (5.7) | (5.4) |
Net periodic benefit (credit) cost | (18.3) | $ (15.4) |
Contributions and payments related to pension and OPEB plans | 0.5 | |
Estimated future employer contributions for the remainder of the year | $ 1.6 |
GOODWILL AND INTANGIBLES - GOOD
GOODWILL AND INTANGIBLES - GOODWILL (Details) $ in Millions | 3 Months Ended |
Mar. 31, 2021USD ($) | |
Changes to our goodwill balances by segment | |
Changes to the carrying amount of goodwill | $ 0 |
Goodwill | 3,052.8 |
Accumulated impairment losses | 0 |
Wisconsin | |
Changes to our goodwill balances by segment | |
Goodwill | 2,104.3 |
Illinois | |
Changes to our goodwill balances by segment | |
Goodwill | 758.7 |
Other States | |
Changes to our goodwill balances by segment | |
Goodwill | 183.2 |
Non-Utility Energy Infrastructure | |
Changes to our goodwill balances by segment | |
Goodwill | $ 6.6 |
GOODWILL AND INTANGIBLES - INDE
GOODWILL AND INTANGIBLES - INDEFINITE LIVED INTANGIBLE ASSETS (Details) $ in Millions | 3 Months Ended |
Mar. 31, 2021USD ($) | |
Indefinite-lived Intangible Assets | |
Changes to the carrying amount of indefinite-lived intangible asset | $ 0 |
MGU | Trade name | |
Indefinite-lived Intangible Assets | |
Indefinite-lived intangible asset | $ 5.7 |
GOODWILL AND INTANGIBLES - INTA
GOODWILL AND INTANGIBLES - INTANGIBLE LIABILITIES (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2021 | Dec. 31, 2020 | |
Finite-Lived Intangible Assets | ||
Period of amortization | 5 years | |
Operating revenues | ||
Amortization to be recorded in the next five years | ||
2022 | $ 8.1 | |
2023 | 8.1 | |
2024 | 8.1 | |
2025 | 8.1 | |
2026 | 8.1 | |
Other operation and maintenance | ||
Amortization to be recorded in the next five years | ||
2022 | 0.2 | |
2023 | 0.2 | |
2024 | 0.2 | |
2025 | 0.2 | |
2026 | 0.2 | |
WECI | ||
Finite-Lived Intangible Assets | ||
Gross carrying amount | 96.9 | $ 88.4 |
Accumulated amortization | (3.5) | (1.6) |
Net carrying amount | 93.4 | 86.8 |
PPAs | WECI | ||
Finite-Lived Intangible Assets | ||
Gross carrying amount | 84.6 | 76.1 |
Accumulated amortization | (1.6) | 0 |
Net carrying amount | $ 83 | 76.1 |
PPAs | Blooming Grove Wind Energy Center LLC, Tatanka Ridge Wind, LLC and Jayhawk | ||
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 | (1.5) | (1.3) |
Net carrying amount | $ 5.7 | 5.9 |
Proxy revenue swap | Upstream | ||
Finite-Lived Intangible Assets | ||
Weighted average useful life | 8 years | |
Length of proxy revenue contract, in years | 10 years | |
Interconnection agreements | WECI | ||
Finite-Lived Intangible Assets | ||
Gross carrying amount | $ 5.1 | 5.1 |
Accumulated amortization | (0.4) | (0.3) |
Net carrying amount | $ 4.7 | $ 4.8 |
Interconnection agreements | Tatanka Ridge Wind LLC and Bishop Hill Energy III LLC | ||
Finite-Lived Intangible Assets | ||
Weighted average useful life | 20 years |
INVESTMENT IN TRANSMISSION AF_3
INVESTMENT IN TRANSMISSION AFFILIATES - CHANGES TO INVESTMENTS (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2021 | Mar. 31, 2020 | |
Changes to investments in transmission affiliates | ||
Add: Earnings from equity method investment | $ 42.6 | $ 39.8 |
Add: Capital contributions | 0 | 3 |
Transmission Affiliates | ||
Changes to investments in transmission affiliates | ||
Investment in transmission affiliates, balance at beginning of period | 1,764.3 | 1,720.8 |
Add: Earnings from equity method investment | 42.6 | 39.8 |
Add: Capital contributions | 3 | |
Less: Distributions | 33.4 | 40.6 |
Less: Return of capital | 5.3 | |
Add: Other | 0.1 | |
Investment in transmission affiliates, balance at end of period | $ 1,773.6 | 1,717.7 |
ATC | ||
Investment in transmission affiliates | ||
Equity method investment, ownership interest (as a percent) | 60.00% | |
Changes to investments in transmission affiliates | ||
Investment in transmission affiliates, balance at beginning of period | $ 1,733.5 | 1,684.7 |
Add: Earnings from equity method investment | 41.7 | 39.6 |
Add: Capital contributions | 3 | |
Less: Distributions | 33.4 | 40.6 |
Less: Return of capital | 0 | |
Add: Other | 0.1 | |
Investment in transmission affiliates, balance at end of period | $ 1,741.9 | 1,686.7 |
ATC Holdco | ||
Investment in transmission affiliates | ||
Equity method investment, ownership interest (as a percent) | 75.00% | |
Changes to investments in transmission affiliates | ||
Investment in transmission affiliates, balance at beginning of period | $ 30.8 | 36.1 |
Add: Earnings from equity method investment | 0.9 | 0.2 |
Add: Capital contributions | 0 | |
Less: Distributions | 0 | 0 |
Less: Return of capital | 5.3 | |
Add: Other | 0 | |
Investment in transmission affiliates, balance at end of period | $ 31.7 | $ 31 |
INVESTMENT IN TRANSMISSION AF_4
INVESTMENT IN TRANSMISSION AFFILIATES - RELATED PARTY TRANSACTIONS (Details) - ATC - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2021 | Mar. 31, 2020 | |
Investment in transmission affiliates | ||
Charges to ATC for services and construction | $ 6 | $ 6 |
Charges from ATC for network transmission services | $ 92.6 | $ 86.9 |
INVESTMENT IN TRANSMISSION AF_5
INVESTMENT IN TRANSMISSION AFFILIATES - RELATED PARTY TRANSACTIONS BALANCE SHEET INFORMATION (Details) - ATC - USD ($) $ in Millions | Mar. 31, 2021 | Dec. 31, 2020 |
Investment in transmission affiliates | ||
Accounts receivable for services provided to ATC | $ 2.4 | $ 3.7 |
Accounts payable for services received from ATC | 30.3 | 29.3 |
Amounts due from ATC for transmission infrastructure upgrades | $ 5.3 | $ 4.6 |
INVESTMENT IN TRANSMISSION AF_6
INVESTMENT IN TRANSMISSION AFFILIATES - SUMMARIZED FINANCIAL DATA (Details) - USD ($) $ in Millions | 3 Months Ended | ||
Mar. 31, 2021 | Mar. 31, 2020 | Dec. 31, 2020 | |
Summarized financial data | |||
Total operating revenues | $ 2,691.4 | $ 2,108.6 | |
Operating expenses | 2,062.1 | 1,482 | |
Other expense, net | 44.1 | 84 | |
Current assets | 2,355.5 | $ 2,083 | |
Noncurrent assets | 35,245.1 | 34,945.1 | |
Total assets | 37,600.6 | 37,028.1 | |
Current liabilities | 3,714.9 | 4,148.1 | |
Other noncurrent liabilities | 1,236.3 | 1,229.4 | |
Total liabilities and members' equity | 37,600.6 | 37,028.1 | |
ATC | |||
Summarized financial data | |||
Total operating revenues | 188.7 | 186.8 | |
Operating expenses | 95.1 | 95.2 | |
Other expense, net | 28.5 | 28.5 | |
Net income | 65.1 | $ 63.1 | |
Current assets | 90 | 92.7 | |
Noncurrent assets | 5,431.8 | 5,400.6 | |
Total assets | 5,521.8 | 5,493.3 | |
Current liabilities | 420.1 | 310.8 | |
Long-term debt | 2,412.5 | 2,512.2 | |
Other noncurrent liabilities | 385 | 378.2 | |
Members' equity | 2,304.2 | 2,292.1 | |
Total liabilities and members' equity | $ 5,521.8 | $ 5,493.3 |
SEGMENT INFORMATION (Details)
SEGMENT INFORMATION (Details) $ in Millions | 3 Months Ended | |
Mar. 31, 2021USD ($)segment | Mar. 31, 2020USD ($) | |
Segment information | ||
Number of reportable segments | segment | 6 | |
Total operating revenues | $ 2,691.4 | $ 2,108.6 |
Other operation and maintenance | 479.9 | 455.7 |
Depreciation and amortization | 261.4 | 239.1 |
Equity in earnings of transmission affiliates | 42.6 | 39.8 |
Interest expense | 119.5 | 129.4 |
Income tax expense (benefit) | 74.9 | 90 |
Net income (loss) | 510.3 | 452.6 |
Net income attributed to common shareholders | 510.1 | 452.5 |
Reconciling Eliminations | ||
Segment information | ||
Other operation and maintenance | (1.6) | (4.5) |
Depreciation and amortization | (14.3) | (12.2) |
Equity in earnings of transmission affiliates | 0 | 0 |
Interest expense | (85.7) | (87.1) |
Income tax expense (benefit) | 0 | 0 |
Net income (loss) | 0 | 0 |
Net income attributed to common shareholders | 0 | 0 |
Wisconsin | ||
Segment information | ||
Total operating revenues | 1,731.7 | 1,498.9 |
Illinois | ||
Segment information | ||
Total operating revenues | 703.4 | 447.6 |
Other States | ||
Segment information | ||
Total operating revenues | 233.3 | 146.4 |
Electric Transmission | ||
Segment information | ||
Other operation and maintenance | 0 | 0 |
Depreciation and amortization | 0 | 0 |
Equity in earnings of transmission affiliates | 42.6 | 39.8 |
Interest expense | 4.9 | 4.8 |
Income tax expense (benefit) | 9.8 | 9.9 |
Net income (loss) | 28 | 25 |
Net income attributed to common shareholders | $ 28 | 25 |
Non-Utility Energy Infrastructure | ||
Segment information | ||
Natural gas storage needs provided to Wisconsin utilities | 33.00% | |
Total operating revenues | $ 137.6 | 129.6 |
Other operation and maintenance | 8.9 | 5.2 |
Depreciation and amortization | 31 | 24.5 |
Equity in earnings of transmission affiliates | 0 | 0 |
Interest expense | 18 | 15.3 |
Income tax expense (benefit) | 0.1 | 11.2 |
Net income (loss) | 71.3 | 65.3 |
Net income attributed to common shareholders | 71.4 | 65.5 |
Corporate and Other | ||
Segment information | ||
Total operating revenues | 0.1 | 0.5 |
Other operation and maintenance | (1.8) | (1.6) |
Depreciation and amortization | 6.6 | 6.1 |
Equity in earnings of transmission affiliates | 0 | 0 |
Interest expense | 24.2 | 35.1 |
Income tax expense (benefit) | (32.9) | (30.7) |
Net income (loss) | 17.6 | (18.3) |
Net income attributed to common shareholders | $ 17.6 | (18.3) |
Bishop Hill III | Non-Utility Energy Infrastructure | ||
Segment information | ||
WEC's ownership interest | 90.00% | |
Coyote Ridge | Non-Utility Energy Infrastructure | ||
Segment information | ||
WEC's ownership interest | 80.00% | |
Upstream | Non-Utility Energy Infrastructure | ||
Segment information | ||
WEC's ownership interest | 90.00% | |
Blooming Grove | Non-Utility Energy Infrastructure | ||
Segment information | ||
WEC's ownership interest | 90.00% | |
Tatanka Ridge | Non-Utility Energy Infrastructure | ||
Segment information | ||
WEC's ownership interest | 85.00% | |
JayhawkWindLLC | Non-Utility Energy Infrastructure | ||
Segment information | ||
WEC's ownership interest | 90.00% | |
ATC | Electric Transmission | ||
Segment information | ||
Equity method investment, ownership interest (as a percent) | 60.00% | |
ATC Holdco | ||
Segment information | ||
Equity method investment, ownership interest (as a percent) | 75.00% | |
Equity in earnings of transmission affiliates | $ 0.9 | 0.2 |
ATC Holdco | Electric Transmission | ||
Segment information | ||
Equity method investment, ownership interest (as a percent) | 75.00% | |
Utility Operations | ||
Segment information | ||
Other operation and maintenance | $ 474.4 | 456.6 |
Depreciation and amortization | 238.1 | 220.7 |
Equity in earnings of transmission affiliates | 0 | 0 |
Interest expense | 158.1 | 161.3 |
Income tax expense (benefit) | 97.9 | 99.6 |
Net income (loss) | 393.4 | 380.6 |
Net income attributed to common shareholders | 393.1 | 380.3 |
Utility Operations | Wisconsin | ||
Segment information | ||
Other operation and maintenance | 341.9 | 330.8 |
Depreciation and amortization | 176.2 | 165.4 |
Equity in earnings of transmission affiliates | 0 | 0 |
Interest expense | 140.1 | 143.1 |
Income tax expense (benefit) | 48.1 | 51.2 |
Net income (loss) | 256.6 | 247 |
Net income attributed to common shareholders | 256.3 | 246.7 |
Utility Operations | Illinois | ||
Segment information | ||
Other operation and maintenance | 109.3 | 104.1 |
Depreciation and amortization | 52.7 | 47.5 |
Equity in earnings of transmission affiliates | 0 | 0 |
Interest expense | 16.5 | 16 |
Income tax expense (benefit) | 41.4 | 39.5 |
Net income (loss) | 112.1 | 107.3 |
Net income attributed to common shareholders | 112.1 | 107.3 |
Utility Operations | Other States | ||
Segment information | ||
Other operation and maintenance | 23.2 | 21.7 |
Depreciation and amortization | 9.2 | 7.8 |
Equity in earnings of transmission affiliates | 0 | 0 |
Interest expense | 1.5 | 2.2 |
Income tax expense (benefit) | 8.4 | 8.9 |
Net income (loss) | 24.7 | 26.3 |
Net income attributed to common shareholders | 24.7 | 26.3 |
External Revenues | ||
Segment information | ||
Total operating revenues | 2,691.4 | 2,108.6 |
External Revenues | Reconciling Eliminations | ||
Segment information | ||
Total operating revenues | 0 | 0 |
External Revenues | Electric Transmission | ||
Segment information | ||
Total operating revenues | 0 | 0 |
External Revenues | Non-Utility Energy Infrastructure | ||
Segment information | ||
Total operating revenues | 22.9 | 15.2 |
External Revenues | Corporate and Other | ||
Segment information | ||
Total operating revenues | 0.1 | 0.5 |
External Revenues | Utility Operations | ||
Segment information | ||
Total operating revenues | 2,668.4 | 2,092.9 |
External Revenues | Utility Operations | Wisconsin | ||
Segment information | ||
Total operating revenues | 1,731.7 | 1,498.9 |
External Revenues | Utility Operations | Illinois | ||
Segment information | ||
Total operating revenues | 703.4 | 447.6 |
External Revenues | Utility Operations | Other States | ||
Segment information | ||
Total operating revenues | 233.3 | 146.4 |
Intersegment Revenues | ||
Segment information | ||
Total operating revenues | 0 | 0 |
Intersegment Revenues | Reconciling Eliminations | ||
Segment information | ||
Total operating revenues | (114.7) | (114.4) |
Intersegment Revenues | Electric Transmission | ||
Segment information | ||
Total operating revenues | 0 | 0 |
Intersegment Revenues | Non-Utility Energy Infrastructure | ||
Segment information | ||
Total operating revenues | 114.7 | 114.4 |
Intersegment Revenues | Corporate and Other | ||
Segment information | ||
Total operating revenues | 0 | 0 |
Intersegment Revenues | Utility Operations | ||
Segment information | ||
Total operating revenues | 0 | 0 |
Intersegment Revenues | Utility Operations | Wisconsin | ||
Segment information | ||
Total operating revenues | 0 | 0 |
Intersegment Revenues | Utility Operations | Illinois | ||
Segment information | ||
Total operating revenues | 0 | 0 |
Intersegment Revenues | Utility Operations | Other States | ||
Segment information | ||
Total operating revenues | $ 0 | $ 0 |
VARIABLE INTEREST ENTITIES (Det
VARIABLE INTEREST ENTITIES (Details) $ in Millions | 3 Months Ended |
Mar. 31, 2021USD ($)MW | |
ATC | |
Variable interest entities | |
Ownership interest (as a percent) | 60.00% |
ATC Holdco | |
Variable interest entities | |
Ownership interest (as a percent) | 75.00% |
Power purchase agreement | |
Variable interest entities | |
Firm capacity from power purchase agreement (in megawatts) | MW | 236 |
Minimum energy requirements over remaining term of power purchase agreement (in megawatts) | MW | 0 |
Remaining term of power purchase agreement (in years) | 1 year |
Residual guarantee associated with power purchase agreement | $ | $ 0 |
Required payments over remaining term of power purchase agreement | $ | $ 11.2 |
COMMITMENTS AND CONTINGENCIES -
COMMITMENTS AND CONTINGENCIES - UNCONDITIONAL PURCHASE OBLIGATIONS (Details) $ in Billions | Mar. 31, 2021USD ($) |
Minimum future commitments for purchase obligations | |
Purchase obligations | $ 11.1 |
COMMITMENTS AND CONTINGENCIES_2
COMMITMENTS AND CONTINGENCIES - ENVIRONMENTAL MATTERS (Details) T in Millions, $ in Millions | 3 Months Ended | 12 Months Ended | 15 Months Ended |
Mar. 31, 2021USD ($)Statesperformance_obligationscompliance_optionMW | Dec. 31, 2020USD ($)T | Mar. 31, 2019MW | |
Manufactured gas plant remediation | |||
Regulatory assets | $ 3,793.8 | $ 3,544.1 | |
Environmental remediation costs | |||
Manufactured gas plant remediation | |||
Regulatory assets | $ 623.1 | $ 638.2 | |
National Ambient Air Quality Standards | Electric | |||
Air quality | |||
Number of changes to the 2015 ozone standards | performance_obligations | 0 | ||
Number of revisions necessary to the 2012 standard for particulate matter | performance_obligations | 0 | ||
Climate Change | Electric | |||
Air quality | |||
Number of rules that regulate GHG emissions from electric generating units | compliance_option | 0 | ||
Company goal percentage met by the end of 2020 for carbon dioxide emissions reduction below 2005 levels | 50.00% | ||
Company goal for percentage of carbon dioxide emissions reduction below 2005 levels by 2025 | 60.00% | ||
Company goal for percentage of carbon dioxide emissions reduction below 2005 levels by 2030 | 80.00% | ||
Capacity of coal-fired generation retired, in megawatts | MW | 1,800 | ||
Capacity of fossil-fueled generation to be retired by 2025, in megawatts | MW | 1,800 | ||
Carbon dioxide emissions | T | 20.1 | ||
Climate Change | Natural gas | |||
Air quality | |||
Initial 2030 percentage goal for a reduction of methane emissions from a 2011 baseline | 30.00% | ||
Carbon dioxide emissions | T | 27 | ||
Cross State Air Pollution Rule Update Rule Revision | Electric | |||
Air quality | |||
Number of states in Group 2 for CSAPR update rule revision | States | 9 | ||
Number of states affected by the CSAPR update rule revision | States | 21 | ||
Amount of further NOx reductions needed within the nine effected states | performance_obligations | 0 | ||
Steam Electric Effluent Limitation Guidelines | Electric | |||
Water quality | |||
Number of new ELG rule requirements that affect our electric utilities | performance_obligations | 2 | ||
Expected capital investment to achieve required discharge limits | $ 110 | ||
Manufactured Gas Plant Remediation | Natural gas | |||
Manufactured gas plant remediation | |||
Reserves for future environmental remediation | 532.9 | $ 532.9 | |
Manufactured Gas Plant Remediation | Natural gas | Environmental remediation costs | |||
Manufactured gas plant remediation | |||
Regulatory assets | $ 623.1 | $ 638.2 |
SUPPLEMENTAL CASH FLOW INFORM_3
SUPPLEMENTAL CASH FLOW INFORMATION - SUPPLEMENTAL INFORMATION (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2021 | Mar. 31, 2020 | |
Supplemental cash flow information | ||
Cash paid for interest, net of amount capitalized | $ 76.8 | $ 85.8 |
Cash received for income taxes, net | (2.5) | (11.2) |
Significant non-cash investing and financing transactions: | ||
Accounts payable related to construction costs | 97.8 | 102.5 |
Receivable related to insurance proceeds for property damage (1) | $ 2.7 | $ 0 |
SUPPLEMENTAL CASH FLOW INFORM_4
SUPPLEMENTAL CASH FLOW INFORMATION - RECONCILIATION OF CASH AND CASH EQUIVALENTS AND RESTRICTED CASH (Details) - USD ($) $ in Millions | Mar. 31, 2021 | Dec. 31, 2020 | Mar. 31, 2020 | Dec. 31, 2019 |
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract] | ||||
Cash and cash equivalents | $ 26.1 | $ 24.8 | ||
Restricted cash included in other current assets | 10.6 | 0 | ||
Restricted cash included in other long term assets | 52.9 | 47.8 | ||
Cash, cash equivalents, and restricted cash | $ 89.6 | $ 72.6 | $ 65.7 | $ 82.3 |
REGULATORY ENVIRONMENT - RECOVE
REGULATORY ENVIRONMENT - RECOVERY OF NATURAL GAS COSTS (Details) - USD ($) | Mar. 30, 2021 | Feb. 28, 2021 | Mar. 31, 2021 | Dec. 31, 2020 |
Public Utilities, General Disclosures [Line Items] | ||||
Amounts recoverable from customers | $ 306,700,000 | $ 20,000,000 | ||
Public Service Commission of Wisconsin (PSCW) | Excess Natural Gas Costs | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Recovery period of regulatory asset | 3 months | |||
Illinois Commerce Commission (ICC) | Excess Natural Gas Costs | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Recovery period of regulatory asset | 12 months | |||
WE | Public Service Commission of Wisconsin (PSCW) | Excess Natural Gas Costs | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Amounts recoverable from customers | $ 54,000,000 | |||
WG | Public Service Commission of Wisconsin (PSCW) | Excess Natural Gas Costs | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Amounts recoverable from customers | 24,000,000 | |||
WPS | Public Service Commission of Wisconsin (PSCW) | Excess Natural Gas Costs | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Amounts recoverable from customers | $ 28,000,000 | |||
Recovery period of regulatory asset | 3 months | |||
PGL | Illinois Commerce Commission (ICC) | Excess Natural Gas Costs | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Amounts recoverable from customers | $ 131,000,000 | |||
NSG | Illinois Commerce Commission (ICC) | Excess Natural Gas Costs | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Amounts recoverable from customers | 10,000,000 | |||
MERC | Minnesota Public Utilities Commission (MPUC) | Excess Natural Gas Costs | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Amounts recoverable from customers | $ 75,000,000 | |||
Recovery period of regulatory asset | 12 months |
REGULATORY ENVIRONMENT - COVID-
REGULATORY ENVIRONMENT - COVID-19 (Details) $ in Millions | Mar. 18, 2021USD ($) | Aug. 01, 2020 | Mar. 31, 2021USD ($) | Jun. 30, 2020USD ($) | Mar. 31, 2020order | Apr. 30, 2021USD ($) | Dec. 31, 2020USD ($) |
Public Utilities, General Disclosures [Line Items] | |||||||
Regulatory assets | $ 3,793.8 | $ 3,544.1 | |||||
Public Service Commission of Wisconsin (PSCW) | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Number of orders issued in response to COVID-19 | order | 2 | ||||||
Illinois Commerce Commission (ICC) | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Additional period of time deposit requirements will be waived | 4 months | ||||||
Percentage below federal poverty level for which customer disconnection is disallowed | 300.00% | ||||||
Illinois Commerce Commission (ICC) | COVID-19 | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Recovery period of regulatory asset | 36 months | ||||||
Regulatory assets | $ 20 | ||||||
Illinois Commerce Commission (ICC) | PGL | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Amount available through bill payment assistance program | $ 12 | ||||||
Additional amount available through bill payment assistance program | $ 6 | ||||||
Illinois Commerce Commission (ICC) | PGL | Subsequent event | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Amount of funds provided through bill payment assistance program | $ 18 | ||||||
Illinois Commerce Commission (ICC) | NSG | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Amount available through bill payment assistance program | $ 1.2 | ||||||
Minnesota Public Utilities Commission (MPUC) | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Period of time after peacetime emergency that order will be effective | 60 days | 90 days |
REGULATORY ENVIRONMENT - 2022 R
REGULATORY ENVIRONMENT - 2022 Rates (Details) - 2022 Rates - Public Service Commission of Wisconsin (PSCW) | Mar. 30, 2021utility |
Public Utilities, General Disclosures [Line Items] | |
Period to forego filing a rate case | 1 year |
Number of Companies Entering into Agreement | 3 |
Percentage of first 15 basis points of additional earnings retained by the utility | 100.00% |
Return on equity in excess of authorized amount (as a percent) | 0.15% |
REGULATORY ENVIRONMENT - WI 202
REGULATORY ENVIRONMENT - WI 2020 AND 2021 RATES (Details) - Public Service Commission of Wisconsin (PSCW) $ in Millions | 1 Months Ended |
Dec. 31, 2019USD ($)utility | |
2020 and 2021 rates | |
Public Utilities, General Disclosures [Line Items] | |
Number of utilities filing rate requests | utility | 3 |
Number of utilities with earnings sharing mechanism | utility | 3 |
Percentage of first 25 basis points of additional earnings retained by the utility | 100.00% |
Return on equity in excess of authorized amount (as a percent) | 0.25% |
Percentage of additional earnings between 25 and 75 basis points refunded to customers | 50.00% |
Return on equity in excess of first 25 basis points above authorized amount (as a percent) | 0.50% |
Percentage of earnings in excess of 75 basis points refunded to customers | 100.00% |
2020 and 2021 rates | Electric rates | Tax Cuts and Jobs Act of 2017 | |
Public Utilities, General Disclosures [Line Items] | |
Amortization period | 2 years |
2020 and 2021 rates | Natural gas rates | Tax Cuts and Jobs Act of 2017 | |
Public Utilities, General Disclosures [Line Items] | |
Number of utilities filing rate requests | utility | 3 |
Amortization period | 4 years |
WE | 2020 and 2021 rates | |
Public Utilities, General Disclosures [Line Items] | |
Approved return on equity (as a percent) | 10.00% |
Approved common equity component average (as a percent) | 52.50% |
WE | 2020 and 2021 rates | Electric rates | |
Public Utilities, General Disclosures [Line Items] | |
Pleasant Prairie power plant's book value to be securitized | $ 100 |
WE | 2020 rates | Electric rates | |
Public Utilities, General Disclosures [Line Items] | |
Approved rate increase | $ 15.3 |
Approved rate increase (as a percent) | 0.50% |
WE | 2020 rates | Electric rates | Tax Cuts and Jobs Act of 2017 | |
Public Utilities, General Disclosures [Line Items] | |
Amortization of regulatory liabilities | $ 65 |
WE | 2020 rates | Natural gas rates | |
Public Utilities, General Disclosures [Line Items] | |
Approved rate increase | $ 10.4 |
Approved rate increase (as a percent) | 2.80% |
WE | 2020 rates | Natural gas rates | Tax Cuts and Jobs Act of 2017 | |
Public Utilities, General Disclosures [Line Items] | |
Amortization of regulatory liabilities | $ (5) |
WE | 2020 rates | Steam rates | |
Public Utilities, General Disclosures [Line Items] | |
Approved rate increase | $ 1.9 |
Approved rate increase (as a percent) | 8.60% |
WE | 2021 rates | Electric rates | Tax Cuts and Jobs Act of 2017 | |
Public Utilities, General Disclosures [Line Items] | |
Amortization of regulatory liabilities | $ 65 |
WE | 2021 rates | Natural gas rates | Tax Cuts and Jobs Act of 2017 | |
Public Utilities, General Disclosures [Line Items] | |
Amortization of regulatory liabilities | $ (5) |
WPS | 2020 and 2021 rates | |
Public Utilities, General Disclosures [Line Items] | |
Approved return on equity (as a percent) | 10.00% |
Approved common equity component average (as a percent) | 52.50% |
WPS | 2020 and 2021 rates | Electric rates | |
Public Utilities, General Disclosures [Line Items] | |
Authorized revenue requirement for ReACT | $ 275 |
Cost of the ReACT project | $ 342 |
WPS | 2020 and 2021 rates | Electric rates | ReACT | |
Public Utilities, General Disclosures [Line Items] | |
Collection of ReACT regulatory asset in years | 8 years |
WPS | 2020 and 2021 rates | Electric rates | Earnings sharing mechanisms | |
Public Utilities, General Disclosures [Line Items] | |
Amortization period | 2 years |
Amortization of regulatory liabilities | $ 21 |
WPS | 2020 rates | Electric rates | |
Public Utilities, General Disclosures [Line Items] | |
Approved rate increase | $ 15.8 |
Approved rate increase (as a percent) | 1.60% |
WPS | 2020 rates | Electric rates | Tax Cuts and Jobs Act of 2017 | |
Public Utilities, General Disclosures [Line Items] | |
Amortization of regulatory liabilities | $ 11 |
WPS | 2020 rates | Natural gas rates | |
Public Utilities, General Disclosures [Line Items] | |
Approved rate increase | $ 4.3 |
Approved rate increase (as a percent) | 1.40% |
WPS | 2020 rates | Natural gas rates | Tax Cuts and Jobs Act of 2017 | |
Public Utilities, General Disclosures [Line Items] | |
Amortization of regulatory liabilities | $ 5 |
WPS | 2021 rates | Electric rates | Tax Cuts and Jobs Act of 2017 | |
Public Utilities, General Disclosures [Line Items] | |
Amortization of regulatory liabilities | 39 |
WPS | 2021 rates | Natural gas rates | Tax Cuts and Jobs Act of 2017 | |
Public Utilities, General Disclosures [Line Items] | |
Amortization of regulatory liabilities | $ 5 |
WG | 2020 and 2021 rates | |
Public Utilities, General Disclosures [Line Items] | |
Approved return on equity (as a percent) | 10.20% |
Approved common equity component average (as a percent) | 52.50% |
WG | 2020 rates | Natural gas rates | |
Public Utilities, General Disclosures [Line Items] | |
Approved rate increase | $ (1.5) |
Approved rate increase (as a percent) | (0.20%) |
WG | 2020 rates | Natural gas rates | Tax Cuts and Jobs Act of 2017 | |
Public Utilities, General Disclosures [Line Items] | |
Amortization of regulatory liabilities | $ 3 |
WG | 2021 rates | Natural gas rates | Tax Cuts and Jobs Act of 2017 | |
Public Utilities, General Disclosures [Line Items] | |
Amortization of regulatory liabilities | $ 3 |
REGULATORY ENVIRONMENT - NSG 20
REGULATORY ENVIRONMENT - NSG 2021 RATE CASE (Details) - Illinois Commerce Commission (ICC) - NSG $ in Millions | Oct. 15, 2020USD ($) |
Public Utilities, General Disclosures [Line Items] | |
Requested rate increase | $ 7.6 |
Requested rate increase (as a percent) | 8.50% |
Requested return on equity (as a percent) | 10.00% |
Requested common equity component average (as a percent) | 52.50% |
REGULATORY ENVIRONMENT - PGL (D
REGULATORY ENVIRONMENT - PGL (Details) | Mar. 31, 2021Assurance |
Illinois Commerce Commission (ICC) | PGL | |
Public Utilities, General Disclosures [Line Items] | |
Amount of assurance that PGL's QIP rider costs will be recoverable | 0 |
REGULATORY ENVIRONMENT - MGU 20
REGULATORY ENVIRONMENT - MGU 2021 RATE APPLICATION (Details) - Michigan Public Service Commission (MPSC) - MGU - USD ($) $ in Millions | Mar. 22, 2021 | Jul. 01, 2020 |
Public Utilities, General Disclosures [Line Items] | ||
Depreciation and interest expense approved for deferral | $ 5 | |
Requested rate increase | $ 15.1 | |
Requested rate increase (as a percent) | 10.70% | |
Requested return on equity (as a percent) | 10.20% | |
Requested common equity component average (as a percent) | 52.50% |