Cover Page
Cover Page - USD ($) $ in Billions | 12 Months Ended | ||
Dec. 31, 2019 | Jan. 31, 2020 | Jun. 30, 2019 | |
Cover page. | |||
Document Type | 10-K | ||
Document Annual Report | true | ||
Document Period End Date | Dec. 31, 2019 | ||
Document Transition Report | false | ||
Entity File Number | 001-09057 | ||
Entity Registrant Name | WEC ENERGY GROUP, INC. | ||
Entity Tax Identification Number | 39-1391525 | ||
Entity Incorporation, State or Country Code | WI | ||
Entity Address, Address Line One | 231 West Michigan Street | ||
Entity Address, Address Line Two | P.O. Box 1331 | ||
Entity Address, City or Town | Milwaukee | ||
Entity Address, State or Province | WI | ||
Entity Address, Postal Zip Code | 53201 | ||
City Area Code | 414 | ||
Local Phone Number | 221-2345 | ||
Title of 12(b) Security | Common Stock, $.01 Par Value | ||
Trading Symbol | WEC | ||
Security Exchange Name | NYSE | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Interactive Data Current | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false | ||
Entity Shell Company | false | ||
Entity Public Float | $ 26.3 | ||
Entity Common Stock, Shares Outstanding | 315,434,531 | ||
Documents Incorporated by Reference | Portions of WEC Energy Group, Inc.'s Definitive Proxy Statement on Schedule 14A for its Annual Meeting of Shareholders, to be held on May 6, 2020 , are incorporated by reference into Part III hereof. | ||
Entity Central Index Key | 0000783325 | ||
Current Fiscal Year End Date | --12-31 | ||
Document Fiscal Year Focus | 2019 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false |
Consolidated Income Statements
Consolidated Income Statements - USD ($) shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Income Statement [Abstract] | |||
Operating revenues | $ 7,523.1 | $ 7,679.5 | $ 7,648.5 |
Operating expenses | |||
Cost of sales | 2,678.8 | 2,897.9 | 2,822.8 |
Other operation and maintenance | 2,184.8 | 2,270.5 | 2,056.1 |
Depreciation and amortization | 926.3 | 845.8 | 798.6 |
Property and revenue taxes | 201.8 | 196.9 | 194.9 |
Total operating expenses | 5,991.7 | 6,211.1 | 5,872.4 |
Operating income | 1,531.4 | 1,468.4 | 1,776.1 |
Equity in earnings of transmission affiliates | 127.6 | 136.7 | 154.3 |
Other income, net | 102.2 | 70.3 | 73.7 |
Interest expense | 501.5 | 445.1 | 415.7 |
Other expense | (271.7) | (238.1) | (187.7) |
Income before income taxes | 1,259.7 | 1,230.3 | 1,588.4 |
Income tax expense | 125 | 169.8 | 383.5 |
Net income | 1,134.7 | 1,060.5 | 1,204.9 |
Preferred stock dividends of subsidiary | 1.2 | 1.2 | 1.2 |
Net loss attributed to noncontrolling interests | 0.5 | 0 | 0 |
Net income attributed to common shareholders | $ 1,134 | $ 1,059.3 | $ 1,203.7 |
Earnings per share | |||
Basic (in dollars per share) | $ 3.60 | $ 3.36 | $ 3.81 |
Diluted (in dollars per share) | $ 3.58 | $ 3.34 | $ 3.79 |
Weighted average common shares outstanding | |||
Basic (in shares) | 315.4 | 315.5 | 315.6 |
Diluted (in shares) | 316.7 | 316.9 | 317.2 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Net income | $ 1,134.7 | $ 1,060.5 | $ 1,204.9 |
Defined benefit plans | |||
Other comprehensive loss, net of tax | (1.5) | (5.5) | 0 |
Comprehensive income | 1,133.2 | 1,055 | 1,204.9 |
Preferred stock dividends of subsidiary | 1.2 | 1.2 | 1.2 |
Comprehensive loss attributed to noncontrolling interests | 0.5 | 0 | 0 |
Comprehensive income attributed to common shareholders | 1,132.5 | 1,053.8 | 1,203.7 |
Cash flow hedges | |||
Other comprehensive (loss) income, net of tax | |||
Cumulative effect adjustment from adoption of ASU 2018-02 | 0 | 1.6 | 0 |
Derivatives accounted for as cash flow hedges | |||
Net derivative losses, net of tax benefits of $1.3, $0.8, and $0.0, respectively | (3.5) | (2.1) | 0 |
Reclassification of net gains to net income, net of tax | (0.8) | (1.2) | (1.3) |
Cash flow hedges, net | (4.3) | (1.7) | (1.3) |
Defined benefit plans | |||
Other comprehensive (loss) income, net of tax | |||
Cumulative effect adjustment from adoption of ASU 2018-02 | 0 | (1) | 0 |
Defined benefit plans | |||
Pension and OPEB adjustments arising during the period, net of tax expense (benefit) of $1.0, $(1.2), and $0.6, respectively | 2.6 | (3.1) | 0.9 |
Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax | 0.2 | 0.3 | 0.4 |
Defined benefit plans, net | $ 2.8 | $ (3.8) | $ 1.3 |
Consolidated Statements of Co_2
Consolidated Statements of Comprehensive Income (Parentheticals) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Statement of Other Comprehensive Income [Abstract] | |||
Net derivative losses, tax benefits | $ 1.3 | $ 0.8 | $ 0 |
Defined benefit plans | |||
Pension and OPEB adjustments arising during the period, tax | $ 1 | $ (1.2) | $ 0.6 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Current assets | ||
Cash and cash equivalents | $ 37.5 | $ 84.5 |
Accounts receivable and unbilled revenues, net of reserves of $140.0 and $149.2, respectively | 1,176.5 | 1,280.9 |
Materials, supplies, and inventories | 549.8 | 548.2 |
Prepayments | 261.8 | 256.8 |
Other | 68 | 77.2 |
Current assets | 2,093.6 | 2,247.6 |
Long-term assets | ||
Property, plant, and equipment, net of accumulated depreciation and amortization of $8,878.7 and $8,636.6, respectively | 23,620.1 | 22,000.9 |
Regulatory assets | 3,506.7 | 3,805.1 |
Equity investment in transmission affiliates | 1,720.8 | 1,665.3 |
Goodwill | 3,052.8 | 3,052.8 |
Other | 957.8 | 704.1 |
Long-term assets | 32,858.2 | 31,228.2 |
Total assets | 34,951.8 | 33,475.8 |
Current liabilities | ||
Short-term debt | 830.8 | 1,440.1 |
Current portion of long-term debt | 693.2 | 365 |
Accounts payable | 908.1 | 876.4 |
Accrued payroll and benefits | 199.8 | 185.4 |
Other | 550.8 | 464.8 |
Current liabilities | 3,182.7 | 3,331.7 |
Long-term liabilities | ||
Long-term debt | 11,211 | 9,994 |
Deferred income taxes | 3,769.3 | 3,388.1 |
Deferred revenue, net | 497.1 | 520.4 |
Regulatory liabilities | 3,992.8 | 4,251.6 |
Environmental remediation liabilities | 589.2 | 616.4 |
Pension and OPEB obligations | 326.2 | 422.8 |
Other | 1,128.9 | 1,108.1 |
Long-term liabilities | 21,514.5 | 20,301.4 |
Commitments and contingencies (Note 23) | ||
Common shareholders' equity | ||
Common stock – $0.01 par value; 325,000,000 shares authorized; 315,434,531 and 315,523,192 shares outstanding, respectively | 3.2 | 3.2 |
Additional paid in capital | 4,186.6 | 4,250.1 |
Retained earnings | 5,927.7 | 5,538.2 |
Accumulated other comprehensive loss | (4.1) | (2.6) |
Common shareholders' equity | 10,113.4 | 9,788.9 |
Preferred stock of subsidiary | 30.4 | 30.4 |
Noncontrolling interests | 110.8 | 23.4 |
Total liabilities and equity | $ 34,951.8 | $ 33,475.8 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Statement of Financial Position [Abstract] | ||
Accounts receivable and unbilled revenues, reserves | $ 140 | $ 149.2 |
Property, plant, and equipment, accumulated depreciation | $ 8,878.7 | $ 8,515.9 |
Common stock, par value | $ 0.01 | |
Common stock, shares authorized | 325,000,000 | |
Common stock, shares outstanding | 315,434,531 | 315,523,192 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Operating activities | |||
Net income | $ 1,134.7 | $ 1,060.5 | $ 1,204.9 |
Reconciliation to cash provided by operating activities | |||
Depreciation and amortization | 926.3 | 845.8 | 798.6 |
Deferred income taxes and investment tax credits, net | 162.9 | 297.3 | 271.7 |
Contributions and payments related to pension and OPEB plans | (65.9) | (77.6) | (120.5) |
Equity income in transmission affiliate, net of distributions | (2.9) | (18.6) | (4.8) |
Change in - | |||
Accounts receivable and unbilled revenues | 98.2 | 23.5 | (86.4) |
Materials, supplies, and inventories | (1.5) | (8.8) | 49.3 |
Other current assets | (7.1) | (10) | (7.1) |
Accounts payable | 1.5 | 110.6 | 8.5 |
Other current liabilities | 78.7 | (67.6) | 161.8 |
Other, net | 20.6 | 290.4 | (197.4) |
Net cash provided by operating activities | 2,345.5 | 2,445.5 | 2,078.6 |
Investing Activities | |||
Capital expenditures | (2,260.8) | (2,115.7) | (1,959.5) |
Acquisition of Upstream, net of cash and restricted cash acquired of $9.2 million | (268.2) | 0 | 0 |
Acquisition of Bishop Hill III, net of restricted cash acquired of $4.5 million | 0 | (162.9) | 0 |
Acquisition of Forward Wind Energy Center | 0 | (77.1) | 0 |
Acquisition of Coyote Ridge | 0 | (61.4) | 0 |
Acquisition of Bluewater | 0 | 0 | (226) |
Capital contributions to transmission affiliates | (52.6) | (53.5) | (109.6) |
Proceeds from the sale of assets and businesses | 37.6 | 12.1 | 24 |
Proceeds from the sale of investments held in rabbi trust | 0.2 | 118.6 | 8.7 |
Purchase of investments held in rabbi trust | 0 | (65) | (3.7) |
Reimbursement for ATC's construction costs | 32.4 | 0 | 0 |
Other, net | 16.5 | 20.5 | 12 |
Net cash used in investing activities | (2,494.9) | (2,384.4) | (2,254.1) |
Financing Activities | |||
Exercise of stock options | 67 | 29.1 | 30.8 |
Purchase of common stock | (140.1) | (72.4) | (71.3) |
Dividends paid on common stock | (744.5) | (697.3) | (656.5) |
Issuance of long-term debt | 1,895 | 1,740 | 435 |
Retirement of long-term debt | (360.1) | (953.3) | (154.5) |
Change in short-term debt | (609.3) | (4.5) | 584.4 |
Other, net | (22.4) | (15.2) | (6.5) |
Net cash provided by financing activities | 85.6 | 26.4 | 161.4 |
Net change in cash, cash equivalents, and restricted cash | (63.8) | 87.5 | (14.1) |
Cash, cash equivalents, and restricted cash at beginning of year | 146.1 | 58.6 | 72.7 |
Cash, cash equivalents, and restricted cash at end of year | $ 82.3 | $ 146.1 | $ 58.6 |
Consolidated Statement of Cash
Consolidated Statement of Cash Flows (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Bishop Hill III Wind Energy Center | ||
Business Acquisition [Line Items] | ||
Cash and restricted cash acquired | $ 4.5 | |
Upstream Wind Energy LLC | ||
Business Acquisition [Line Items] | ||
Cash and restricted cash acquired | $ 9.2 |
Consolidated Statements of Equi
Consolidated Statements of Equity - USD ($) $ in Millions | Total | Total Equity | Total Common Shareholders' Equity | Common Stock | Additional Paid-in Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Other Comprehensive Loss | ASU 2018-02 Cumulative Effect Adjustment | Preferred Stock of Subsidiary | Noncontrolling Interests |
Equity | |||||||||||
Cumulative effect adjustment from new accounting principle | $ 15.7 | $ 15.7 | $ 0 | $ 0 | $ 15.7 | $ 0 | $ 0 | $ 0 | |||
Balance at Dec. 31, 2016 | 8,960.2 | 8,929.8 | 3.2 | 4,309.8 | 4,613.9 | 2.9 | 30.4 | 0 | |||
Equity | |||||||||||
Net income attributed to common shareholders | $ 1,203.7 | 1,203.7 | 1,203.7 | 0 | 0 | 1,203.7 | 0 | 0 | 0 | ||
Net loss attributed to noncontrolling interests | 0 | ||||||||||
Other comprehensive loss | 0 | ||||||||||
Common stock dividends | (656.5) | (656.5) | 0 | 0 | (656.5) | 0 | 0 | 0 | |||
Exercise of stock options | 30.8 | 30.8 | 0 | 30.8 | 0 | 0 | 0 | 0 | |||
Purchase of common stock | (71.3) | (71.3) | (71.3) | 0 | (71.3) | 0 | 0 | 0 | 0 | ||
Capital contributions from noncontrolling interest | 0 | ||||||||||
Stock-based compensation and other | 9.2 | 9.2 | 0 | 9.2 | 0 | 0 | 0 | 0 | |||
Balance at Dec. 31, 2017 | 9,491.8 | 9,461.4 | 3.2 | 4,278.5 | 5,176.8 | 2.9 | 30.4 | 0 | |||
Equity | |||||||||||
Cumulative effect adjustment from new accounting principle | 0 | 0 | 0 | 0 | (0.6) | $ 0.6 | 0 | 0 | |||
Net income attributed to common shareholders | 1,059.3 | 1,059.3 | 1,059.3 | 0 | 0 | 1,059.3 | 0 | 0 | 0 | ||
Net loss attributed to noncontrolling interests | 0 | ||||||||||
Other comprehensive loss | (5.5) | (6.1) | (6.1) | 0 | 0 | 0 | $ (6.1) | 0 | 0 | ||
Common stock dividends | (697.3) | (697.3) | 0 | 0 | (697.3) | 0 | 0 | 0 | |||
Exercise of stock options | 29.1 | 29.1 | 0 | 29.1 | 0 | 0 | 0 | 0 | |||
Purchase of common stock | (72.4) | (72.4) | (72.4) | 0 | (72.4) | 0 | 0 | 0 | 0 | ||
Acquisition of noncontrolling interests | 23.8 | 0 | 0 | 0 | 0 | 0 | 0 | 23.8 | |||
Capital contributions from noncontrolling interest | 0 | ||||||||||
Stock-based compensation and other | 14.5 | 14.9 | 0 | 14.9 | 0 | 0 | 0 | (0.4) | |||
Balance at Dec. 31, 2018 | 9,842.7 | 9,788.9 | 3.2 | 4,250.1 | 5,538.2 | (2.6) | 30.4 | 23.4 | |||
Equity | |||||||||||
Net income attributed to common shareholders | 1,134 | 1,134 | 1,134 | 0 | 0 | 1,134 | 0 | 0 | 0 | ||
Net loss attributed to noncontrolling interests | 0.5 | (0.5) | 0 | 0 | 0 | 0 | 0 | 0 | (0.5) | ||
Other comprehensive loss | (1.5) | (1.5) | (1.5) | 0 | 0 | 0 | (1.5) | 0 | 0 | ||
Common stock dividends | (744.5) | (744.5) | 0 | 0 | (744.5) | 0 | 0 | 0 | |||
Exercise of stock options | 67 | 67 | 0 | 67 | 0 | 0 | 0 | 0 | |||
Purchase of common stock | (140.1) | (140.1) | (140.1) | 0 | (140.1) | 0 | 0 | 0 | 0 | ||
Acquisition of noncontrolling interests | 69 | 0 | 0 | 0 | 0 | 0 | 0 | 69 | |||
Capital contributions from noncontrolling interest | $ 21 | 21 | 0 | 0 | 0 | 0 | 0 | 0 | 21 | ||
Distributions to noncontrolling interests | (2.1) | 0 | 0 | 0 | 0 | 0 | 0 | (2.1) | |||
Stock-based compensation and other | 9.6 | 9.6 | 0 | 9.6 | 0 | 0 | 0 | 0 | |||
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 |
Consolidated Statements of Eq_2
Consolidated Statements of Equity (Parenthetical) - $ / shares | 3 Months Ended | 12 Months Ended | |||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Statement of Stockholders' Equity [Abstract] | |||||||
Dividends per share (in dollars per share) | $ 0.59 | $ 0.59 | $ 0.59 | $ 0.59 | $ 2.36 | $ 2.21 | $ 2.08 |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2019 | |
Accounting Policies [Abstract] | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (a) Nature of Operations —WEC Energy Group serves approximately 1.6 million electric customers and 2.9 million natural gas customers, and owns approximately 60% of ATC. As used in these notes, the term "financial statements" refers to the consolidated financial statements. This includes the income statements, statements of comprehensive income, balance sheets, statements of cash flows, and statements of equity, unless otherwise noted. On our financial statements, we consolidate our majority-owned subsidiaries 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 sheet as of December 31, 2019 related to the minority interests at Bishop Hill III, Coyote Ridge, and Upstream held by third parties. Our financial statements include the accounts of WEC Energy Group, a diversified energy holding company, and the accounts of our subsidiaries in the following reportable segments: • Wisconsin segment – Consists of WE, WPS, and WG, which are engaged primarily in the generation of electricity and the distribution of electricity and natural gas in Wisconsin; and UMERC, which generates electricity and distributes electricity and natural gas to customers located in the Upper Peninsula of Michigan. • Illinois segment – Consists of PGL and NSG, which are engaged primarily in the distribution of natural gas in Illinois. • Other states segment – Consists of MERC and MGU, which are engaged primarily in the distribution of natural gas in Minnesota and Michigan, respectively. • Electric transmission segment – Consists of our approximate 60% ownership interest in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions, and our approximate 75% ownership interest in ATC Holdco, which invests in transmission-related projects outside of ATC's traditional footprint. • Non-utility energy infrastructure segment – Consists of We Power, which is principally engaged in the ownership of electric power generating facilities for long-term lease to WE, and Bluewater, which owns underground natural gas storage facilities in Michigan. WECI, which holds our ownership interests in several wind generating facilities, is also included in this segment. See Note 2, Acquisitions, for more information on Bluewater and the WECI wind generating facilities. • Corporate and other segment – Consists of the WEC Energy Group holding company, the Integrys holding company, the PELLC holding company, Wispark, Bostco, Wisvest, WECC, WBS, and PDL. In the first quarter of 2017, we sold substantially all of the remaining assets of Bostco, and, in October 2018, Bostco was dissolved. In 2019, we sold certain PDL solar power generating facilities. See Note 3, Dispositions, for more information on these sales. Investments in companies not controlled by us, but over which we have significant influence regarding the operating and financial policies of the investee, are accounted for using the equity method. We use the cumulative earnings approach for classifying distributions received in the statements of cash flows. Under the cumulative earnings approach, we compare the distributions received to cumulative equity method earnings since inception. Any distributions received up to the amount of cumulative equity earnings are considered a return on investment and classified in operating activities. Any excess distributions are considered a return of investment and classified in investing activities. Our financial statements also reflect our proportionate interests in certain jointly owned utility facilities. See Note 7, Jointly Owned Utility Facilities, for more information (b) Basis of Presentation —We prepare our financial statements in conformity with GAAP. We make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates. (c) Cash and Cash Equivalents —Cash and cash equivalents include marketable debt securities with an original maturity of three months or less. (d) Operating Revenues —The following discussion includes our significant accounting policies related to operating revenues. For additional required disclosures on disaggregation of operating revenues, see Note 4, Operating Revenues . Revenues from Contracts with Customers Electric Utility Operating Revenues Electricity sales to residential and commercial and industrial customers are generally accomplished through requirements contracts, which provide for the delivery of as much electricity as the customer needs. These contracts represent discrete deliveries of electricity and consist of one distinct performance obligation satisfied over time, as the electricity is delivered and consumed by the customer simultaneously. For our Wisconsin residential and commercial and industrial customers and the majority of our Michigan residential and commercial and industrial customers, our performance obligation is bundled to consist of both the sale and the delivery of the electric commodity. In our Michigan service territory, a limited number of residential and commercial and industrial customers can purchase the commodity from a third party. In this case, the delivery of the electricity represents our sole performance obligation. The transaction price of the performance obligations for residential and commercial and industrial customers is valued using the rates, charges, terms, and conditions of service included in the tariffs of our regulated electric utilities, which have been approved by state regulators. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on the quantity of electricity delivered each month. Our retail electric rates in Wisconsin include base amounts for fuel and purchased power costs, which also impact our revenues. The electric fuel rules set by the PSCW allow us to defer, for subsequent rate recovery or refund, under- or over-collections of actual fuel and purchased power costs that exceed a 2% price variance from the costs included in the rates charged to customers. Our electric utilities monitor the deferral of under-collected costs to ensure that it does not cause them to earn a greater ROE than authorized by the PSCW. In contrast, the rates of our Michigan retail electric customers include recovery of fuel and purchased power costs on a one-for-one basis. In addition, the Wisconsin residential tariffs of WE and WPS include a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. Wholesale customers who resell power can choose to either bundle capacity and electricity services together under one contract with a supplier or purchase capacity and electricity separately from multiple suppliers. Furthermore, wholesale customers can choose to have our utilities provide generation to match the customer's load, similar to requirements contracts, or they can purchase specified quantities of electricity and capacity. Contracts with wholesale customers that include capacity bundled with the delivery of electricity contain two performance obligations, as capacity and electricity are often transacted separately in the marketplace at the wholesale level. When recognizing revenue associated with these contracts, the transaction price is allocated to each performance obligation based on its relative standalone selling price. Revenue is recognized as control of each individual component is transferred to the customer. Electricity is the primary product sold by our electric utilities and represents a single performance obligation satisfied over time through discrete deliveries to a customer. Revenue from electricity sales is generally recognized as units are produced and delivered to the customer within the production month. Capacity represents the reservation of an electric generating facility and conveys the ability to call on a plant to produce electricity when needed by the customer. The nature of our performance obligation as it relates to capacity is to stand ready to deliver power. This represents a single performance obligation transferred over time, which generally represents a monthly obligation. Accordingly, capacity revenue is recognized on a monthly basis. The transaction price of the performance obligations for wholesale customers is valued using the rates, charges, terms, and conditions of service, which have been approved by the FERC. These wholesale rates include recovery of fuel and purchased power costs from customers on a one-for-one basis. For the majority of our wholesale customers, the price billed for energy and capacity is a formula-based rate. Formula-based rates initially set a customer's current year rates based on the previous year’s expenses. This is a predetermined formula derived from the utility's costs and a reasonable rate of return. Because these rates are eventually trued up to reflect actual, current-year costs, they represent a form of variable consideration in certain circumstances. The variable consideration is estimated and recognized over time as wholesale customers receive and consume the capacity and electricity services. We are an active participant in the MISO Energy Markets, where we bid our generation into the Day Ahead and Real Time markets and procure electricity for our retail and wholesale customers at prices determined by the MISO Energy Markets. Purchase and sale transactions are recorded using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded as purchased power in cost of sales and net sales in a single hour are recorded as resale revenues on our income statements. For resale revenues, our performance obligation is created only when electricity is sold into the MISO Energy Markets. For all of our customers, consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days . Natural Gas Utility Operating Revenues We recognize natural gas utility operating revenues under requirements contracts with residential, commercial and industrial, and transportation customers served under the tariffs of our regulated utilities. Tariffs provide our customers with the standard terms and conditions, including rates, related to the services offered. Requirements contracts provide for the delivery of as much natural gas as the customer needs. These requirements contracts represent discrete deliveries of natural gas and constitute a single performance obligation satisfied over time. Our performance obligation is both created and satisfied with the transfer of control of natural gas upon delivery to the customer. For most of our customers, natural gas is delivered and consumed by the customer simultaneously. A performance obligation can be bundled to consist of both the sale and the delivery of the natural gas commodity. In certain of our service territories, customers can purchase the commodity from a third party. In this case, the performance obligation only includes the delivery of the natural gas to the customer. The transaction price of the performance obligations for our natural gas customers is valued using the rates, charges, terms, and conditions of service included in the tariffs of our regulated utilities, which have been approved by state regulators. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on natural gas delivered each month. The tariffs of our natural gas utilities include various rate mechanisms that allow them to recover or refund changes in prudently incurred costs from rate case-approved amounts. The rates for all of our natural gas utilities include one-for-one recovery mechanisms for natural gas commodity costs. We defer any difference between actual natural gas costs incurred and costs recovered through rates as a current asset or liability. The deferred balance is returned to or recovered from customers at intervals throughout the year. In addition, the rates of PGL and NSG, and the residential tariffs of WE, WPS, and WG, include riders or other mechanisms for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. The rates of PGL and NSG include riders for cost recovery of both environmental cleanup costs, energy conservation and management program costs, and income tax expense changes resulting from the Tax Legislation. Finally, PGL's rates include a cost recovery mechanism for SMP costs, and similarly, MERC's rates include a rider to recover costs incurred to replace or modify natural gas facilities. Consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days . Other Natural Gas Operating Revenues We have other natural gas operating revenues from Bluewater, which is in our non-utility energy infrastructure segment. Bluewater has entered into long-term service agreements for natural gas storage services with WE, WPS, and WG, and provides service to several unaffiliated customers. All amounts associated with services from affiliates have been eliminated at the consolidated level. Other Non-Utility Operating Revenues 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 deferred revenue, and we continually amortize the deferred carrying costs to revenues over the life of the related lease term that We Power has with WE. During 2019 and 2018, we recorded $25.4 million and $25.3 million , respectively, of revenue related to these deferred carrying costs, which were included in the contract liability balance at the beginning of the period. This contract liability is presented as deferred revenue, net on our balance sheets. Non-utility operating revenues are also derived from servicing appliances for customers at MERC. These contracts customarily have a duration of one year or less and consist of a single performance obligation satisfied over time. We use a time-based output method to recognize revenues monthly for the service fee. Revenues from distributed renewable solar projects consist primarily of sales of renewable energy and SRECs generated by PDL. The sale of SRECs is a distinct performance obligation as they are often sold separately from the renewable energy generated. Although the performance obligation for the sale of renewable energy is recognized over time and the performance obligation for SRECs is recognized at a point-in-time, the timing of revenue recognition is the same, as the generation of renewable energy and sales of SREC's occur concurrently. See Note 3, Dispositions, for more information on the sale of certain of these solar facilities. Wind generation revenues from WECI's ownership interests in wind generation facilities continued to grow with the acquisition of Upstream in January 2019. See Note 2, Acquisitions, for more information on Upstream, the December 2018 acquisition of Coyote Ridge, and other planned future acquisitions. Most of these wind generation facilities have offtake agreements with unaffiliated third parties for all of the energy to be produced by the facility. The contracts consist of one distinct performance obligation satisfied over time, as the electricity is delivered and consumed by the customer simultaneously. We recognize revenue as energy is produced and delivered to the customer within the production month. Upstream's revenue is substantially fixed over 10 years through an agreement with an unaffiliated third party. Other Operating Revenues Alternative Revenues Alternative revenues are created from programs authorized by regulators that allow our utilities to record additional revenues by adjusting rates in the future, usually as a surcharge applied to future billings, in response to past activities or completed events. Alternative revenue programs allow compensation for the effects of weather abnormalities, other external factors, or demand side management initiatives. Alternative revenue programs can also provide incentive awards if the utility achieves certain objectives and in other limited circumstances. We record alternative revenues when the regulator-specified conditions for recognition have been met. We reverse these alternative revenues as the customer is billed, at which time this revenue is presented as revenues from contracts with customers. Below is a summary of the alternative revenue programs at our utilities: • The rates of PGL, NSG, and MERC include decoupling mechanisms. These mechanisms differ by state and allow the utilities to recover or refund the differences between actual and authorized margins for certain customer classes. See Note 25, Regulatory Environment, for more information . • MERC’s rates include a conservation improvement program rider, which includes a financial incentive for meeting energy savings goals. • WE and WPS provide wholesale electric service to customers under market-based rates and FERC formula rates. The customer is charged a base rate each year based upon a formula using prior year actual costs and customer demand. A true-up is calculated based on the difference between the amount billed to customers for the demand component of their rates and what the actual cost of service was for the year. The true-up can result in an amount that we will recover from or refund to the customer. We consider the true-up portion of the wholesale electric revenues to be alternative revenues. (e) Materials, Supplies, and Inventories —Our inventory as of December 31 consisted of: (in millions) 2019 2018 Materials and supplies $ 234.2 $ 226.6 Natural gas in storage 227.7 232.9 Fossil fuel 87.9 88.7 Total $ 549.8 $ 548.2 PGL and NSG price natural gas storage injections at the calendar year average of the costs of natural gas supply purchased. Withdrawals from storage are priced on the LIFO cost method. Inventories stated on a LIFO basis represented approximately 19% and 16% of total inventories at December 31, 2019 and 2018 , respectively. The estimated replacement cost of natural gas in inventory at December 31, 2019 and 2018 , exceeded the LIFO cost by $9.8 million and $72.4 million , respectively. In calculating these replacement amounts, PGL and NSG used a Chicago city-gate natural gas price per Dth of $1.95 at December 31, 2019 , and $3.08 at December 31, 2018 . Substantially all other materials and supplies, natural gas in storage, and fossil fuel inventories are recorded using the weighted-average cost method of accounting. (f) Regulatory Assets and Liabilities —The economic effects of regulation can result in regulated companies recording costs and revenues that are allowed in the rate-making process in a period different from the period they would have been recognized by a nonregulated company. When this occurs, regulatory assets and regulatory liabilities are recorded on the balance sheet. Regulatory assets represent deferred costs probable of recovery from customers that would have otherwise been charged to expense. Regulatory liabilities represent amounts that are expected to be refunded to customers in future rates or future costs already collected from customers in rates. The recovery or refund of regulatory assets and liabilities is based on specific periods determined by our regulators or occurs over the normal operating period of the related assets and liabilities. If a previously recorded regulatory asset is no longer probable of recovery, the regulatory asset is reduced to the amount considered probable of recovery, and the reduction is charged to expense in the current period. See Note 5, Regulatory Assets and Liabilities, for more information . (g) Property, Plant, and Equipment —We record property, plant, and equipment at cost. Cost includes material, labor, overhead, and both debt and equity components of AFUDC. Additions to and significant replacements of property are charged to property, plant, and equipment at cost; minor items are charged to other operation and maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired. We record straight-line depreciation expense over the estimated useful life of utility property using depreciation rates approved by the applicable regulators. Annual utility composite depreciation rates are shown below: Annual Utility Composite Depreciation Rates 2019 2018 2017 WE 3.11% 3.18% 2.95% WPS 2.44% 2.50% 2.55% WG 2.29% 2.30% 2.30% PGL 3.20% 3.25% 3.29% NSG 2.48% 2.45% 2.43% MERC * 2.33% 1.95% 2.51% MGU 2.54% 2.61% 2.61% UMERC 2.87% 2.50% 2.46% * The 2018 rate reflects the impact of a new depreciation study approved by the MPUC in May 2018. The rates approved were effective retroactive to January 2017. An approximate $1.4 million reduction in depreciation expense was recorded in 2018 related to this depreciation study. We depreciate our We Power assets over the estimated useful life of the various property components. The components have useful lives of between 10 to 45 years for PWGS 1 and PWGS 2 and 10 to 55 years for ER 1 and ER 2. We capitalize certain costs related to software developed or obtained for internal use and record these costs to amortization expense over the estimated useful life of the related software, which ranges from 3 to 15 years. If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statement. Third parties reimburse the utilities for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs are recorded as a reduction to property, plant, and equipment. See Note 6, Property, Plant, and Equipment, for more information . (h) Allowance for Funds Used During Construction —AFUDC is included in utility plant accounts and represents the cost of borrowed funds (AFUDC – Debt) used during plant construction, and a return on shareholders' capital (AFUDC – Equity) used for construction purposes. AFUDC – Debt is recorded as a reduction of interest expense, and AFUDC – Equity is recorded in other income, net. The majority of AFUDC is recorded at WE, WPS, WBS, WG, and UMERC. Approximately 50% of WE's, WPS's, WG's, UMERC's, and WBS's retail jurisdictional CWIP expenditures are subject to the AFUDC calculation. The AFUDC calculation for WBS uses the WPS AFUDC retail rate, while our other utilities' AFUDC rates are determined by their respective state commissions, each with specific requirements. Based on these requirements, the other utilities did not record significant AFUDC for 2019 , 2018 , or 2017 . Average AFUDC rates are shown below: 2019 Average AFUDC Retail Rate Average AFUDC Wholesale Rate WE 8.45% 5.11% WPS 7.72% 2.58% WG 8.33% N/A UMERC 6.28% N/A WBS 7.72% N/A Our regulated utilities and WBS recorded the following AFUDC for the years ended December 31: (in millions) 2019 2018 2017 AFUDC – Debt WE $ 1.5 $ 1.5 $ 1.2 WPS 2.4 1.9 1.6 WG 0.5 0.2 0.3 UMERC 1.3 2.4 0.1 WBS 0.1 0.2 1.1 Other 0.1 0.7 0.6 Total AFUDC – Debt $ 5.9 $ 6.9 $ 4.9 AFUDC – Equity WE $ 3.7 $ 3.9 $ 3.1 WPS 5.7 4.6 4.1 WG 1.3 0.6 0.9 UMERC 3.3 5.4 0.2 WBS 0.2 0.6 3.0 Other 0.2 0.1 0.1 Total AFUDC – Equity $ 14.4 $ 15.2 $ 11.4 (i) Cloud Computing Hosting Arrangements that are Service Contracts —We have entered into several cloud computing arrangements that are hosted service contracts as part of projects related to the continuous transformation of technology. These projects include, among other things, developing a centralized repository for data to improve analytics and reporting, targeted ERP systems, a project management tool, and a power generation employee scheduling system. We present prepaid hosting fees that are service contracts in either prepayments or other long-term assets on our balance sheets and amortize them as the hosting services are received. Amortization expense, as well as the fees associated with the hosting arrangements, is recorded in other operation and maintenance expense on our income statements. As of January 1, 2020, we started capitalizing implementation costs related to cloud computing arrangements that are hosted service contracts. We will amortize the implementation costs on a straight-line basis over the cloud computing service arrangement term once the component of the hosted service is ready for its intended use. The presentation of these costs, along with the related amortization, will follow the prepaid hosting fees. (j) Asset Impairment —Goodwill and other intangible assets with indefinite lives are subject to an annual impairment test. Interim impairment tests are performed when impairment indicators are present. Our reporting units containing goodwill perform annual goodwill impairment tests during the third quarter of each year. The carrying amount of the reporting unit's goodwill is considered not recoverable if the carrying amount of the reporting unit exceeds the reporting unit's fair value. An impairment loss is recorded for the excess of the carrying amount of the goodwill over its implied fair value. See Note 9, Goodwill, for more information . Intangible assets with definite lives are reviewed for impairment on a quarterly basis. We periodically assess the recoverability of certain long-lived assets when factors indicate the carrying value of such assets may be impaired or such assets are planned to be sold. These assessments require significant assumptions and judgments by management. The long-lived assets assessed for impairment generally include certain assets within regulated operations that may not be fully recovered from our customers as a result of regulatory decisions that will be made in the future, as well as assets within nonregulated operations that are proposed to be sold or are currently generating operating losses. An impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds the fair value of the asset. The carrying amount of an asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. An impairment loss is measured as the excess of the carrying amount of the asset in comparison to the fair value of the asset. When it becomes probable that a generating unit will be retired before the end of its useful life, we assess whether the generating unit meets the criteria for abandonment accounting. Generating units that are considered probable of abandonment are expected to cease operations in the near term, significantly before the end of their original estimated useful lives. If a generating unit meets the applicable criteria to be considered probable of abandonment, and the unit has been abandoned, we assess the likelihood of recovery of the remaining net book value of that generating unit at the end of each reporting period. If it becomes probable that regulators will disallow full recovery as well as a return on the remaining net book value of a generating unit that is either abandoned or probable of being abandoned, an impairment loss may be required. An impairment loss would be recorded if the remaining net book value of the generating unit is greater than the present value of the amount expected to be recovered from ratepayers. See Note 6, Property, Plant, and Equipment, for more information . The carrying amounts of equity method investments are assessed for impairment by comparing the fair values of these investments to their carrying amounts if a fair value assessment was completed or by reviewing for the presence of impairment indicators. If an impairment exists, and it is determined to be other-than-temporary, an impairment loss is recognized equal to the amount by which the carrying amount exceeds the investment's fair value. (k) Asset Retirement Obligations —We recognize, at fair value, legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and normal operation of the assets. An ARO liability is recorded, when incurred, for these obligations as long as the fair value can be reasonably estimated, even if the timing or method of settling the obligation is unknown. The associated retirement costs are capitalized as part of the related long-lived asset and are depreciated over the useful life of the asset. The ARO liabilities are accreted each period using the credit-adjusted risk-free interest rates associated with the expected settlement dates of the AROs. These rates are determined when the obligations are incurred. Subsequent changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or a decrease to the carrying amount of the liability and the associated capitalized retirement costs. For our regulated entities, we recognize regulatory assets or liabilities for the timing differences between when we recover an ARO in rates and when we recognize the associated retirement costs. See Note 8, Asset Retirement Obligations, for more information . (l) Stock-Based Compensation —In accordance with the shareholder approved Omnibus Stock Incentive Plan, we provide long-term incentives through our equity interests to our non-employee directors, officers, and other key employees. The plan provides for the granting of stock options, restricted stock, performance shares, and other stock-based awards. Awards may be paid in common stock, cash, or a combination thereof. The number of shares of common stock authorized for issuance under the plan is 34.3 million . We recognize stock-based compensation expense on a straight-line basis over the requisite service period. Awards classified as equity awards are measured based on their grant-date fair value. Awards classified as liability awards are recorded at fair value each reporting period. In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which modified certain aspects of the accounting for stock-based compensation awards. This ASU became effective for us on January 1, 2017. Under the new guidance, all excess tax benefits and tax deficiencies are recognized as income tax expense or benefit in the income statement on a prospective basis. Prior to January 1, 2017, these amounts were recorded in additional paid in capital on the balance sheet, and excess tax benefits could only be recognized to the extent they reduced taxes payable. In the first quarter of 2017, we recorded a $15.7 million cumulative-effect adjustment to increase retained earnings for excess tax benefits that had not been recognized in prior years as they did not reduce taxes payable. As allowed under this ASU, we have elected to account for forfeitures as they occur, rather than estimating potential future forfeitures and recording them over the vesting period. Stock Options We grant non-qualified stock options that generally vest on a cliff-basis after three years . The exercise price of a stock option under the plan cannot be less than 100% of our common stock's fair market value on the grant date. Historically, all stock options have been granted with an exercise price equal to the fair market value of our common stock on the date of the grant. Options vest immediately upon retirement, death, or disability; however, they may not be exercised within six months of the gra |
Acquisitions
Acquisitions | 12 Months Ended |
Dec. 31, 2019 | |
Business Combinations [Abstract] | |
ACQUISITIONS | ACQUISITIONS On January 1, 2018, we adopted ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (ASU 2017-01). The amendments in this update clarify the definition of a business and provide guidance on evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 also clarifies that transaction costs are capitalized in an asset acquisition but expensed in a business combination. 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 production tax credits and 100% bonus depreciation. The transaction is subject to FERC approval and commercial operation is expected to begin at the end of 2020, at which time the transaction is expected to close. Thunderhead will be included in the non-utility energy infrastructure segment. In January 2019, WECI completed the acquisition of an 80% ownership interest in Upstream, a commercially operational 202.5 MW wind generating facility, for $268.2 million , which included transaction costs and is net of cash and restricted cash acquired of $9.2 million . In February 2020, WECI signed an agreement to acquire an additional 10% ownership interest in Upstream for $31 million . Upstream is located in Antelope County, Nebraska and supplies energy to the Southwest Power Pool. Upstream's revenue will be substantially fixed over 10 years through an agreement with an unaffiliated third party. Under the Tax Legislation, WECI's investment in Upstream qualifies for production tax credits and 100% bonus depreciation. Upstream is included in the non-utility energy infrastructure segment. The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition. (in millions) Current assets $ 1.5 Net property, plant, and equipment 341.6 Other long-term assets * 22.9 Current liabilities (4.6 ) Long-term liabilities (15.0 ) Noncontrolling interest (69.0 ) Total purchase price $ 277.4 * Includes $8.1 million of restricted cash. Acquisition of a Wind Generation Facility in South Dakota In December 2018, WECI acquired an 80% ownership interest in Coyote Ridge, a 96.7 MW wind generating facility located in Brookings County, South Dakota, for $61.4 million , which included transaction costs. In December 2019, Coyote Ridge achieved commercial operation and WECI made an additional investment of $84.0 million related to capital expenditures for the project for a total investment of $145.4 million . The project has an offtake agreement with an unaffiliated third party for all of the energy produced for 12 years . Under the Tax Legislation, WECI's investment in Coyote Ridge qualifies for production tax credits and 100% bonus depreciation. 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. Coyote Ridge is included in the non-utility energy infrastructure segment. The table below shows the allocation of the purchase price to the assets acquired at the date of the acquisition. (in millions) Net property, plant, and equipment $ 66.4 Noncontrolling interest (5.0 ) Total purchase price $ 61.4 Acquisition of Wind Generation Facilities in Illinois In January 2020, WECI signed an agreement to acquire an 80% ownership interest in Blooming Grove, a 250 MW wind generating facility under construction in McLean County, Illinois, for a total investment of approximately $345 million . In February 2020, WECI agreed to acquire an additional 10% ownership interest in Blooming Grove for $44 million . Blooming Grove has long-term offtake agreements for all the energy produced with affiliates of two investment grade multinational companies. Under the Tax Legislation, WECI's investment in Blooming Grove is expected to qualify for production tax credits and 100% bonus depreciation. The transaction is subject to FERC approval and commercial operation is expected to begin by the end of 2020, at which time the transaction is expected to close. In addition to the customary covenants and closing conditions contained in the agreement, if Blooming Grove does not achieve commercial operation by the end of 2020 and any related potential adverse consequences are not otherwise mitigated, we may terminate the agreement in our sole discretion. Blooming Grove will be included in the non-utility energy infrastructure segment. In August 2018, WECI completed the acquisition of an 80% ownership interest in Bishop Hill III, a 132.1 MW wind generating facility located in Henry County, Illinois, known as Bishop Hill III, for $144.7 million , which includes transaction costs and is net of restricted cash acquired of $4.5 million . In December 2018, WECI completed the acquisition of an additional 10% ownership interest in Bishop Hill III for $18.2 million . Bishop Hill III has an offtake agreement with an unaffiliated company for the sale of all of the energy produced by the facility for 22 years . Under the Tax Legislation, WECI's investment in Bishop Hill III qualifies for production tax credits and 100% bonus depreciation. Bishop Hill III is included in the non-utility energy infrastructure segment. The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition. (in millions) Current assets $ 1.4 Net property, plant, and equipment 190.2 Other long-term assets * 4.5 Current liabilities (1.6 ) Long-term liabilities (8.3 ) Noncontrolling interest (18.8 ) Total purchase price $ 167.4 * Represents restricted cash. Acquisition of a Wind Generation Facility in Wisconsin In April 2018, WPS, along with two unaffiliated utilities, completed the purchase of Forward Wind Energy Center, which consists of 86 wind turbines located in Wisconsin with a total capacity of 138 MW. The aggregate purchase price was $172.9 million of which WPS’s proportionate share was 44.6% , or $77.1 million . In addition, WPS incurred $1.9 million of transaction costs that were recorded as a regulatory asset. Since 2008 and up until the acquisition, WPS purchased 44.6% of the facility’s energy output under a power purchase agreement. The table below shows the allocation of the purchase price to the assets acquired at the date of the acquisition, which are included in rate base. (in millions) Current assets $ 0.2 Net property, plant, and equipment 76.9 Total purchase price $ 77.1 Under a joint ownership agreement with the two other utilities, WPS is entitled to its share of generating capability and output of the facility equal to its ownership interest. WPS is also paying its ownership share of additional capital expenditures and operating expenses. Forward Wind Energy Center is included in the Wisconsin segment. Acquisition of Natural Gas Storage Facilities in Michigan In June 2017, we completed the acquisition of Bluewater for $226.0 million . Bluewater owns natural gas storage facilities in Michigan that provide approximately one-third of the current storage needs for our Wisconsin natural gas utilities. The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition. The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. Bluewater is included in the non-utility energy infrastructure segment. (in millions) Current assets $ 2.0 Net property, plant, and equipment 217.6 Goodwill 7.3 Current liabilities (0.9 ) Total purchase price $ 226.0 |
Dispositions
Dispositions | 12 Months Ended |
Dec. 31, 2019 | |
Discontinued Operations and Disposal Groups [Abstract] | |
DISPOSITIONS | DISPOSITIONS Corporate and Other Segment Sale of Certain WPS Power Development, LLC Solar Power Generation Facilities In 2019, we sold four solar power generation facilities owned by PDL for $26.3 million . These solar facilities were located in Massachusetts. In 2019, we recorded an after-tax gain on the sales of $6.5 million primarily related to the recognition of deferred investment tax credits, which were included as a reduction of income tax expense on our income statements. The assets included in the sales were not material and, therefore, were not presented as held for sale. The results of operations of these facilities remained in continuing operations through the sale dates as the sales did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results. Sale of Bostco LLC Real Estate Holdings In March 2017, we sold the remaining real estate holdings of Bostco located in downtown Milwaukee, Wisconsin, which included retail, office, and residential space, and in October 2018, Bostco was dissolved. During the first quarter of 2017, we recorded an insignificant gain on the sale, which was included in other income, net on our income statements. The assets included in the sale were not material and, therefore, were not presented as held for sale. The results of operations associated with these assets remained in continuing operations through the sale date as the sale did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results. |
Operating Revenues
Operating Revenues | 12 Months Ended |
Dec. 31, 2019 | |
Revenue from Contract with Customer [Abstract] | |
OPERATING REVENUES | OPERATING REVENUES For more information about our significant accounting policies related to operating revenues, see Note 1(d), Operating Revenues . Disaggregation of Operating Revenues The following tables present our operating revenues disaggregated by revenue source. We 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 are impacted by regulatory activities within their jurisdictions. Comparable amounts have not been presented for the year ended December 31, 2017, due to our adoption of ASU 2014-09, Revenues from Contracts with Customers, under the modified retrospective method. (in millions) Wisconsin Illinois Other States Total Utility Operations Non-Utility Energy Infrastructure Corporate and Other Reconciling Eliminations WEC Energy Group Consolidated Year ended December 31, 2019 Electric $ 4,307.7 $ — $ — $ 4,307.7 $ — $ — $ — $ 4,307.7 Natural gas 1,324.1 1,332.4 411.6 3,068.1 47.4 — (44.1 ) 3,071.4 Total regulated revenues 5,631.8 1,332.4 411.6 7,375.8 47.4 — (44.1 ) 7,379.1 Other non-utility revenues — 0.1 16.6 16.7 55.2 4.0 (5.7 ) 70.2 Total revenues from contracts with customers 5,631.8 1,332.5 428.2 7,392.5 102.6 4.0 (49.8 ) 7,449.3 Other operating revenues 15.3 24.6 (2.2 ) 37.7 393.3 0.4 (357.6 ) 73.8 Total operating revenues $ 5,647.1 $ 1,357.1 $ 426.0 $ 7,430.2 $ 495.9 $ 4.4 $ (407.4 ) $ 7,523.1 (in millions) Wisconsin Illinois Other States Total Utility Operations Non-Utility Energy Infrastructure Corporate and Other Reconciling Eliminations WEC Energy Group Consolidated Year ended December 31, 2018 Electric $ 4,432.4 $ — $ — $ 4,432.4 $ — $ — $ — $ 4,432.4 Natural gas 1,350.6 1,406.9 428.4 3,185.9 45.4 — (36.4 ) 3,194.9 Total regulated revenues 5,783.0 1,406.9 428.4 7,618.3 45.4 — (36.4 ) 7,627.3 Other non-utility revenues — 0.2 16.1 16.3 34.6 7.9 (5.8 ) 53.0 Total revenues from contracts with customers 5,783.0 1,407.1 444.5 7,634.6 80.0 7.9 (42.2 ) 7,680.3 Other operating revenues 11.7 (7.1 ) (6.3 ) (1.7 ) 388.4 0.8 (388.3 ) (0.8 ) Total operating revenues $ 5,794.7 $ 1,400.0 $ 438.2 $ 7,632.9 $ 468.4 $ 8.7 $ (430.5 ) $ 7,679.5 Revenues from Contracts with Customers Electric Utility Operating Revenues The following table disaggregates electric utility operating revenues into customer class: Electric Utility Operating Revenues Year Ended December 31 (in millions) 2019 2018 Residential $ 1,608.6 $ 1,636.3 Small commercial and industrial 1,384.6 1,408.6 Large commercial and industrial 871.9 912.2 Other 29.6 29.9 Total retail revenues 3,894.7 3,987.0 Wholesale 189.5 210.1 Resale 163.1 192.2 Steam 23.3 24.1 Other utility revenues 37.1 19.0 Total electric utility operating revenues $ 4,307.7 $ 4,432.4 Natural Gas Utility Operating Revenues The following tables disaggregate natural gas utility operating revenues into customer class: (in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues Year Ended December 31, 2019 Residential $ 837.9 $ 857.8 $ 258.2 $ 1,953.9 Commercial and industrial 419.9 261.7 148.7 830.3 Total retail revenues 1,257.8 1,119.5 406.9 2,784.2 Transport 72.6 245.3 31.6 349.5 Other utility revenues * (6.3 ) (32.4 ) (26.9 ) (65.6 ) Total natural gas utility operating revenues $ 1,324.1 $ 1,332.4 $ 411.6 $ 3,068.1 (in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues Year Ended December 31, 2018 Residential $ 834.5 $ 877.5 $ 263.3 $ 1,975.3 Commercial and industrial 436.7 266.9 140.0 843.6 Total retail revenues 1,271.2 1,144.4 403.3 2,818.9 Transport 70.8 244.1 31.8 346.7 Other utility revenues * 8.6 18.4 (6.7 ) 20.3 Total natural gas utility operating revenues $ 1,350.6 $ 1,406.9 $ 428.4 $ 3,185.9 * Includes amounts collected from (refunded to) customers for purchased gas adjustment costs. Other Non-Utility Operating Revenues Other non-utility operating revenues consist primarily of the following: Year Ended December 31 (in millions) 2019 2018 We Power revenues $ 25.4 $ 25.3 Wind generation revenues 24.0 3.6 Appliance service revenues 16.6 15.9 Distributed renewable solar project revenues 4.0 8.0 Other 0.2 0.2 Total other non-utility operating revenues $ 70.2 $ 53.0 Other Operating Revenues Other operating revenues consist primarily of the following: Year Ended December 31 (in millions) 2019 2018 Late payment charges $ 43.7 $ 40.3 Alternative revenues * (9.6 ) (45.6 ) Other 39.7 4.5 Total other operating revenues $ 73.8 $ (0.8 ) * Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. Negative amounts can also result from revenues to be refunded to customers subject to decoupling mechanisms and wholesale true-ups, as discussed in Note 1(d), Operating Revenues . |
Regulatory Assets and Liabiliti
Regulatory Assets and Liabilities | 12 Months Ended |
Dec. 31, 2019 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
REGULATORY ASSETS AND LIABILITIES | REGULATORY ASSETS AND LIABILITIES The following regulatory assets were reflected on our balance sheets as of December 31: (in millions) 2019 2018 See Note Regulatory assets (1) (2) Pension and OPEB costs (3) $ 1,066.6 $ 1,193.5 19 Plant retirements (4) 856.4 832.3 6 Environmental remediation costs (5) 685.5 687.1 23 Income tax related items (6) 457.8 369.1 15 SSR (7) 151.5 316.7 25 AROs 137.5 185.4 8 Uncollectible expense (8) 52.2 38.7 1(d) Derivatives 33.8 17.8 1(q) We Power generation (9) 25.8 43.0 Electric transmission costs 0.3 58.1 25 Other, net 60.2 114.1 Total regulatory assets $ 3,527.6 $ 3,855.8 Balance sheet presentation Other current assets $ 20.9 $ 50.7 Regulatory assets 3,506.7 3,805.1 Total regulatory assets $ 3,527.6 $ 3,855.8 (1) Based on prior and current rate treatment, we believe it is probable that our utilities will continue to recover from customers the regulatory assets in this table. In accordance with GAAP, our regulatory assets do not include the allowance for ROE that is capitalized for regulatory purposes. This allowance was $24.3 million and $18.2 million at December 31, 2019 and 2018 , respectively. (2) As of December 31, 2019 , we had $175.1 million of regulatory assets not earning a return, $29.1 million of regulatory assets earning a return based on short-term interest rates, and $151.5 million of regulatory assets earning a return based on long-term interest rates. The regulatory assets not earning a return primarily relate to certain environmental remediation costs, the recovery of which depends on the timing of the actual expenditures, as well as uncollectible expense, our electric real-time market pricing program, and unamortized loss on reacquired debt. The other regulatory assets in the table either earn a return at the applicable utility's weighted average cost of capital or the cash has not yet been expended, in which case the regulatory assets are offset by liabilities. (3) Primarily represents the unrecognized future pension and OPEB costs related to our defined benefit pension and OPEB plans. We are authorized recovery of these regulatory assets over the average remaining service life of each plan. (4) In accordance with the rate orders issued by the PSCW in December 2019, amounts previously collected from customers for the future removal of our recently retired plants were used to reduce our unrecovered plant balances during December 2019. Any additional removal costs that we incur will increase our plant retirement regulatory assets. (5) As of December 31, 2019 , we had made cash expenditures of $96.3 million related to these environmental remediation costs. The remaining $589.2 million represents our estimated future cash expenditures. (6) For information on the flow through of tax repairs and the regulatory treatment of the impacts of the Tax Legislation in our various jurisdictions, see Note 25, Regulatory Environment . (7) As a result of the rate order WE received from the PSCW in December 2019, the regulatory liability related to its mines deferral was offset against its SSR regulatory asset during December 2019. The rate order also authorized recovery of WE's SSR regulatory asset over a 15-year period that began on January 1, 2020. (8) Represents amounts recoverable from customers related to our uncollectible expense tracking mechanisms and riders. These mechanisms allow us to recover or refund the difference between actual uncollectible write-offs and the amounts recovered in rates. (9) Represents amounts recoverable from customers related to WE's costs of the generating units leased from We Power, including subsequent capital additions. The following regulatory liabilities were reflected on our balance sheets as of December 31: (in millions) 2019 2018 See Note Regulatory liabilities Income tax related items (1) $ 2,248.8 $ 2,406.6 15 Removal costs (2) 1,181.5 1,329.6 Pension and OPEB benefits (3) 354.9 238.3 19 Energy costs refundable through rate adjustments (4) 89.8 39.6 1(d) Earnings sharing mechanisms (5) 43.5 30.0 25 Electric transmission costs (5) 42.2 9.7 25 Uncollectible expense (6) 39.1 30.5 1(d) Decoupling 36.8 30.5 1(d) Energy efficiency programs (7) 30.7 31.7 Derivatives 6.7 16.4 1(q) Mines deferral (8) — 120.8 Other, net 6.4 4.7 Total regulatory liabilities $ 4,080.4 $ 4,288.4 Balance sheet presentation Other current liabilities $ 87.6 $ 36.8 Regulatory liabilities 3,992.8 4,251.6 Total regulatory liabilities $ 4,080.4 $ 4,288.4 (1) For information on the regulatory treatment of the impacts of the Tax Legislation in our various jurisdictions, see Note 25, Regulatory Environment . (2) Represents amounts collected from customers to cover the future cost of property, plant, and equipment removals that are not legally required. Legal obligations related to the removal of property, plant, and equipment are recorded as AROs. See Note 8, Asset Retirement Obligations, for more information on our legal obligations. (3) Primarily represents the unrecognized future pension and OPEB benefits related to our defined benefit pension and OPEB plans. We will amortize these regulatory liabilities into net periodic benefit cost over the average remaining service life of each plan. (4) Represents an over-collection of energy costs that will be refunded to customers in the future. When the rates we charge to customers include energy costs that are higher than our actual energy costs, any over-collection outside of the allowable energy cost price variance is refunded to customers. (5) Based on orders received from the PSCW, WE was required to apply the refunds due to customers from its earnings sharing mechanism to its electric transmission escrow through 2019. As a result, $38.6 million of WE's earnings sharing refunds were reflected in its electric transmission regulatory liability at December 31, 2019, and $37.2 million of WE's earnings sharing refunds were netted against its electric transmission regulatory asset at December 31, 2018. (6) Represents amounts refundable to customers related to our uncollectible expense tracking mechanisms and riders. These mechanisms allow us to recover or refund the difference between actual uncollectible write-offs and the amounts recovered in rates. (7) Represents amounts refundable to customers related to programs at the utilities designed to meet energy efficiency standards. (8) Represents the deferral of revenues less the associated cost of sales related to Tilden, which were not included in the PSCW's 2015 rate order. As a result of the rate order WE received from the PSCW in December 2019, this regulatory liability was offset against WE's SSR regulatory asset during December 2019. |
Property, Plant, and Equipment
Property, Plant, and Equipment | 12 Months Ended |
Dec. 31, 2019 | |
Property, Plant and Equipment [Abstract] | |
PROPERTY, PLANT AND EQUIPMENT | PROPERTY, PLANT, AND EQUIPMENT Property, plant, and equipment consisted of the following at December 31: (in millions) 2019 2018 Electric – generation $ 6,858.8 $ 6,410.6 Electric – distribution 7,018.1 6,534.6 Natural gas – distribution, storage, and transmission 11,602.7 10,766.3 Property, plant, and equipment to be retired, net — 174.8 Other 1,696.7 1,649.1 Less: Accumulated depreciation 8,073.7 7,573.6 Net 19,102.6 17,961.8 CWIP 820.4 707.5 Net utility property, plant, and equipment 19,923.0 18,669.3 We Power generation 3,245.7 3,244.4 Renewable generation 716.5 193.3 Natural gas storage 245.9 244.8 Net non-utility energy infrastructure 4,208.1 3,682.5 Corporate services 180.4 171.0 Other 88.8 127.1 Less: Accumulated depreciation 805.0 731.5 Net 3,672.3 3,249.1 CWIP 24.8 82.5 Net non-utility and other property, plant, and equipment 3,697.1 3,331.6 Total property, plant, and equipment $ 23,620.1 $ 22,000.9 Pleasant Prairie Power Plant The Pleasant Prairie power plant was retired on April 10, 2018. The net book value of this plant was $615.1 million at December 31, 2019 , representing book value less cost of removal and accumulated depreciation. In addition, previously deferred unprotected tax benefits from the Tax Legislation related to the unrecovered balance of this plant were $20.6 million . The net amount of $594.5 million was classified as a regulatory asset on our balance sheets as a result of the retirement of the plant. This regulatory asset does not include certain other previously recorded deferred tax liabilities of $172.1 million related to the retired Pleasant Prairie power plant. Effective with its rate order issued by the PSCW in December 2019, WE will continue to amortize this regulatory asset on a straight-line basis through 2039, using the composite depreciation rates approved by the PSCW before this plant was retired. Amortization is included in depreciation and amortization in the income statement. WE has FERC approval to continue to collect the net book value of the Pleasant Prairie power plant using the approved composite depreciation rates, in addition to a return on the remaining net book value. Collection of the return of and on the net book value is no longer subject to refund as the FERC completed its prudency review and concluded that the retirement of this plant was prudent. WE received approval from the PSCW in December 2019 to collect a full return of and on all but $100 million of the net book value of the Pleasant Prairie power plant. In accordance with its PSCW rate order received in December 2019, WE will seek a financing order from the PSCW to securitize the remaining $100 million . See Note 25, Regulatory Environment, for more information . Presque Isle Power Plant Pursuant to MISO's April 2018 approval of the retirement of the PIPP, these units were retired on March 31, 2019. The net book value of the PIPP was $162.7 million at December 31, 2019 , representing book value less cost of removal and accumulated depreciation. In addition, previously deferred unprotected tax benefits from the Tax Legislation related to the unrecovered balance of these units were $6.4 million . The net amount of $156.3 million was classified as a regulatory asset on our balance sheets as a result of the retirement of the plant. This regulatory asset does not include certain other previously recorded deferred tax liabilities of $46.5 million related to the retired PIPP. After the retirement of the PIPP, a portion of the regulatory asset and related cost of removal reserve was transferred to UMERC for recovery from its retail customers. Effective with its rate order issued by the PSCW in December 2019, WE received approval to collect a return of and on its share of the net book value of the PIPP, and as a result, will continue to amortize the regulatory assets on a straight-line basis through 2037, using the composite depreciation rates approved by the PSCW before the units were retired. UMERC will also continue to amortize the regulatory assets on a straight-line basis using the composite depreciation rates approved by the PSCW before the units were retired. Amortization is included in depreciation and amortization in the income statement. UMERC will address the accounting and regulatory treatment related to the retirement of the PIPP with the MPSC in conjunction with a future rate case. WE has FERC approval to continue to collect the net book value of the PIPP using the approved composite depreciation rates, in addition to a return on the net book value. However, this approval is subject to refund pending the outcome of settlement proceedings. See Note 25, Regulatory Environment, for more information . Pulliam Power Plant In connection with a MISO ruling, WPS retired Pulliam Units 7 and 8 on October 21, 2018. The net book value of the Pulliam units was $36.3 million at December 31, 2019 , representing book value less cost of removal and accumulated depreciation. This amount was classified as a regulatory asset on our balance sheets as a result of the retirement of the plant. Effective with its rate order issued by the PSCW in December 2019, WPS received approval to collect a return of and on the entire net book value of the Pulliam units, and as a result, will continue to amortize this regulatory asset on a straight-line basis through 2031, using the composite depreciation rates approved by the PSCW before these generating units were retired. Amortization is included in depreciation and amortization in the income statement. WPS has FERC approval to continue to collect the net book value of the Pulliam power plant using the approved composite depreciation rates, in addition to a return on the remaining net book value. FERC has completed its prudency review of Pulliam, concluding that the retirement of this plant was prudent. Edgewater Unit 4 The Edgewater 4 generating unit was retired on September 28, 2018. The net book value of the generating unit was $5.3 million at December 31, 2019 , representing book value less cost of removal and accumulated depreciation. This amount was classified as a regulatory asset on our balance sheets as a result of the retirement of the plant. Effective with its rate order issued by the PSCW in December 2019, WPS received approval to collect a return of and on the entire net book value of the Edgewater 4 generating unit, and as a result, will continue to amortize this regulatory asset on a straight-line basis through 2026, using the composite depreciation rates approved by the PSCW before this generating unit was retired. Amortization is included in depreciation and amortization in the income statement. WPS has FERC approval to continue to collect the net book value of the Edgewater 4 generating unit using the approved composite depreciation rates, in addition to a return on the remaining net book value. FERC has completed its prudency review of Edgewater 4, concluding that the retirement of this plant was prudent. Severance Liability for Plant Retirements In December 2017, a severance liability of $29.4 million was recorded in other current liabilities on our balance sheets related to these plant retirements. Activity related to this severance liability for the years ended December 31 was as follows: (in millions) 2019 2018 Severance liability at January 1 $ 15.7 $ 29.4 Severance payments (7.2 ) (10.7 ) Other (6.4 ) (3.0 ) Total severance liability at December 31 $ 2.1 $ 15.7 |
Jointly Owned Utility Facilitie
Jointly Owned Utility Facilities | 12 Months Ended |
Dec. 31, 2019 | |
Jointly Owned Utility Plant, Net Ownership Amount [Abstract] | |
JOINTLY OWNED UTILITY FACILITIES | JOINTLY OWNED UTILITY FACILITIES We Power and WPS hold joint ownership interests in certain electric generating facilities. They are entitled to their share of generating capability and output of each facility equal to their respective ownership interest. They pay their ownership share of additional construction costs and have supplied their own financing for all jointly owned projects. We record We Power's and WPS's proportionate share of significant jointly owned electric generating facilities as property, plant, and equipment on the balance sheets. We Power leases its ownership interest in ER 1 and ER 2 to WE, and WE operates these units. WE and WPS record their respective share of fuel inventory purchases and operating expenses, unless specific agreements have been executed to limit their maximum exposure to additional costs. WE's and WPS's proportionate share of direct expenses for the joint operation of these plants is recorded in operating expenses in the income statements. Information related to jointly owned utility facilities at December 31, 2019 was as follows: We Power WPS (in millions, except for percentages and MW) Elm Road Generating Station Units 1 and 2 Weston Unit 4 Columbia Energy Center Units 1 and 2 (2) Forward Wind Energy Center Ownership 83.34 % 70.0 % 27.6 % 44.6 % Share of rated capacity (MW) (1) 1,054.3 386.0 313.9 8.4 In-service date 2010 and 2011 2008 1975 and 1978 2008 Property, plant, and equipment $ 2,447.9 $ 663.2 $ 422.3 $ 118.7 Accumulated depreciation $ (416.1 ) $ (232.4 ) $ (129.5 ) $ (46.4 ) CWIP $ 0.8 $ 5.3 $ 1.8 $ 0.1 (1) Capacity for our electric generation facilities is based on rated capacity, which is the net power output under average operating conditions with equipment in an average state of repair as of a given month in a given year. Values are primarily based on the net dependable expected capacity ratings for summer 2020 established by tests and may change slightly from year to year. The summer period is the most relevant for capacity planning purposes. This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand. (2) Columbia Energy Center is jointly owned by Wisconsin Power and Light, Madison Gas and Electric, and WPS. In October 2016, Wisconsin Power and Light received an order from the PSCW approving amendments to the Columbia Energy Center joint operating agreement between the parties allowing WPS and Madison Gas and Electric to forgo certain capital expenditures at the Columbia Energy Center. As a result, Wisconsin Power and Light will incur these capital expenditures in exchange for a proportional increase in its ownership share of the Columbia Energy Center. Based upon the additional capital expenditures Wisconsin Power and Light expects to incur through June 1, 2020, WPS's ownership interest would decrease to 27.5% . WPS has partnered with an unaffiliated utility to construct two solar projects in Wisconsin. Badger Hollow I is located in Iowa County, Wisconsin, and Two Creeks is located in Manitowoc County, Wisconsin. Once constructed, WPS will own 100 MW of the output of each project for a total of 200 MW. The PSCW approved the acquisition of these two projects in April 2019. Construction began at Two Creeks and Badger Hollow I in August 2019 and October 2019, respectively. Commercial operation of both projects is targeted for the end of 2020. The CWIP balances for Badger Hollow I and Two Creeks as of December 31, 2019 were $32.5 million and $87.3 million , respectively. In August 2019, WE, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire an ownership interest in a proposed solar project, Badger Hollow II, that will be located in Iowa County, Wisconsin. At its meeting on February 20, 2020, the PSCW approved the acquisition of this project. The approval is still subject to WE's receipt and review of a final written order from the PSCW. Once constructed, WE will own 100 MW of the output of this project. Commercial operation of Badger Hollow II is targeted for the end of 2021. |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2019 | |
Asset Retirement Obligation Disclosure [Abstract] | |
ASSET RETIREMENT OBLIGATIONS | ASSET RETIREMENT OBLIGATIONS Our utilities have recorded AROs primarily for the removal of natural gas distribution mains and service pipes (including asbestos and PCBs); asbestos abatement at certain generation and substation facilities, office buildings, and service centers; the removal and dismantlement of biomass and hydro generation facilities; the dismantling of wind generation projects; the disposal of PCB-contaminated transformers; the closure of fly-ash landfills at certain generation facilities; and the removal of above ground storage tanks. Regulatory assets and liabilities are established by our utilities to record the differences between ongoing expense recognition under the ARO accounting rules and the rate-making practices for retirement costs authorized by the applicable regulators. AROs have also been recorded at Bishop Hill III, Coyote Ridge, and Upstream for the dismantling of wind generation projects. On our balance sheets, AROs are recorded within other long-term liabilities. The following table shows changes to our AROs during the years ended December 31: (in millions) 2019 2018 2017 Balance as of January 1 $ 461.4 $ 573.7 $ 557.7 Accretion 22.1 28.0 27.5 Additions and revisions to estimated cash flows 39.1 (1) (104.5 ) (2) 26.5 Liabilities settled (39.1 ) (35.8 ) (38.0 ) Balance as of December 31 $ 483.5 $ 461.4 $ 573.7 (1) AROs increased $40.1 million in 2019, primarily due to new natural gas distribution lines being placed into service at PGL. Also in 2019, AROs increased $10.7 million as a result of AROs being recorded for the legal requirement to dismantle, at retirement, the wind generation projects known as Upstream and Coyote Ridge. See Note 2, Acquisitions, for more information on Upstream and Coyote Ridge. AROs decreased $7.3 million due to revisions made to estimated cash flows for the abatement of asbestos at WE. (2) AROs decreased $127.3 million in 2018 due to revisions made to estimated cash flows primarily for changes in the cost to retire natural gas distribution pipe at PGL. Also in 2018, AROs increased $10.7 million as a result of revisions made to estimated cash flows for the abatement of asbestos at WPS's Pulliam power plant, and a $10.9 million ARO was recorded for the legal requirement to dismantle, at retirement, the wind generation projects known as Forward Wind Energy Center and Bishop Hill III. See Note 2, Acquisitions, for more information on Forward Wind Energy Center and Bishop Hill III. |
Goodwill
Goodwill | 12 Months Ended |
Dec. 31, 2019 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
GOODWILL | 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 changes to our goodwill balances by segment during the years ended December 31, 2019 and 2018 : Wisconsin Illinois Other States Non-Utility Energy Infrastructure Total (in millions) 2019 2018 2019 2018 2019 2018 2019 2018 2019 2018 Goodwill balance as of January 1 $ 2,104.3 $ 2,104.3 $ 758.7 $ 758.7 $ 183.2 $ 183.2 $ 6.6 $ 7.3 $ 3,052.8 $ 3,053.5 Adjustment to Bluewater purchase price allocation (1) — — — — — — — (0.7 ) — (0.7 ) Goodwill balance as of December 31 (2) $ 2,104.3 $ 2,104.3 $ 758.7 $ 758.7 $ 183.2 $ 183.2 $ 6.6 $ 6.6 $ 3,052.8 $ 3,052.8 (1) See Note 2, Acquisitions, for more information on the acquisition of Bluewater. (2) We had no accumulated impairment losses related to our goodwill as of December 31, 2019 . As of July 1, 2019, annual impairment tests were completed at all of our reporting units that carried a goodwill balance. No impairments resulted from these tests. |
Common Equity
Common Equity | 12 Months Ended |
Dec. 31, 2019 | |
Stockholders' Equity Note [Abstract] | |
COMMON EQUITY | COMMON EQUITY Stock-Based Compensation Plans The following table summarizes our pre-tax stock-based compensation expense and the related tax benefit recognized in income for the years ended December 31: (in millions) 2019 2018 2017 Stock options $ 4.4 $ 5.2 $ 3.4 Restricted stock 7.1 10.7 5.4 Performance units 38.7 20.2 20.2 Stock-based compensation expense $ 50.2 $ 36.1 $ 29.0 Related tax benefit $ 13.8 $ 9.9 $ 11.6 Stock-based compensation costs capitalized during 2019 , 2018 , and 2017 were not significant. Stock Options The following is a summary of our stock option activity during 2019 : Stock Options Number of Options Weighted-Average Exercise Price Weighted-Average Remaining Contractual Life (in years) Aggregate Intrinsic Value (in millions) Outstanding as of January 1, 2019 4,452,533 $ 48.86 Granted 476,418 $ 68.18 Exercised (1,609,948 ) $ 41.63 Forfeited (69,085 ) $ 62.33 Outstanding as of December 31, 2019 3,249,918 $ 54.98 6.3 $ 121.0 Exercisable as of December 31, 2019 1,744,386 $ 46.92 4.8 $ 79.0 The aggregate intrinsic value of outstanding and exercisable options in the above table represents the total pre-tax intrinsic value that would have been received by the option holders had they exercised all of their options on December 31, 2019 . This is calculated as the difference between our closing stock price on December 31, 2019 , and the option exercise price, multiplied by the number of in-the-money stock options. The intrinsic value of options exercised during the years ended December 31, 2019 , 2018 , and 2017 was $62.4 million , $32.4 million , and $33.8 million , respectively. The actual tax benefit from option exercises for the same periods was approximately $17.1 million , $8.9 million , and $13.5 million , respectively. As of December 31, 2019 , approximately $2.1 million of unrecognized compensation cost related to unvested and outstanding stock options was expected to be recognized over the next 1.6 years on a weighted-average basis. During the first quarter of 2020 , the Compensation Committee awarded 512,139 non-qualified stock options with a weighted-average exercise price of $91.49 and a weighted-average grant date fair value of $10.82 per option to certain of our officers and other key employees under its normal schedule of awarding long-term incentive compensation. Restricted Shares The following restricted stock activity occurred during 2019 : Restricted Shares Number of Shares Weighted-Average Grant Date Fair Value Outstanding and unvested as of January 1, 2019 234,627 $ 61.01 Granted 97,343 $ 68.18 Released (192,291 ) $ 60.76 Forfeited (5,570 ) $ 62.99 Outstanding and unvested as of December 31, 2019 134,109 $ 66.48 The intrinsic value of restricted stock released was $13.4 million , $7.9 million , and $5.4 million for the years ended December 31, 2019 , 2018 , and 2017 , respectively. The actual tax benefit from released restricted shares for the same years was $3.7 million , $2.2 million , and $2.1 million , respectively. As of December 31, 2019 , approximately $2.4 million of unrecognized compensation cost related to unvested and outstanding restricted stock was expected to be recognized over the next 1.6 years on a weighted-average basis. During the first quarter of 2020 , the Compensation Committee awarded 84,540 restricted shares to certain of our directors, officers, and other key employees under its normal schedule of awarding long-term incentive compensation. The grant date fair value of these awards was $91.49 per share. Performance Units During 2019 , 2018 , and 2017 , the Compensation Committee awarded 148,036 ; 217,560 ; and 237,650 performance units, respectively, to officers and other key employees under the WEC Energy Group Performance Unit Plan. Performance units with an intrinsic value of $18.7 million , $9.7 million , and $6.7 million were settled during 2019 , 2018 , and 2017 , respectively. The actual tax benefit from the distribution of performance units for the same years was $4.4 million , $2.2 million , and $2.1 million , respectively. At December 31, 2019 , we had 539,475 performance units outstanding, including dividend equivalents. A liability of $58.1 million was recorded on our balance sheet at December 31, 2019 related to these outstanding units. As of December 31, 2019 , approximately $20.5 million of unrecognized compensation cost related to unvested and outstanding performance units was expected to be recognized over the next 1.6 years on a weighted-average basis. During the first quarter of 2020 , we settled performance units with an intrinsic value of $34.2 million . The actual tax benefit from the distribution of these awards was $8.4 million . In January 2020 , the Compensation Committee also awarded 140,455 performance units to certain of our officers and other key employees under its normal schedule of awarding long-term incentive compensation. Restrictions Our ability as a holding company to pay common stock dividends primarily depends on the availability of funds received from our utility subsidiaries, We Power, ATC Holding, and WECI. Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans, or advances. All of our utility subsidiaries, with the exception of UMERC and MGU, are prohibited from loaning funds to us, either directly or indirectly. In accordance with their most recent rate orders, WE, WPS, and WG may not pay common dividends above the test year forecasted amounts reflected in their respective rate cases, if it would cause their average common equity ratio, on a financial basis, to fall below their authorized level of 52.5% . A return of capital in excess of the test year amount can be paid by each company at the end of the year provided that their respective average common equity ratios do not fall below the authorized level. WE may not pay common dividends to us under WE's Restated Articles of Incorporation if any dividends on its outstanding preferred stock have not been paid. In addition, pursuant to the terms of WE's 3.60% Serial Preferred Stock, WE's ability to declare common dividends would be limited to 75% or 50% of net income during a twelve month period if its common stock equity to total capitalization, as defined in the preferred stock designation, is less than 25% and 20% , respectively. NSG's long-term debt obligations contain provisions and covenants restricting the payment of cash dividends and the purchase or redemption of its capital stock. The long-term debt obligations of UMERC, Bluewater Gas Storage, and ATC Holding contain a provision requiring them to maintain a total funded debt to capitalization ratio of 65% or less. WEC Energy Group and Integrys have the option to defer interest payments on their junior subordinated notes, from time to time, for one or more periods of up to 10 consecutive years per period. During any period in which they defer interest payments, they may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire, their respective common stock. See Note 12, Short-Term Debt and Lines of Credit , for discussion of certain financial covenants related to short-term debt obligations. As of December 31, 2019 , restricted net assets of our consolidated subsidiaries totaled approximately $7.4 billion . Our equity in undistributed earnings of investees accounted for by the equity method was approximately $363 million . We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future. Share Purchases We have instructed our independent agents to purchase shares on the open market to fulfill obligations under various stock-based employee benefit and compensations plans and to provide shares to participants in our dividend reinvestment and stock purchase plan. As a result, no new shares of common stock were issued in 2019 , 2018 , or 2017 . The following is a summary of shares purchased to fulfill exercised stock options and restricted stock awards during the years ended December 31 : (in millions) 2019 2018 2017 Shares purchased 1.8 1.1 1.1 Cost of shares purchased $ 140.1 $ 72.4 $ 71.3 Common Stock Dividends During the year ended December 31, 2019 , our Board of Directors declared common stock dividends which are summarized below: Date Declared Date Payable Per Share Period January 17, 2019 March 1, 2019 $0.59 First quarter April 18, 2019 June 1, 2019 $0.59 Second quarter July 18, 2019 September 1, 2019 $0.59 Third quarter October 17, 2019 December 1, 2019 $0.59 Fourth quarter On January 16, 2020 , our Board of Directors declared a quarterly cash dividend of $0.6325 per share, which equates to an annual dividend of $2.53 per share. The dividend is payable on March 1, 2020 , to shareholders of record on February 14, 2020 . In addition, the Board of Directors affirmed our dividend policy that continues to target a dividend payout ratio of 65 - 70% of earnings. |
Preferred Stock
Preferred Stock | 12 Months Ended |
Dec. 31, 2019 | |
Class of Stock Disclosures [Abstract] | |
PREFERRED STOCK | PREFERRED STOCK The following table shows preferred stock authorized and outstanding at December 31, 2019 and 2018 : (in millions, except share and per share amounts) Shares Authorized Shares Outstanding Redemption Price Per Share Total WEC Energy Group $.01 par value Preferred Stock 15,000,000 — — $ — WE $100 par value, Six Per Cent. Preferred Stock 45,000 44,498 — 4.4 $100 par value, Serial Preferred Stock 3.60% Series 2,286,500 260,000 $ 101 26.0 $25 par value, Serial Preferred Stock 5,000,000 — — — WPS $100 par value, Preferred Stock 1,000,000 — — — PGL $100 par value, Cumulative Preferred Stock 430,000 — — — NSG $100 par value, Cumulative Preferred Stock 160,000 — — — Total $ 30.4 |
Short-Term Debt and Lines of Cr
Short-Term Debt and Lines of Credit | 12 Months Ended |
Dec. 31, 2019 | |
Short-term Debt [Abstract] | |
SHORT-TERM DEBT AND LINES OF CREDIT | SHORT-TERM DEBT AND LINES OF CREDIT The following table shows our short-term borrowings and their corresponding weighted-average interest rates as of December 31: (in millions, except percentages) 2019 2018 Commercial paper Amount outstanding at December 31 $ 830.8 $ 1,440.1 Average interest rate on amounts outstanding at December 31 2.00 % 2.92 % Our average amount of commercial paper borrowings based on daily outstanding balances during 2019 , was $1,039.2 million with a weighted-average interest rate during the period of 2.58% . WEC Energy Group, WE, WPS, WG, and PGL have entered into bank back-up credit facilities to maintain short-term credit liquidity which, among other terms, require them to maintain, subject to certain exclusions, a total funded debt to capitalization ratio of 70.0% , 65.0% , 65.0% , 65.0% , and 65.0% or less, respectively. As of December 31, 2019 , all companies were in compliance with their respective ratio. The information in the table below relates to our revolving credit facilities used to support our commercial paper borrowing program, including remaining available capacity under these facilities as of December 31 : (in millions) Maturity 2019 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 830.8 Available capacity under existing agreements $ 1,966.9 Each of these facilities has a renewal provision for two extensions, subject to lender approval. Each extension is for a period of one year . The bank back-up credit facilities contain customary covenants, including certain limitations on the respective companies' ability to sell assets. The credit facilities also contain customary events of default, including payment defaults, material inaccuracy of representations and warranties, covenant defaults, bankruptcy proceedings, certain judgments, Employee Retirement Income Security Act of 1974 defaults, and change of control. In addition, pursuant to the terms of our credit agreement, we must ensure that certain of our subsidiaries comply with several of the covenants contained therein. |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2019 | |
Debt Disclosure [Abstract] | |
LONG-TERM DEBT | LONG-TERM DEBT The following table is a summary of our long-term debt outstanding (excluding finance/capital leases) as of December 31: (in millions) 2019 2018 Long-term debt Maturity Date Weighted Average Interest Rate Balance Weighted Average Interest Rate Balance WEC Energy Group Senior Notes (unsecured) (1) 2020-2033 3.47 % $ 2,050.0 3.54 % $ 1,700.0 WEC Energy Group Junior Notes (unsecured) (1) (2) 2067 4.50 % 500.0 4.85 % 500.0 WE Debentures (unsecured) 2021-2095 4.26 % 2,785.0 4.50 % 2,735.0 WPS Senior Notes (unsecured) 2021-2049 4.04 % 1,625.0 4.21 % 1,325.0 WG Debentures (unsecured) 2024-2046 3.65 % 640.0 4.04 % 490.0 Integrys Senior Notes (unsecured) 2020 4.17 % 250.0 4.17 % 250.0 Integrys Junior Notes (unsecured) (3) 2073 6.00 % 400.0 6.00 % 400.0 PGL First and Refunding Mortgage Bonds (secured) (4) 2024-2047 3.59 % 1,520.0 3.88 % 1,195.0 NSG First Mortgage Bonds (secured) (5) 2027-2043 3.81 % 132.0 3.81 % 132.0 MERC Senior Notes (unsecured) 2027-2047 3.51 % 120.0 3.51 % 120.0 MGU Senior Notes (unsecured) 2027-2047 3.51 % 90.0 3.51 % 90.0 UMERC Senior Notes (unsecured) 2029 3.26 % 160.0 N/A — Bluewater Gas Storage Senior Notes (unsecured) (6) 2020-2047 3.76 % 120.3 3.76 % 122.7 ATC Holding Senior Notes (unsecured) 2025-2030 4.05 % 475.0 4.34 % 240.0 We Power Subsidiaries Notes (secured, nonrecourse) (6) (7) 2020-2041 5.57 % 1,005.2 5.56 % 1,037.9 WECC Notes (unsecured) 2028 6.94 % 50.0 6.94 % 50.0 Total 11,922.5 10,387.6 Integrys acquisition fair value adjustment 14.3 20.6 Unamortized debt issuance costs (52.9 ) (44.7 ) Unamortized discount, net and other (25.6 ) (27.8 ) Total long-term debt, including current portion (8) 11,858.3 10,335.7 Current portion of long-term debt (686.9 ) (360.1 ) Total long-term debt $ 11,171.4 $ 9,975.6 (1) In connection with our outstanding 2007 Junior Notes, we executed an RCC, which we amended on June 29, 2015, for the benefit of persons that buy, hold, or sell a specified series of our long-term indebtedness (covered debt). Our 6.20% Senior Notes due April 1, 2033 have been designated as the covered debt under the RCC. The RCC provides that we may not redeem, defease, or purchase, and that our subsidiaries may not purchase, any 2007 Junior Notes on or before May 15, 2037, unless, subject to certain limitations described in the RCC, we have received a specified amount of proceeds from the sale of qualifying securities. (2) Variable interest rate reset quarterly. The rates were 4.02% and 4.73% as of December 31, 2019 and 2018 , respectively. On July 12, 2018 we executed two interest rate swaps that provided a fixed rate of 4.9765% on $250.0 million of the outstanding notes. The effective rates of 4.50% and 4.85% as of December 31, 2019 and 2018 , respectively, were blended rates of the variable and fixed portions. (3) Effective August 2023, Integrys's $400.0 million of 2013 6.00% Junior Subordinated Notes due 2073 will bear interest at the three-month LIBOR plus 322 basis points and will reset quarterly. (4) PGL's First Mortgage Bonds are subject to the terms and conditions of PGL's First Mortgage Indenture dated January 2, 1926, as supplemented. Under the terms of the Indenture, substantially all property owned by PGL is pledged as collateral for these outstanding debt securities. PGL has used certain First Mortgage Bonds to secure tax exempt interest rates. The Illinois Finance Authority has issued Tax Exempt Bonds, and the proceeds from the sale of these bonds were loaned to PGL. In return, PGL issued equal principal amounts of certain collateralized First Mortgage Bonds. The mandatory reset date for PGL's $50.0 million of 1.875% Bonds, series WW, is August 1, 2020. (5) NSG's First Mortgage Bonds are subject to the terms and conditions of NSG's First Mortgage Indenture dated April 1, 1955, as supplemented. Under the terms of the Indenture, substantially all property owned by NSG is pledged as collateral for these outstanding debt securities. (6) The long-term debt of Bluewater and We Power's subsidiaries amortizes on a mortgage-style basis. (7) We Power's subsidiaries' senior notes are secured by a collateral assignment of the leases between We Power's subsidiaries and WE related to PWGS and ERGS, as applicable. (8) The amount of long-term debt on our balance sheets includes finance/capital lease obligations of $45.9 million and $23.3 million at December 31, 2019 and 2018 , respectively. We amortize debt premiums, discounts, and debt issuance costs over the life of the debt and we include the costs in interest expense. WEC Energy Group, Inc. In March 2019, we issued $350.0 million of 3.10% Senior Notes due March 8, 2022. We used the net proceeds to repay short-term debt, and for working capital and other general corporate purposes. Wisconsin Electric Power Company In December 2019, WE issued $300.0 million of 2.05% Debentures due December 15, 2024, and used the net proceeds to repay WE's $250.0 million of 4.25% Debentures which matured in December 2019, to repay short-term debt, and for working capital and other corporate purposes. Wisconsin Public Service Corporation In August 2019, WPS issued $300.0 million of 3.30% Senior Notes due September 1, 2049, and used the net proceeds to repay short-term debt and for working capital and other corporate purposes. Wisconsin Gas LLC In October 2019, WG issued $150.0 million of 2.38% Debentures due November 1, 2024, and used the net proceeds to repay short-term debt and for working capital and other corporate purposes. The Peoples Gas Light and Coke Company In September 2019, PGL issued $275.0 million of 2.96% Bonds, Series GGG due September 1, 2029. PGL used the net proceeds to repay PGL's $75.0 million of 4.63% Bonds, Series UU which matured in September 2019, and for general corporate purposes, including capital expenditures and the repayment of short-term debt. In November 2019, PGL issued $75.0 million of 2.64% Bonds, Series HHH due November 1, 2024 and $50.0 million of 3.06% Bonds, Series III due November 1, 2031. PGL used the net proceeds for general corporate purposes, including capital expenditures and the repayment of short-term debt. Upper Michigan Energy Resources Corporation In August 2019, UMERC issued $160.0 million of 3.26% Senior Notes due August 28, 2029, and used the net proceeds to redeem its long-term debt to WEC Energy Group and for working capital and general corporate purposes. ATC Holding LLC In September 2019, ATC Holding issued $235.0 million of 3.75% Senior Notes due September 16, 2029, and used the net proceeds to balance its capital structure. The following table shows the long-term debt securities (excluding finance leases) maturing within one year of December 31, 2019 : (in millions) Interest Rate Maturity Date * Principal Amount WEC Energy Group Senior Notes (unsecured) 2.45% June $ 400.0 Integrys Senior Notes (unsecured) 4.17% November 250.0 Bluewater Gas Storage Senior Notes (unsecured) 3.76% Semi-annually 2.5 We Power Subsidiaries Notes – PWGS (secured, nonrecourse) 4.91% Monthly 6.6 We Power Subsidiaries Notes – ERGS (secured, nonrecourse) 5.209% Semi-annually 12.6 We Power Subsidiaries Notes – ERGS (secured, nonrecourse) 4.673% Semi-annually 9.7 We Power Subsidiaries Notes – PWGS (secured, nonrecourse) 6.00% Monthly 5.5 Total $ 686.9 * Maturity dates listed as semi-annually and monthly are associated with debt that amortizes on a mortgage-style basis. The following table shows the future maturities of our long-term debt outstanding (excluding obligations under finance leases) as of December 31, 2019 : (in millions) Payments 2020 $ 686.9 2021 1,338.8 2022 390.8 2023 42.8 2024 570.0 Thereafter 8,893.2 Total $ 11,922.5 Certain long-term debt obligations contain financial and other covenants related to payment of principal and interest when due, maintaining certain total funded debt to capitalization ratios, and various other obligations. Failure to comply with these covenants could result in an event of default, which could result in the acceleration of outstanding debt obligations. |
Leases
Leases | 12 Months Ended |
Dec. 31, 2019 | |
Leases [Abstract] | |
LEASES | LEASES Obligations Under Operating Leases We have recorded right of use assets and lease liabilities associated with the following operating leases. • Leases of office space, primarily related to several floors we are leasing in the Aon Center office building in Chicago, Illinois, though April 2029. • Land we are leasing related to our Rothschild biomass plant through June 2051. • Rail cars we are leasing to transport coal to various generating facilities through February 2021. The operating leases generally require us to pay property taxes, insurance premiums, and operating and maintenance costs associated with the leased property. Many of our leases contain options to renew past the initial term, as set forth in the lease agreement. Obligations Under Finance Lease Power Purchase Commitment In 1997, we entered into a 25 -year power purchase contract with an unaffiliated independent power producer. The contract, for 236 MWs of firm capacity from a natural gas-fired cogeneration facility, includes zero minimum energy requirements. When the contract expires in 2022, we may, at our option and with proper notice, renew for another ten years , purchase the generating facility at fair market value, or allow the contract to expire. At lease inception we recorded this leased facility and corresponding obligation on our balance sheets at the estimated fair value of the plant's electric generating facilities. Minimum lease payments are a function of the 236 MWs of firm capacity we receive from the plant and the fixed monthly capacity rate published in the lease. Prior to our adoption of Topic 842 on January 1, 2019, we accounted for this finance lease under Topic 980-840, Regulated Operations – Leases, as follows: • We recorded our minimum lease payments as purchased power expense in cost of sales on our income statement. • We recorded the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under finance lease accounting rules as a deferred regulatory asset on our balance sheets. In conjunction with our adoption of Topic 842, while the timing of expense recognition related to this finance lease did not change, classification of the lease expense changed as follows: • Effective January 1, 2019, the minimum lease payments under the power purchase contract were no longer classified within cost of sales in our income statements, but were instead recorded as a component of depreciation and amortization and interest expense in accordance with Topic 980-842, Regulated Operations – Leases. • In accordance with Topic 980-842, the timing of lease expense did not change for this finance lease upon adoption of Topic 842, and still resembled the expense recognition pattern of an operating lease, as the amortization of the right of use assets was modified from what would typically be recorded for a finance lease under Topic 842. • We continue to record the difference between the minimum lease payments and the sum of imputed interest and unadjusted amortization costs calculated under the finance lease accounting rules as a deferred regulatory asset on our balance sheets. Due to the timing and the amounts of the minimum lease payments, the regulatory asset increased to $78.5 million in 2009, at which time the regulatory asset began to be reduced to zero over the remaining life of the contract. The total obligation under the finance lease was $18.4 million at December 31, 2019 , and will decrease to zero over the remaining life of the contract. Two Creeks Solar Project Related to its investment in Two Creeks, WPS, along with an unaffiliated utility, entered into several land leases in Manitowoc County, Wisconsin that commenced in the third quarter of 2019. The leases with unaffiliated parties are for a total of approximately 600 acres of land. Each lease has an initial term of 30 years with two optional 10 -year extensions. We expect the two optional extensions to be exercised, and, as a result, the land leases are being amortized over the 50 -year extended term of the leases. The lease payments are being recovered through rates. We treat these land lease contracts as operating leases for rate-making purposes. Our total obligation under the finance leases for Two Creeks was $7.7 million as of December 31, 2019 , and will decrease to zero over the remaining lives of the leases. Badger Hollow Solar Farm I Related to its investment in Badger Hollow I, WPS, along with an unaffiliated utility, entered into several land leases in Iowa County, Wisconsin that commenced in the third quarter of 2019. The leases are for a total of approximately 1,400 acres of land. Each lease has an initial construction term that ends upon achieving commercial operation, then automatically extends for 25 years with an option for an additional 25 -year extension. We expect the optional extension to be exercised, and, as a result, the land leases are being amortized over the extended term of the leases. The lease payments will be recovered through rates. We treat these land lease contracts as operating leases for rate-making purposes. Our total obligation under the finance leases for Badger Hollow I was $19.8 million as of December 31, 2019 , and will decrease to zero over the remaining lives of the leases. Amounts Recognized in the Financial Statements The components of lease expense and supplemental cash flow information related to our leases for the years ended December 31 are as follows: (in millions) 2019 2018 2017 Finance/capital lease expense (1) $ 8.2 $ 7.7 $ 7.2 Operating lease expense (2) 5.5 5.6 6.4 Short-term lease expense (2) 0.6 1.5 0.8 Total lease expense $ 14.3 $ 14.8 $ 14.4 Other information Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from finance/capital leases (3) $ 3.3 $ 7.7 $ 7.2 Operating cash flows from operating leases $ 6.0 $ 6.5 $ 7.1 Financing cash flows from finance leases (3) $ 4.9 Non-cash activities: Right of use assets obtained in exchange for finance lease liabilities $ 27.2 Right of use assets obtained in exchange for operating lease liabilities $ 49.0 Weighted-average remaining lease term – finance leases 31.5 years Weighted-average remaining lease term – operating leases 12.9 years Weighted-average discount rate – finance lease (4) 6.7 % Weighted average discount rate – operating leases (4) 4.4 % (1) For the year ended December 31, 2019 , finance lease expense included amortization of right of use assets in the amount of $4.9 million (included in depreciation and amortization expense) and interest on lease liabilities of $3.3 million (included in interest expense). For the years ended December 31, 2018 and 2017 , total capital lease expense related to the long-term power purchase agreement was included in cost of sales. (2) Operating and short-term lease expense were included as a component of operation and maintenance for the years ended December 31, 2019 , 2018 , and 2017 . (3) Prior to our adoption of Topic 842 on January 1, 2019, all cash flows related to the finance lease were recorded as a component of operating cash flows. (4) Because our operating leases do not provide an implicit rate of return, we used the fully collateralized incremental borrowing rates based upon information available for similarly rated companies in determining the present value of lease payments for our operating leases. For our power purchase agreement that meets the definition of a finance lease, the rate implicit in the lease was readily determinable. For our solar land leases that are finance leases, we used the fully collateralized incremental borrowing rates based upon information available for similarly rated companies in determining the present value of lease payments. The following table summarizes our finance lease right of use assets, which were included in property, plant and equipment on our balance sheets at December 31: (in millions) 2019 2018 Long-term power purchase commitment Under finance/capital lease $ 140.3 $ 140.3 Accumulated amortization (126.6 ) (120.9 ) Total long-term power purchase commitment $ 13.7 $ 19.4 Two Creeks land leases Under finance leases $ 7.7 $ — Accumulated amortization (0.1 ) — Total Two Creeks land leases $ 7.6 $ — Badger Hollow I land leases Under finance leases $ 19.5 $ — Accumulated amortization (0.2 ) — Total Badger Hollow I land leases $ 19.3 $ — Total finance lease right of use assets/capital lease asset $ 40.6 $ 19.4 Right of use assets related to operating leases were $41.4 million at December 31, 2019 , and were included in other long-term assets on our balance sheets. Future minimum lease payments under our operating leases and our finance leases, and the present value of our net minimum lease payments as of December 31, 2019 , were as follows: (in millions) Total Operating Leases Power Purchase Commitment Two Creeks Badger Hollow I Total Finance Leases 2020 $ 6.8 $ 8.8 $ 0.2 $ 0.3 $ 9.3 2021 4.8 9.4 0.2 0.7 10.3 2022 4.8 4.2 0.2 0.7 5.1 2023 4.9 — 0.2 0.7 0.9 2024 4.8 — 0.2 0.7 0.9 Thereafter 30.1 — 22.8 53.4 76.2 Total minimum lease payments 56.2 22.4 23.8 56.5 102.7 Less: Interest (14.8 ) (4.0 ) (16.1 ) (36.7 ) (56.8 ) Present value of minimum lease payments 41.4 18.4 7.7 19.8 45.9 Less: Short-term lease liabilities (4.4 ) (6.3 ) — — (6.3 ) Long-term lease liabilities $ 37.0 $ 12.1 $ 7.7 $ 19.8 $ 39.6 Short-term and long-term lease liabilities related to operating leases were included in other current liabilities and other long-term liabilities on the balance sheets, respectively. At December 31, 2018 , short-term and long-term liabilities under our capital lease were $4.9 million and $18.4 million , respectively. Short-term and long-term lease liabilities related to our finance/capital leases were included in current portion of long-term debt and long-term debt on the balance sheets, respectively. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | |
INCOME TAXES | INCOME TAXES Income Tax Expense The following table is a summary of income tax expense for the years ended December 31: (in millions) 2019 2018 2017 Current tax expense (benefit) $ (37.9 ) $ (127.5 ) $ 111.8 Deferred income taxes, net 167.7 300.1 274.4 Investment tax credit, net (4.8 ) (2.8 ) (2.7 ) Total income tax expense $ 125.0 $ 169.8 $ 383.5 Statutory Rate Reconciliation The provision for income taxes for each of the years ended December 31 differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes as a result of the following: 2019 2018 2017 (2) Effective Effective Effective (in millions) Amount Tax Rate Amount Tax Rate Amount Tax Rate Statutory federal income tax $ 264.4 21.0 % $ 258.1 21.0 % $ 555.5 35.0 % State income taxes net of federal tax benefit 80.4 6.4 % 71.8 5.8 % 100.8 6.4 % Tax repairs (1) (122.8 ) (9.8 )% (120.7 ) (9.8 )% — — % Federal excess deferred tax amortization (34.9 ) (2.8 )% (16.8 ) (1.4 )% — — % Wind production tax credits (34.1 ) (2.7 )% (12.1 ) (1.0 )% (16.8 ) (1.1 )% Excess tax benefits – stock options (15.8 ) (1.3 )% (5.9 ) (0.5 )% (10.0 ) (0.6 )% Investment tax credit restored (4.8 ) (0.4 )% (2.8 ) (0.2 )% (2.7 ) (0.2 )% AFUDC – Equity (3.0 ) (0.2 )% (3.2 ) (0.3 )% (4.0 ) (0.3 )% Federal tax reform — — % — — % (226.9 ) (14.3 )% Other, net (4.4 ) (0.3 )% 1.4 0.2 % (12.4 ) (0.8 )% Total income tax expense $ 125.0 9.9 % $ 169.8 13.8 % $ 383.5 24.1 % (1) In accordance with a settlement agreement with the PSCW, WE flowed through the tax benefit of its repair related deferred tax liabilities in 2018 and 2019, to maintain certain regulatory asset balances at their December 31, 2017 levels. The flow through treatment of the repair related deferred tax liabilities offsets the negative income statement impact of holding the regulatory assets level, resulting in no change to net income. See Note 25, Regulatory Environment, for more information about the impact of the Tax Legislation and the Wisconsin rate order. (2) In 2017, the net impact of tax reform in the amount of $206.7 million is represented in both the Federal tax reform and State income taxes net of federal tax benefit lines above. Deferred Income Tax Assets and Liabilities On December 22, 2017, the Tax Legislation was signed into law. For businesses, the Tax Legislation reduced the corporate federal tax rate from a maximum of 35% to a 21% rate effective January 1, 2018. In December 2017, we recorded a tax benefit related to the re-measurement of our deferred taxes in the amount of $2,657 million . Accordingly, the tax benefit related to our regulated utilities was recorded as both an increase to regulatory liabilities as well as a decrease to certain existing regulatory assets as of December 31, 2017. The effects of the Tax Legislation primarily at our non-utility energy infrastructure and corporate and other segments resulted in the recording of an income tax benefit of approximately $206.7 million for the year ended December 31, 2017. This tax benefit was primarily due to a re-measurement of deferred tax assets and liabilities. On December 22, 2017, the SEC staff issued guidance in SAB 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act, which provided for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, certain amounts related to bonus depreciation and future tax benefit utilization recorded in the financial statements as a result of the Tax Legislation were considered "provisional" and subject to revision at December 31, 2017, and through 2018, as discussed in SAB 118. In 2018, we considered all available guidance from industry and income tax authorities related to these tax items, and revised our Alternative Minimum Tax Credit valuation allowance, and revised our estimates for re-measurement of deferred income taxes related to guidance on bonus depreciation. See Note 25, Regulatory Environment, for more information on the re-measurement of deferred income taxes. At December 31, 2018, we no longer considered any amounts related to bonus depreciation and future tax benefit utilization "provisional," subject to any additional amendments or technical corrections to the Tax Legislation. In 2019, we considered all available guidance from industry and income tax authorities related to these tax items, and reversed the valuation allowance we had related to Alternative Minimum Tax Credits due to an IRS Announcement issued January 14, 2019. Any further amendments or technical corrections to the Tax Legislation could subject these tax items to revision. The components of deferred income taxes as of December 31 were as follows: (in millions) 2019 2018 Deferred tax assets Tax gross up – regulatory items $ 519.8 $ 579.2 Deferred revenues 106.3 129.3 Future tax benefits 101.0 70.6 Other 159.8 194.4 Total deferred tax assets 886.9 973.5 Valuation allowance (2.3 ) (11.4 ) Net deferred tax assets $ 884.6 $ 962.1 Deferred tax liabilities Property-related $ 3,609.0 $ 3,436.9 Investment in affiliates 531.7 420.6 Deferred costs – Plant retirements 232.0 176.0 Employee benefits and compensation 131.4 121.2 Other 149.8 195.5 Total deferred tax liabilities 4,653.9 4,350.2 Deferred tax liability, net $ 3,769.3 $ 3,388.1 Consistent with rate-making treatment, deferred taxes related to our regulated utilities in the table above are offset for temporary differences that have related regulatory assets and liabilities. The components of net deferred tax assets associated with federal and state tax benefit carryforwards as of December 31, 2019 and 2018 are summarized in the tables below: 2019 (in millions) Gross Value Deferred Tax Effect Valuation Allowance Earliest Year of Expiration Future tax benefits as of December 31, 2019 Federal tax credit $ — $ 75.4 $ — 2037 State net operating loss 287.1 17.6 (2.3 ) 2023 Other state benefits — 8.0 — 2019 Balance as of December 31, 2019 $ 287.1 $ 101.0 $ (2.3 ) 2018 (in millions) Gross Value Deferred Tax Effect Valuation Allowance Earliest Year of Expiration Future tax benefits as of December 31, 2018 Federal foreign tax credit $ — $ 9.7 $ (9.7 ) 2018 Other federal tax credit — 39.3 (1.7 ) 2038 State net operating loss 275.9 17.0 — 2023 Other state benefits — 4.6 — 2018 Balance as of December 31, 2018 $ 275.9 $ 70.6 $ (11.4 ) Unrecognized Tax Benefits A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows: (in millions) 2019 2018 Balance as of January 1 $ 20.0 $ 17.3 Additions for tax positions of prior years 1.9 2.8 Additions based on tax positions related to the current year 0.2 0.1 Reductions for tax positions of prior years (4.2 ) (0.2 ) Balance as of December 31 $ 17.9 $ 20.0 The amount of unrecognized tax benefits as of both December 31, 2019 and 2018 , excludes deferred tax assets related to uncertainty in income taxes of $2.0 million . As of December 31, 2019 and 2018 , the net amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate for continuing operations was $15.9 million and $18.0 million , respectively. For the years ended December 31, 2019 , 2018 , and 2017 , we recognized $0.1 million of interest expense, $0.5 million of interest expense, and $0.6 million of interest income, respectively, related to unrecognized tax benefits in our income statements. For the years ended December 31, 2019 , 2018 , and 2017 , we recognized no penalties related to unrecognized tax benefits in our income statements. For the year ended December 31, 2019 , we had $0.8 million of interest accrued and no penalties accrued related to unrecognized tax benefits on our balance sheets. For the year ended December 31, 2018 , we had $0.7 million of interest accrued and no penalties accrued related to unrecognized tax benefits on our balance sheets. Although analysis of our unrecognized tax benefits is ongoing, the potential estimated decrease in the total amounts of unrecognized tax benefits within the next 12 months is approximately $11.4 million associated with statutes of limitations on certain tax years. We do not anticipate any significant increases in the total amounts of unrecognized tax benefits within the next 12 months. We file income tax returns in the United States federal jurisdiction and state tax returns based on income in our major state operating jurisdictions of Wisconsin, Illinois, Michigan, and Minnesota. We also file tax returns in other state and local jurisdictions with varying statutes of limitations. As of December 31, 2019 , with a few exceptions, we were subject to examination by federal and state or local tax authorities for the 2015 through 2019 tax years in our major operating jurisdictions as follows: Jurisdiction Years Federal 2015–2019 Illinois 2015–2019 Michigan 2015–2019 Minnesota 2015–2019 Wisconsin 2015–2019 |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2019 | |
Fair Value Disclosures [Abstract] | |
FAIR VALUE MEASUREMENTS | FAIR VALUE MEASUREMENTS The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy: December 31, 2019 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 1.4 $ 2.0 $ — $ 3.4 FTRs — — 3.1 3.1 Coal contracts — 0.4 — 0.4 Total derivative assets $ 1.4 $ 2.4 $ 3.1 $ 6.9 Investments held in rabbi trust $ 85.3 $ — $ — $ 85.3 Derivative liabilities Natural gas contracts $ 21.4 $ 1.3 $ — $ 22.7 Coal contracts — 0.2 — 0.2 Interest rate swaps — 6.0 — 6.0 Total derivative liabilities $ 21.4 $ 7.5 $ — $ 28.9 December 31, 2018 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 6.3 $ 1.8 $ — $ 8.1 FTRs — — 7.4 7.4 Coal contracts — 0.4 — 0.4 Total derivative assets $ 6.3 $ 2.2 $ 7.4 $ 15.9 Investments held in rabbi trust $ 65.0 $ — $ — $ 65.0 Derivative liabilities Natural gas contracts $ 4.7 $ 0.8 $ — $ 5.5 Coal contracts — 0.1 — 0.1 Interest rate swaps — 2.3 — 2.3 Total derivative liabilities $ 4.7 $ 3.2 $ — $ 7.9 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 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. For the years ended December 31, 2019 and 2017 , the net unrealized gains included in earnings related to the investments held at the end of the period were $18.7 million and $18.8 million , respectively. The net unrealized gains included in earnings for the year ended December 31, 2018 were not significant. The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy at December 31 : (in millions) 2019 2018 2017 Balance at the beginning of the period $ 7.4 $ 4.4 $ 5.1 Purchases 12.8 18.4 13.8 Settlements (17.1 ) (15.4 ) (14.5 ) Balance at the end of the period $ 3.1 $ 7.4 $ 4.4 Fair Value of Financial Instruments The following table shows the financial instruments included on our balance sheets that are not recorded at fair value at December 31 : 2019 2018 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock of subsidiary $ 30.4 $ 29.5 $ 30.4 $ 28.3 Long-term debt, including current portion * 11,858.3 13,035.9 10,335.7 10,554.9 * The carrying amount of long-term debt excludes finance and capital lease obligations of $45.9 million and $23.3 million at December 31, 2019 and 2018 , respectively. The fair values of our long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy. |
Derivative Instruments
Derivative Instruments | 12 Months Ended |
Dec. 31, 2019 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
DERIVATIVE INSTRUMENTS | DERIVATIVE INSTRUMENTS The following table shows our derivative assets and derivative liabilities, along with their classification on our balance sheets. None of our derivatives are designated as hedging instruments, with the exception of our interest rate swaps, which have been designated as cash flow hedges. December 31, 2019 December 31, 2018 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Other current Natural gas contracts $ 3.4 $ 21.8 $ 7.7 $ 5.3 FTRs 3.1 — 7.4 — Coal contracts 0.2 0.2 0.2 0.1 Interest rate swaps — 2.8 — 0.4 Total other current 6.7 24.8 15.3 5.8 Other long-term Natural gas contracts — 0.9 0.4 0.2 Coal contracts 0.2 — 0.2 — Interest rate swaps — 3.2 — 1.9 Total other long-term 0.2 4.1 0.6 2.1 Total $ 6.9 $ 28.9 $ 15.9 $ 7.9 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 for the years ended: December 31, 2019 December 31, 2018 December 31, 2017 (in millions) Volumes Gains (Losses) Volumes Gains Volumes Gains (Losses) Natural gas contracts 183.9 Dth $ (27.1 ) 173.2 Dth $ 24.6 123.1 Dth $ (8.0 ) Petroleum products contracts — gallons — 6.0 gallons 1.6 18.0 gallons (1.3 ) FTRs 31.2 MWh 16.3 30.5 MWh 15.9 36.2 MWh 14.0 Total $ (10.8 ) $ 42.1 $ 4.7 At December 31, 2019 and 2018 , we had posted cash collateral of $34.4 million and $2.7 million , respectively, in our margin accounts. At December 31, 2018 , we had also received cash collateral of $0.2 million in our margin accounts. We had not received any cash collateral at December 31, 2019 . The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets: December 31, 2019 December 31, 2018 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 6.9 $ 28.9 $ 15.9 $ 7.9 Gross amount not offset on the balance sheet (1.4 ) (21.4 ) (1) (4.0 ) (2) (4.9 ) (3) Net amount $ 5.5 $ 7.5 $ 11.9 $ 3.0 (1) Includes cash collateral posted of $20.0 million . (2) Includes cash collateral received of $0.2 million . (3) Includes cash collateral posted of $1.1 million . Cash Flow Hedges Effective January 1, 2019, we adopted ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities. The amendments in this update expand the strategies that qualify for hedge accounting, amend the presentation and disclosure requirements related to hedging activities, and provide overall targeted improvements to simplify hedge accounting in certain situations. The adoption of this standard did not have a significant impact on our financial statements. As of December 31, 2019 , 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 qualified 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 loss and in earnings, along with our total interest expense on the income statements, for the years ended December 31 : (in millions) 2019 2018 2017 Derivative losses recognized in other comprehensive loss $ (4.8 ) $ (2.9 ) $ — Net derivative gains reclassified from accumulated other comprehensive loss to interest expense 1.1 1.6 2.2 Total interest expense line item on the income statements 501.5 445.1 415.7 We estimate that during the next twelve months, $1.0 million will be reclassified from accumulated other comprehensive loss as an increase to interest expense. |
Guarantees
Guarantees | 12 Months Ended |
Dec. 31, 2019 | |
Guarantees [Abstract] | |
GUARANTEES | GUARANTEES The following table shows our outstanding guarantees: Expiration (in millions) Total Amounts Committed at December 31, 2019 Less Than 1 Year 1 to 3 Years Over 3 Years Guarantees Guarantees supporting transactions of subsidiaries (1) $ 31.4 $ 10.2 $ 0.2 $ 21.0 Standby letters of credit (2) 103.0 1.2 0.2 101.6 Surety bonds (3) 9.9 9.9 — — Other guarantees (4) 11.7 0.9 — 10.8 Total guarantees $ 156.0 $ 22.2 $ 0.4 $ 133.4 (1) Consists of $4.0 million , $6.2 million , and $21.2 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 $11.7 million related to other indemnifications, for which a liability of $10.8 million related to workers compensation coverage was recorded on our balance sheets. |
Employee Benefits
Employee Benefits | 12 Months Ended |
Dec. 31, 2019 | |
Retirement Benefits [Abstract] | |
EMPLOYEE BENEFITS | EMPLOYEE BENEFITS Pension and Other Postretirement Employee Benefits We and our subsidiaries have defined benefit pension plans that cover substantially all of our employees, as well as several unfunded non-qualified retirement plans. In addition, we and our subsidiaries offer multiple OPEB plans to employees. The benefits for a portion of these plans are funded through irrevocable trusts, as allowed for income tax purposes. We also offer medical, dental, and life insurance benefits to active employees and their dependents. We expense the costs of these benefits as incurred. Generally, former Wisconsin Energy Corporation employees who started with the company after 1995 receive a benefit based on a percentage of their annual salary plus an interest credit, while employees who started before 1996 receive a benefit based upon years of service and final average salary. New Wisconsin Energy Corporation management employees hired after December 31, 2014, and certain new represented employees hired after May 1, 2017, receive an annual company contribution to their 401(k) savings plan instead of being enrolled in the defined benefit plans. For former Integrys employees, the defined benefit pension plans are closed to all new hires. In addition, the service accruals for the defined benefit pension plans were frozen for non-union employees as of January 1, 2013. These employees receive an annual company contribution to their 401(k) savings plan, which is calculated based on age, wages, and full years of vesting service as of December 31 each year. We use a year-end measurement date to measure the funded status of all of our pension and OPEB plans. Due to the regulated nature of our business, we have concluded that substantially all of the unrecognized costs resulting from the recognition of the funded status of our pension and OPEB plans qualify as a regulatory asset. The following tables provide a reconciliation of the changes in our plans' benefit obligations and fair value of assets: Pension Benefits OPEB Benefits (in millions) 2019 2018 2019 2018 Change in benefit obligation Obligation at January 1 $ 2,927.2 $ 3,163.7 $ 608.2 $ 818.5 Service cost 47.0 47.1 16.3 23.7 Interest cost 120.4 114.3 25.7 29.9 Participant contributions — — 12.3 15.5 Plan amendments — — (4.0 ) (3.5 ) Actuarial loss (gain) 269.3 (171.8 ) (60.7 ) (222.6 ) Benefit payments (240.2 ) (226.1 ) (42.3 ) (55.4 ) Federal subsidy on benefits paid N/A N/A 1.3 1.0 Transfer — — 1.8 1.1 Obligation at December 31 $ 3,123.7 $ 2,927.2 $ 558.6 $ 608.2 Change in fair value of plan assets Fair value at January 1 $ 2,690.8 $ 2,966.8 $ 771.7 $ 841.5 Actual return on plan assets 494.1 (122.2 ) 134.3 (35.2 ) Employer contributions 62.3 72.3 3.6 5.3 Participant contributions — — 12.3 15.5 Benefit payments (240.2 ) (226.1 ) (42.3 ) (55.4 ) Fair value at December 31 $ 3,007.0 $ 2,690.8 $ 879.6 $ 771.7 Funded status at December 31 $ (116.7 ) $ (236.4 ) $ 321.0 $ 163.5 The amounts recognized on our balance sheets at December 31 related to the funded status of the benefit plans were as follows: Pension Benefits OPEB Benefits (in millions) 2019 2018 2019 2018 Other long-term assets $ 188.8 $ 139.1 $ 341.7 $ 210.8 Pension and OPEB obligations 305.5 375.5 20.7 47.3 Total net (liabilities) assets $ (116.7 ) $ (236.4 ) $ 321.0 $ 163.5 The accumulated benefit obligation for all defined benefit pension plans was $2,992.9 million and $2,804.9 million as of December 31, 2019 and 2018 , respectively. The following table shows information for pension plans with an accumulated benefit obligation in excess of plan assets. Amounts presented are as of December 31: (in millions) 2019 2018 Projected benefit obligation $ 1,810.1 $ 1,930.8 Accumulated benefit obligation 1,754.2 1,882.2 Fair value of plan assets 1,504.6 1,572.7 The following table shows the amounts that have not yet been recognized in our net periodic benefit cost as of December 31: Pension Benefits OPEB Benefits (in millions) 2019 2018 2019 2018 Pre-tax accumulated other comprehensive loss (1) Net actuarial loss (gain) $ 10.6 $ 14.5 $ (1.6 ) $ (1.6 ) Prior service credits — — (0.1 ) (0.1 ) Total $ 10.6 $ 14.5 $ (1.7 ) $ (1.7 ) Net regulatory assets (liabilities) (2) Net actuarial loss (gain) $ 1,067.7 $ 1,184.1 $ (266.6 ) $ (133.0 ) Prior service costs (credits) 2.7 4.9 (88.6 ) (100.0 ) Total $ 1,070.4 $ 1,189.0 $ (355.2 ) $ (233.0 ) (1) Amounts related to the nonregulated entities are included in accumulated other comprehensive loss. (2) Amounts related to the utilities and WBS are recorded as net regulatory assets or liabilities. The following table shows the estimated amounts that will be amortized into net periodic benefit cost during 2020 : (in millions) Pension Benefits OPEB Benefits Net actuarial loss (gain) $ 97.1 $ (21.5 ) Prior service costs (credits) 1.6 (15.0 ) Total 2020 – estimated amortization $ 98.7 $ (36.5 ) The components of net periodic benefit cost (credit) (including amounts capitalized to our balance sheets) for the years ended December 31 were as follows: Pension Benefits OPEB Benefits (in millions) 2019 2018 2017 2019 2018 2017 Service cost $ 47.0 $ 47.1 $ 44.6 $ 16.3 $ 23.7 $ 24.1 Interest cost 120.4 114.3 121.8 25.7 29.9 32.9 Expected return on plan assets (193.3 ) (196.5 ) (195.7 ) (54.7 ) (59.5 ) (55.5 ) Plan settlement 11.5 1.0 9.0 — — — Amortization of prior service cost (credit) 2.2 2.7 2.9 (15.4 ) (15.4 ) (12.3 ) Amortization of net actuarial loss 77.3 94.0 86.1 (6.6 ) 1.0 3.1 Net periodic benefit cost (credit) $ 65.1 $ 62.6 $ 68.7 $ (34.7 ) $ (20.3 ) $ (7.7 ) The weighted-average assumptions used to determine the benefit obligations for the plans were as follows for the years ended December 31: Pension Benefits OPEB Benefits 2019 2018 2019 2018 Discount rate 3.41% 4.30% 3.39% 4.27% Rate of compensation increase 4.00% 3.66% N/A N/A Assumed medical cost trend rate (Pre 65) N/A N/A 6.00% 6.25% Ultimate trend rate (Pre 65) N/A N/A 5.00% 5.00% Year ultimate trend rate is reached (Pre 65) N/A N/A 2028 2024 Assumed medical cost trend rate (Post 65) N/A N/A 5.91% 6.01% Ultimate trend rate (Post 65) N/A N/A 5.00% 5.00% Year ultimate trend rate is reached (Post 65) N/A N/A 2028 2028 The weighted-average assumptions used to determine the net periodic benefit cost for the plans were as follows for the years ended December 31: Pension Benefits 2019 2018 2017 Discount rate 4.21% 3.71% 4.11% Expected return on plan assets 7.12% 7.12% 7.11% Rate of compensation increase 3.66% 3.66% 3.60% OPEB Benefits 2019 2018 2017 Discount rate 4.27% 3.63% 4.04% Expected return on plan assets 7.25% 7.25% 7.25% Assumed medical cost trend rate (Pre 65) 6.25% 6.50% 7.00% Ultimate trend rate (Pre 65) 5.00% 5.00% 5.00% Year ultimate trend rate is reached (Pre 65) 2024 2024 2021 Assumed medical cost trend rate (Post 65) 6.01% 6.09% 7.00% Ultimate trend rate (Post 65) 5.00% 5.00% 5.00% Year ultimate trend rate is reached (Post 65) 2028 2028 2021 We consult with our investment advisors on an annual basis to help us forecast expected long-term returns on plan assets by reviewing historical returns as well as calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the fund. For 2020 , the expected return on assets assumption is 6.87% for the pension plans and 7.00% for the OPEB plans. Assumed health care cost trend rates have a significant effect on the amounts reported by us for health care plans. For the year ended December 31, 2019 , a one-percentage-point change in assumed health care cost trend rates would have had the following effects: (in millions) 1% Increase 1% Decrease Effect on total of service and interest cost components of net periodic postretirement health care benefit cost $ 4.7 $ (3.8 ) Effect on health care component of the accumulated postretirement benefit obligations 43.5 (36.5 ) Plan Assets Current pension trust assets and amounts which are expected to be contributed to the trusts in the future are expected to be adequate to meet pension payment obligations to current and future retirees. The Investment Trust Policy Committee oversees investment matters related to all of our funded benefit plans. The Committee works with external actuaries and investment consultants on an on-going basis to establish and monitor investment strategies and target asset allocations. Forecasted cash flows for plan liabilities are regularly updated based on annual valuation results. Target allocations are determined utilizing projected benefit payment cash flows and risk analyses of appropriate investments. They are intended to reduce risk, provide long-term financial stability for the plans and maintain funded levels which meet long-term plan obligations while preserving sufficient liquidity for near-term benefit payments. The legacy Wisconsin Energy Corporation pension trust target asset allocations are 35% equity investments, 55% fixed income investments, and 10% private equity and real estate investments. The legacy Integrys pension trust target asset allocation is 45% equity investments, 45% fixed income investments, and 10% private equity and real estate investments. The two legacy Wisconsin Energy Corporation OPEB trusts' target asset allocations are 50% equity investments and 50% fixed income investments, and 70% equity investments and 30% fixed income investments, respectively. The two largest legacy OPEB trusts for Integrys have the same target asset allocations of 45% equity investments and 55% fixed income. Equity securities include investments in large-cap, mid-cap, and small-cap companies. Fixed income securities include corporate bonds of companies from diversified industries, mortgage and other asset backed securities, commercial paper, and United States Treasuries. Pension and OPEB plan investments are recorded at fair value. See Note 1(p), Fair Value Measurements, for more information regarding the fair value hierarchy and the classification of fair value measurements based on the types of inputs used. The following tables provide the fair values of our investments by asset class: December 31, 2019 Pension Plan Assets OPEB Assets (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Asset Class Equity securities: United States equity $ 335.6 $ — $ — $ 335.6 $ 103.0 $ — $ — $ 103.0 International equity 321.6 0.7 — 322.3 107.3 0.2 — 107.5 Fixed income securities: * United States bonds 94.3 887.4 — 981.7 119.1 165.9 — 285.0 International bonds 51.5 87.0 — 138.5 24.6 8.5 — 33.1 $ 803.0 $ 975.1 $ — $ 1,778.1 $ 354.0 $ 174.6 $ — $ 528.6 Investments measured at net asset value $ 1,228.9 $ 351.0 Total $ 803.0 $ 975.1 $ — $ 3,007.0 $ 354.0 $ 174.6 $ — $ 879.6 * This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries. December 31, 2018 Pension Plan Assets OPEB Assets (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Asset Class Equity securities: United States equity $ 281.7 $ — $ — $ 281.7 $ 88.2 $ — $ — $ 88.2 International equity 279.7 0.7 — 280.4 92.2 0.2 — 92.4 Fixed income securities: * United States bonds 123.7 838.8 — 962.5 119.6 150.8 — 270.4 International bonds 16.1 85.5 — 101.6 7.1 8.9 — 16.0 $ 701.2 $ 925.0 $ — $ 1,626.2 $ 307.1 $ 159.9 $ — $ 467.0 Investments measured at net asset value $ 1,064.6 $ 304.7 Total $ 701.2 $ 925.0 $ — $ 2,690.8 $ 307.1 $ 159.9 $ — $ 771.7 * This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries. The following table sets forth a reconciliation of changes in the fair value of pension and OPEB plan assets categorized as Level 3 in the fair value hierarchy: Private Equity and Real Estate International Equity (in millions) Pension OPEB Pension OPEB Beginning balance at January 1, 2018 $ 100.1 $ 7.7 $ 0.8 $ 0.2 Realized and unrealized gains (losses) 8.0 1.1 (0.1 ) — Purchases 18.3 1.5 — — Liquidations (1.7 ) (0.2 ) — — Transfers out of level 3 (124.7 ) (10.1 ) (0.7 ) (0.2 ) Ending balance at December 31, 2018 $ — $ — $ — $ — Cash Flows We expect to contribute $11.6 million to the pension plans and $0.9 million to the OPEB plans in 2020 , dependent upon various factors affecting us, including our liquidity position and the effects of the Tax Legislation. The following table shows the payments, reflecting expected future service, that we expect to make for pension and OPEB over the next 10 years: (in millions) Pension Benefits OPEB Benefits 2020 $ 236.9 $ 37.1 2021 236.7 34.7 2022 228.4 35.6 2023 226.8 36.1 2024 218.8 36.1 2025-2029 1,004.2 179.5 Savings Plans We sponsor 401(k) savings plans which allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with plan-specified guidelines. A percentage of employee contributions are matched by us through a contribution into the employee's savings plan account, up to certain limits. The 401(k) savings plans include an Employee Stock Ownership Plan. Certain employees receive an employer retirement contribution, in which amounts are contributed to the employee's savings plan account based on the employee's wages, age, and years of service. Total costs incurred under all of these plans were $50.9 million , $49.3 million , and $47.9 million in 2019 , 2018 , and 2017 , respectively. |
Investment in Transmission Affi
Investment in Transmission Affiliates | 12 Months Ended |
Dec. 31, 2019 | |
Equity Method Investments and Joint Ventures [Abstract] | |
INVESTMENT IN TRANSMISSION AFFILATES | INVESTMENT IN TRANSMISSION AFFILIATES We own approximately 60% of ATC, a for-profit, transmission-only company regulated by the FERC for cost of service and certain state regulatory commissions for routing and siting of transmission projects. We also own approximately 75% of ATC Holdco, a separate entity formed in December 2016 to invest in transmission-related projects outside of ATC's traditional footprint. The corporate managers for ATC and ATC Holdco each have a ten -member board of directors. We have one representative on each board. Each member of the board has only one vote. Due to voting requirements, each individual board member has 10% of the voting control. The following tables provide a reconciliation of the changes in our investments in ATC and ATC Holdco: 2019 (in millions) ATC ATC Holdco Total Balance at January 1 $ 1,625.3 $ 40.0 $ 1,665.3 Add: Earnings (loss) from equity method investment * 132.8 (5.2 ) 127.6 Add: Capital contributions 51.3 1.3 52.6 Less: Distributions 124.7 — 124.7 Balance at December 31 $ 1,684.7 $ 36.1 $ 1,720.8 * In November 2019, the FERC issued an order that addressed the complaints related to ATC's allowed ROE. Due to the numerous rehearing requests filed related to this order, our financials continue to include a $41.9 million liability for potential future refunds that ATC may be required to provide, resulting in reduced equity earnings from ATC. This liability reflects a 10.38% ROE for all periods covered by the complaints. 2018 (in millions) ATC ATC Holdco Total Balance at January 1 $ 1,515.8 $ 37.6 $ 1,553.4 Add: Earnings (loss) from equity method investment 139.6 (2.9 ) 136.7 Add: Capital contributions 48.2 5.3 53.5 Less: Distributions 78.2 — 78.2 Less: Other 0.1 — 0.1 Balance at December 31 $ 1,625.3 $ 40.0 $ 1,665.3 2017 (in millions) ATC ATC Holdco Total Balance at January 1 $ 1,443.9 (1) $ — $ 1,443.9 Add: Earnings (loss) from equity method investment 166.0 (11.7 ) 154.3 Add: Capital contributions 60.3 49.3 109.6 Less: Distributions 154.2 (2) — 154.2 Less: Other 0.2 — 0.2 Balance at December 31 $ 1,515.8 $ 37.6 $ 1,553.4 (1) Distributions of $35.2 million , received in the first quarter of 2017, were approved and recorded as a receivable from ATC in other current assets at December 31, 2016 . (2) Of this amount, $39.9 million was recorded as a receivable from ATC in other current assets at December 31, 2017 . 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 required to pay the cost of needed transmission infrastructure upgrades for new generation projects while the projects are under construction. ATC reimburses us for these costs when the new generation is placed in service. The following table summarizes our significant related party transactions with ATC during the years ended December 31: (in millions) 2019 2018 2017 Charges to ATC for services and construction $ 25.9 $ 21.8 $ 17.1 Charges from ATC for network transmission services 348.1 338.1 349.3 Refund from ATC related to a FERC audit — 22.0 — Refund from ATC per FERC ROE order — — 28.3 As of December 31, 2019 and 2018 , our balance sheets included the following receivables and payables for services received from or provided to ATC: (in millions) 2019 2018 Accounts receivable for services provided to ATC $ 3.5 $ 3.4 Accounts payable for services received from ATC 29.0 28.2 Amounts due from ATC for transmission infrastructure upgrades 2.8 (1) 29.4 (2) (1) In connection with WPS's construction of its two new solar projects, Badger Hollow I and Two Creeks, WPS was required to initially fund the construction of the transmission infrastructure upgrades needed for the new generation. ATC owns these transmission assets and will reimburse WPS for these costs after the new generation has been placed in service. (2) In connection with UMERC's construction of the new natural gas-fired generation in the Upper Peninsula of Michigan, UMERC was required to initially fund the construction of the transmission infrastructure upgrades owned by ATC that were needed for the new generation. In the second quarter of 2019, ATC fully reimbursed UMERC for these costs. Summarized financial data for ATC is included in the tables below: Year Ended December 31 (in millions) 2019 2018 2017 Income statement data Operating revenues $ 744.4 $ 690.5 $ 721.7 Operating expenses 373.5 358.7 345.0 Other expense, net 110.5 108.3 104.1 Net income $ 260.4 $ 223.5 $ 272.6 (in millions) December 31, 2019 December 31, 2018 Balance sheet data Current assets $ 84.7 $ 87.2 Noncurrent assets 5,244.2 4,928.8 Total assets $ 5,328.9 $ 5,016.0 Current liabilities $ 502.6 $ 640.0 Long-term debt 2,312.8 2,014.0 Other noncurrent liabilities 298.9 295.3 Shareholders' equity 2,214.6 2,066.7 Total liabilities and shareholders' equity $ 5,328.9 $ 5,016.0 |
Segment Information
Segment Information | 12 Months Ended |
Dec. 31, 2019 | |
Segment Reporting [Abstract] | |
SEGMENT INFORMATION | SEGMENT INFORMATION We use operating income to measure segment profitability and to allocate resources to our businesses. At December 31, 2019 , 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 and non-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, and ▪ 80% ownership interest in Upstream, located in Antelope County, Nebraska. See Note 2, Acquisitions, for more information on Bluewater, Bishop Hill III, Coyote Ridge, and Upstream. • The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, the PELLC holding company, Wispark, Bostco, Wisvest, WECC, WBS, and PDL. In the first quarter of 2017, we sold substantially all of the remaining assets of Bostco, and, in October 2018, Bostco was dissolved. In 2019, we sold certain PDL solar power generating facilities. See Note 3, Dispositions, for more information on these sales. All of our operations and assets are located within the United States. The following tables show summarized financial information related to our reportable segments for the years ended December 31, 2019 , 2018 , and 2017 . Utility Operations 2019 (in millions) Wisconsin Illinois Other States Total Utility Operations Electric Transmission Non-Utility Energy Infrastructure Corporate and Other Reconciling Eliminations WEC Energy Group Consolidated External revenues $ 5,647.1 $ 1,357.1 $ 426.0 $ 7,430.2 $ — $ 88.5 $ 4.4 $ — $ 7,523.1 Intersegment revenues — — — — — 407.4 — (407.4 ) — Other operation and maintenance 1,591.3 461.1 98.5 2,150.9 — 19.7 14.0 0.2 2,184.8 Depreciation and amortization 617.0 181.3 27.5 825.8 — 92.0 24.3 (15.8 ) 926.3 Operating income (loss) 1,189.6 291.9 65.3 1,546.8 — 366.6 (34.4 ) (347.6 ) 1,531.4 Equity in earnings of transmission affiliates — — — — 127.6 — — — 127.6 Interest expense 572.0 59.0 8.5 639.5 13.1 62.1 140.9 (354.1 ) 501.5 Capital expenditures and asset acquisitions 1,378.6 624.9 109.1 2,112.6 — 389.9 26.5 — 2,529.0 Total assets * 23,934.8 6,932.5 1,237.8 32,105.1 1,723.1 3,654.1 814.0 (3,344.5 ) 34,951.8 * Total assets at December 31, 2019 reflect an elimination of $1,896.7 million for all lease activity between We Power and WE. Utility Operations 2018 (in millions) Wisconsin Illinois Other States Total Utility Operations Electric Transmission Non-Utility Energy Infrastructure Corporate and Other Reconciling Eliminations WEC Energy Group Consolidated External revenues $ 5,794.7 $ 1,400.0 $ 438.2 $ 7,632.9 $ — $ 37.9 $ 8.7 $ — $ 7,679.5 Intersegment revenues — — — — — 430.5 — (430.5 ) — Other operation and maintenance 2,076.1 472.3 101.0 2,649.4 — 12.6 1.8 (393.3 ) 2,270.5 Depreciation and amortization 546.6 170.3 24.1 741.0 — 75.7 29.1 — 845.8 Operating income (loss) 800.2 255.8 68.8 1,124.8 — 365.8 (22.2 ) — 1,468.4 Equity in earnings of transmission affiliates — — — — 136.7 — — — 136.7 Interest expense 200.7 51.2 8.7 260.6 0.3 63.7 125.8 (5.3 ) 445.1 Capital expenditures and asset acquisitions 1,466.1 547.1 103.6 2,116.8 — 260.6 39.7 — 2,417.1 Total assets * 23,407.0 6,483.3 1,147.9 31,038.2 1,665.3 3,227.2 959.6 (3,414.5 ) 33,475.8 * Total assets at December 31, 2018 reflect an elimination of $1,968.5 million for all lease activity between We Power and WE. Utility Operations 2017 (in millions) Wisconsin Illinois Other States Total Utility Operations Electric Transmission Non-Utility Energy Infrastructure Corporate and Other Reconciling Eliminations WEC Energy Group Consolidated External revenues $ 5,829.2 $ 1,355.5 $ 411.2 $ 7,595.9 $ — $ 38.9 $ 13.7 $ — $ 7,648.5 Intersegment revenues — — — — — 446.3 — (446.3 ) — Other operation and maintenance 1,923.2 464.2 101.1 2,488.5 — 7.3 1.4 (441.1 ) 2,056.1 Depreciation and amortization 523.9 152.6 24.8 701.3 — 71.4 25.9 — 798.6 Operating income (loss) 1,055.2 279.9 54.4 1,389.5 — 400.5 (13.9 ) — 1,776.1 Equity in earnings of transmission affiliates — — — — 154.3 — — — 154.3 Interest expense 193.7 45.0 8.7 247.4 — 62.8 107.3 (1.8 ) 415.7 Capital expenditures 1,152.3 545.2 74.5 1,772.0 — 35.4 152.1 — 1,959.5 Total assets * 22,237.1 6,144.7 1,067.8 29,449.6 1,593.4 2,992.8 953.6 (3,398.9 ) 31,590.5 * Total assets at December 31, 2017 reflect an elimination of $2,038.1 million for all lease activity between We Power and WE. |
Variable Interest Entities
Variable Interest Entities | 12 Months Ended |
Dec. 31, 2019 | |
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 power purchase agreements, 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 December 31, 2019 and 2018 , our equity investment in ATC was $1,684.7 million and $1,625.3 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 December 31, 2019 and 2018 , our equity investment in ATC Holdco was $36.1 million and $40.0 million , respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC Holdco. See Note 20, 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 power purchase agreement 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 two years . 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 power purchase agreement. We have $22.4 million of required capacity payments over the remaining term of this agreement. We believe that the required capacity payments under this contract will continue to be recoverable in rates, and our maximum exposure to loss is limited to these capacity payments. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2019 | |
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. Our non-utility energy infrastructure generation facilities have obligations to distribute and sell electricity through long-term offtake agreements with their customers for all of the energy produced. These projects also enter into related easements and other agreements associated with the generating facilities. The following table shows our minimum future commitments related to these purchase obligations as of December 31, 2019 , including those of our subsidiaries. Payments Due By Period (in millions) Date Contracts Extend Through Total Amounts Committed 2020 2021 2022 2023 2024 Later Years Electric utility: Nuclear 2033 $ 8,319.0 $ 475.1 $ 501.1 $ 531.2 $ 563.0 $ 596.8 $ 5,651.8 Coal supply and transportation 2024 983.2 306.9 255.7 223.4 196.5 0.7 — Purchased power 2051 428.3 88.9 58.5 51.5 46.5 43.4 139.5 Natural gas utility: Supply and transportation 2048 1,652.3 344.8 285.5 224.6 131.2 70.8 595.4 Non-utility energy infrastructure: Purchased power 2061 173.6 7.7 8.8 8.6 8.8 8.9 130.8 Natural gas storage and transportation 2048 13.6 7.7 2.7 1.3 0.8 0.1 1.0 Total $ 11,570.0 $ 1,231.1 $ 1,112.3 $ 1,040.6 $ 946.8 $ 720.7 $ 6,518.5 Environmental Matters Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as SO 2 , NOx, fine particulates, mercury, and GHGs; water intake and discharges; management of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites. We have continued to pursue a proactive strategy to manage our environmental compliance obligations, including: • the development of additional sources of renewable electric energy supply; • the addition of improvements for water quality matters such as treatment technologies to meet regulatory discharge limits and improvements to our cooling water intake systems; • the addition of emission control equipment to existing facilities to comply with ambient air quality standards and federal clean air rules; • the protection of wetlands and waterways, threatened and endangered species, and cultural resources associated with utility construction projects; • the retirement of older coal-fired power plants and conversion to modern, efficient, natural gas generation, super-critical pulverized coal generation, and/or replacement with renewable generation; • the beneficial use of ash and other products from coal-fired and biomass generating units; and • the remediation of 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, which lowered the limit for ground-level ozone, creating a more stringent standard than the 2008 NAAQS. The EPA issued final nonattainment area designations in April 2018. The following counties within our service territories were designated as partial nonattainment: Door, Kenosha, Manitowoc, Northern Milwaukee/Ozaukee, and Sheboygan shorelines. This re-designation was challenged in the D.C. Circuit Court of Appeals in Clean Wisconsin et al. v. U.S. Environmental Protection Agency. Petitioners in that case have argued that additional portions of Milwaukee, Waukesha, Ozaukee, and Washington Counties (among others) should be designated as nonattainment for ozone. In November 2019, the D.C. Circuit Court of Appeals heard oral arguments for that case. A decision is expected in spring 2020, and we expect that any subsequent EPA re-designation, if necessary, would take place in mid-2021. We believe we are well positioned to meet the requirements associated with the ozone standard and do not expect to incur significant costs to comply. The State of Wisconsin is currently working with stakeholders, including us, in developing regulations for inclusion in the state implementation plan required by the rule. Mercury and Air Toxics Standards In December 2018, the EPA proposed to revise the Supplemental Cost Finding for the MATS rule as well as the CAA required RTR. The EPA was required by the United States Supreme Court to review both costs and benefits of complying with the MATS rule. After its review of costs, the EPA determined that it is not appropriate and necessary to regulate hazardous air pollutant emissions from power plants under Section 112 of the CAA. As a result, under the proposed rule, the emission standards and other requirements of the MATS rule first enacted in 2012 would remain in place. The EPA is not proposing to remove coal- and oil-fired power plants from the list of sources that are regulated under Section 112. The EPA also proposes that no revisions to MATS are warranted based on the results of the RTR. As a result, we do not expect the proposed rule to have a material impact on our financial condition or operations. Climate Change The ACE rule became effective in September 2019. This rule provides existing coal-fired generating units with standards for achieving GHG emission reductions. The rule was finalized in conjunction with two other separate and distinct rulemakings, (1) the repeal of the Clean Power Plan, and (2) revised implementing regulations for ACE, ongoing emissions guidelines, and all future emission guidelines for existing sources issued under CAA section 111(d). Every state's plan to implement ACE is required to focus on reducing GHG emissions by improving the efficiency of fossil-fueled power plants. The rule is being litigated in challenges brought in the D.C. Circuit Court of Appeals by 22 states (including Illinois, Michigan, Minnesota, and Wisconsin), local governments, and certain nongovernmental organizations. This litigation is proceeding, but has not yet been scheduled for oral argument. The WDNR is working with state utilities and has begun the process of developing the implementation plan with respect to the ACE rule. In December 2018, the EPA proposed to revise the New Source Performance Standards for GHG emissions from new, modified, and reconstructed fossil-fueled power plants. The EPA determined that the BSER for new, modified, and reconstructed coal units is highly efficient generation that would be equivalent to supercritical steam conditions for larger units and subcritical steam conditions for smaller units. This proposed BSER would replace the determination from the previous rule, which identified BSER as partial carbon capture and storage. In April 2019, we issued a climate report, which analyzes our GHG reduction goals with respect to international efforts to limit future global temperature increases to less than two degrees Celsius. We will evaluate potential GHG reduction pathways as climate change policies and relevant technologies evolve over time. We continue to evaluate opportunities and actions that preserve fuel diversity, lower costs for our customers, and contribute toward long-term GHG emissions reductions. Our current plan is to work with our industry peers, environmental groups, public policy makers, and customers, with goals of reducing CO 2 emissions. In 2019, we met and exceeded our 2030 goal of reducing CO 2 emissions by 40% below 2005 levels, and are re-evaluating our longer-term CO 2 reduction goals. As a result of our generation reshaping plan, we retired approximately 1,800 MW of coal generation since the beginning of 2018, including the 2018 retirements of the Pleasant Prairie power plant, the Pulliam power plant, and the jointly-owned Edgewater Unit 4 generating units as well as the March 2019 retirement of the PIPP. See Note 6, Property, Plant, and Equipment, for more information . We also have a goal to decrease the rate of methane emissions from the natural gas distribution lines in our network by 30% per mile by the year 2030 from a 2011 baseline. We were over half way toward meeting that goal at the end of 2019. We are required to report our CO 2 equivalent emissions from our electric generating facilities under the EPA Greenhouse Gases Reporting Program. Based upon our analysis of the data, we reported CO 2 equivalent emissions of 21.8 million metric tonnes and 26.4 million metric tonnes to the EPA for 2019 and 2018 , respectively. The level of CO 2 and other GHG emissions varies from year to year and is dependent on the level of electric generation and mix of fuel sources, which is determined primarily by demand, the availability of the generating units, the unit cost of fuel consumed, and how our units are dispatched by MISO. We are also required to report CO 2 equivalent emissions related to the natural gas that our natural gas utilities distribute and sell. Based upon our analysis of the data, we reported CO 2 equivalent emissions of 29.4 million metric tonnes to the EPA for 2019 and 2018 . 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 VAPP. Although we currently believe that existing technology at the PWGS satisfies the BTA requirements, final determinations will not be made until the discharge permit is renewed for this facility, which is expected to be in 2021. Until that time, we cannot determine what, if any, intake structure or operational modifications will be required to meet the new BTA requirements for this facility. 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 meet the regulation and do not expect to incur significant costs to comply with this regulation. Steam Electric Effluent Limitation Guidelines The EPA's final 2015 ELG rule took effect in January 2016. 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. As a result of past capital investments at WE and WPS, we believe our fleet is well positioned to meet the existing ELG regulations. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. There will, however, need to be modifications to the BATW systems at Weston Unit 3 and OC 7 and OC 8. Also, one wastewater treatment system modification may be required for the wet FGD discharges from the six units that make up the OCPP and ERGS. Based on preliminary engineering, we estimate that compliance with the current rule will require $60 million in capital costs. The ELG requirements for BATW and wet FGD systems are currently being re-evaluated by the EPA. In September 2017, the EPA issued a final rule (Postponement Rule) to postpone the earliest compliance date to November 1, 2020 for the BATW and wet FGD wastewater requirements while it reconsiders the ELG rule. The Postponement Rule left unchanged the latest ELG rule compliance date of December 31, 2023. In November 2019, the EPA Administrator signed the proposed ELG Reconsideration Rule to revise the treatment technology requirements related to BATW and wet FGD wastewaters at existing facilities. The EPA also proposed a provision that exempts facility owners from the new BATW and wet FGD requirements if a generating unit is retired by December 31, 2028. We expect the rule to be finalized in late 2020. In the meantime, we are currently evaluating what impact, if any, the proposed rule would have on our estimated compliance cost. Land Quality Manufactured Gas Plant Remediation We have identified sites at which our utilities or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. Our natural gas utilities are responsible for the environmental remediation of these sites, some of which are in the EPA Superfund Alternative Approach Program. We are also working with various state jurisdictions in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure. In addition, we are coordinating the investigation and cleanup of some of these sites subject to the jurisdiction of the EPA under what is called a "multisite" program. This program involves prioritizing the work to be done at the sites, preparation and approval of documents common to all of the sites, and use of a consistent approach in selecting remedies. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below. The future costs for detailed site investigation, future remediation, and monitoring are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation. Historically, our regulators have allowed us to recover incurred costs, net of insurance recoveries and recoveries from potentially responsible parties, associated with the remediation of manufactured gas plant sites. Accordingly, we have established regulatory assets for costs associated with these sites. We have established the following regulatory assets and reserves for manufactured gas plant sites as of December 31: (in millions) 2019 2018 Regulatory assets $ 685.5 $ 687.1 Reserves for future environmental remediation 589.2 616.4 Renewables, Efficiency, and Conservation Wisconsin Legislation In 2005, Wisconsin enacted Act 141, which established a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources annually. WE and WPS have achieved their required renewable energy percentages of 8.27% and 9.74% , respectively, and met their compliance requirements by constructing various wind parks, a biomass facility, and by also relying on renewable energy purchases. WE and WPS continue to review their renewable energy portfolios and acquire cost-effective renewables as needed to meet their requirements on an ongoing basis. The PSCW administers the renewable program related to Act 141, and each utility funds the program based on 1.2% of its annual retail operating revenues. Michigan Legislation In December 2016, Michigan enacted Act 342, which requires 12.5% of the state's electric energy to come from renewables for years 2019 through 2020, and energy optimization (efficiency) targets up to 1% annually. The renewable requirement is increased to 15.0% for 2021. UMERC was in compliance with these requirements as of December 31, 2019 . The legislation continues to allow recovery of costs incurred to meet the standards and provides for ongoing review and revision to assure the measures taken are cost-effective. Enforcement and Litigation Matters We and our subsidiaries are involved in legal and administrative proceedings before various courts and agencies with respect to matters arising in the ordinary course of business. Although we are unable to predict the outcome of these matters, management believes that appropriate reserves have been established and that final settlement of these actions will not have a material effect on our financial condition or results of operations. Consent Decrees Wisconsin Public Service Corporation – Weston and Pulliam Power Plants In November 2009, the EPA issued an NOV to WPS, which alleged violations of the CAA's New Source Review requirements relating to certain projects completed at the Weston and Pulliam power plants from 1994 to 2009. WPS entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Eastern District of Wisconsin in March 2013. With the retirement of Pulliam Units 7 and 8 in October 2018, WPS completed the mitigation projects required by the Consent Decree and received a completeness letter from the EPA in October 2018. See Note 6, Property, Plant, and Equipment, for more information about the retirement of the Pulliam units. We plan to request termination of the WPS Consent Decree during 2020. Joint Ownership Power Plants – Columbia and Edgewater In December 2009, the EPA issued an NOV to Wisconsin Power and Light, 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, 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. See Note 6, Property, Plant, and Equipment, for more information about the retirement. WE paid an immaterial portion of the assessed penalty but has no further obligations under the Consent Decree. |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | 12 Months Ended |
Dec. 31, 2019 | |
Supplemental Cash Flow Information [Abstract] | |
SUPPLEMENTAL CASH FLOW INFORMATION | SUPPLEMENTAL CASH FLOW INFORMATION Year Ended December 31 (in millions) 2019 2018 2017 Cash paid for interest, net of amount capitalized $ 485.9 $ 441.5 $ 413.7 Cash paid (received) for income taxes, net (24.9 ) 16.3 (5.2 ) Significant non-cash investing and financing transactions: Accounts payable related to construction costs 159.9 65.9 169.2 Capital contributions from noncontrolling interest 21.0 — — Receivable related to corporate-owned life insurance proceeds — 7.7 — Portion of Bostco real estate holdings sale financed with note receivable * — — 7.0 * See Note 3, Dispositions, for more information on this sale. 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 Bishop Hill III and Upstream during August 2018 and January 2019, respectively. 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. See Note 2, Acquisitions, for more information on the acquisitions of Bishop Hill III and Upstream. The following table reconciles the cash, cash equivalents, and restricted cash amounts reported within the balance sheets at December 31 to the total of these amounts shown on the statements of cash flows: (in millions) 2019 2018 2017 Cash and cash equivalents $ 37.5 $ 84.5 $ 38.9 Restricted cash included in other current assets — 2.5 — Restricted cash included in other long term assets 44.8 59.1 19.7 Cash, cash equivalents, and restricted cash $ 82.3 $ 146.1 $ 58.6 |
Regulatory Environment
Regulatory Environment | 12 Months Ended |
Dec. 31, 2019 | |
Regulated Operations [Abstract] | |
REGULATORY ENVIRONMENT | REGULATORY ENVIRONMENT Tax Cuts and Jobs Act of 2017 Due to the Tax Legislation, our regulated utilities deferred for return to ratepayers, through future refunds, bill credits, riders, or reductions in other regulatory assets, the estimated tax benefit of $2,529 million that resulted from the revaluation of deferred taxes. The Tax Legislation also reduced the corporate federal tax rate from a maximum of 35% to a 21% rate, effective January 1, 2018. We have received written orders from the PSCW and the MPSC addressing the refunding of certain of these tax benefits to ratepayers in Wisconsin and Michigan, respectively. The ICC has approved the VITA in Illinois, and the MPUC addressed the impacts to MERC in its 2018 rate order. See the Variable Income Tax Adjustment Rider discussion and the 2018 Minnesota Rate Order discussion below for more information. A summary of the Wisconsin and Michigan orders is outlined below. Wisconsin In May 2018, the PSCW issued an order regarding the benefits associated with the Tax Legislation. The PSCW order required WE's and WPS’s electric utility operations to use 80% and 40% , respectively, of the current 2018 and 2019 tax benefits to reduce certain regulatory assets. The remaining 20% and 60% at WE and WPS, respectively, was to be returned to electric customers in the form of bill credits. For our Wisconsin natural gas utility operations, the PSCW indicated that 100% of the current 2018 and 2019 tax benefits should be returned to natural gas customers in the form of bill credits. Regarding the net tax benefit associated with the revaluation of deferred taxes, amortization required in accordance with normalization accounting was used to reduce certain regulatory assets for our electric utilities and was deferred at our natural gas utilities. The timing and method of returning the remaining net tax benefit associated with the revaluation of deferred taxes was addressed in the rate orders issued by the PSCW in December 2019. See the 2020 and 2021 Rates discussion below for more information. Michigan In February 2018, the MPSC issued an order requiring Michigan utilities to make three filings related to the Tax Legislation. The first of those filings, which was filed in March 2018, prospectively addressed the impact on base rates for the change in tax expense resulting from the federal tax rate reduction from 35% to 21%. MGU and UMERC proposed providing a volumetric bill credit, subject to reconciliation and true up. In May 2018, the MPSC issued orders approving settlements that resulted in volumetric bill credits for all of MGU's and UMERC's customers effective July 1, 2018. The bill credits will remain in effect until each company's next rate proceeding. The second filing, which was filed in July 2018, addressed the impact on base rates for the change in tax expense resulting from the federal tax rate reduction from 35% to 21% from January 1, 2018 until July 1, 2018. MGU and UMERC proposed to return the tax savings from these months to customers via volumetric bill credits over multiple months. The MPSC issued orders approving settlements in September 2018. In accordance with the settlement orders, the savings were returned to MGU's and UMERC's customers via volumetric bill credits that were in effect from October 1, 2018 through December 31, 2018. The third filing was filed in October 2018 and addressed the remaining impacts of the Tax Legislation on base rates – most notably the re-measurement of deferred tax balances. MGU and UMERC proposed providing a volumetric bill credit, subject to reconciliation and true up, to return these remaining impacts of the Tax Legislation to customers. The MPSC issued orders approving settlements in May 2019. The settlement orders provide for volumetric bill credits to MGU's and UMERC's customers effective June 1, 2019. The bill credits will remain in effect until each company's next rate proceeding. WE, which served one retail electric customer in Michigan, reached a settlement with that customer. That settlement was approved by the MPSC in May 2018 and addressed all base rate impacts of the Tax Legislation, which were returned to the customer through bill credits. Wisconsin Electric Power Company, Wisconsin Public Service Corporation, and Wisconsin Gas LLC 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. On December 19, 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 are being amortized in 2020 and approximately $39 million will be amortized in 2021. The unprotected deferred tax benefits related to the unrecovered balances of WE's recently retired plants and its SSR regulatory asset are being 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 will be made to customers evenly over two years , with half being returned in 2020 and the remainder 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 will seek a financing order from the PSCW 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. The securitization will 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 the new 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. 2018 and 2019 Rates During April 2017, WE, WPS, and WG filed an application with the PSCW for approval of a settlement agreement they made with several of their commercial and industrial customers regarding 2018 and 2019 base rates. In September 2017, the PSCW issued an order that approved the settlement agreement, which froze base rates through 2019 for electric, natural gas, and steam customers of WE, WPS, and WG. Based on the PSCW order, the authorized ROE for WE, WPS, and WG remained at 10.2% , 10.0% , and 10.3% , respectively, and the capital cost structure for all of our Wisconsin utilities remained unchanged through 2019. In addition to freezing base rates, the settlement agreement extended and expanded the electric real-time market pricing program options for large commercial and industrial customers and mitigated the continued growth of certain escrowed costs at WE during the base rate freeze period by accelerating the recognition of certain tax benefits. WE was flowing through the tax benefit of its repair-related deferred tax liabilities in 2018 and 2019, to maintain certain regulatory asset balances at their December 31, 2017 levels. While WE would typically follow the normalization accounting method and utilize the tax benefits of the deferred tax liabilities in rate-making as an offset to rate base, benefiting customers over time, the federal tax code does allow for passing these tax repair-related benefits to ratepayers much sooner using the flow through accounting method. The flow through treatment of the repair-related deferred tax liabilities offset the negative income statement impact of holding the regulatory assets level, resulting in no change to net income. The agreement also allowed WPS to extend through 2019, the deferral for the revenue requirement of ReACT™ costs above the authorized $275.0 million level, and other deferrals related to WPS's electric real-time market pricing program and network transmission expenses. Pursuant to the settlement agreement, WPS also agreed to adopt, beginning in 2018, the earnings sharing mechanism that had been in place for WE and WG since January 2016, and all three utilities agreed to keep the mechanism in place through 2019. Under this earnings sharing mechanism, if WE, WPS, or WG earned above its authorized ROE, 50% of the first 50 basis points of additional utility earnings were required to be refunded to customers. All utility earnings above the first 50 basis points were also required to be refunded to customers. Liquefied Natural Gas Facilities On November 1, 2019, WE and WG filed a joint application with the PSCW requesting approval for each company to construct its own LNG facility. If approved, each facility would provide one billion cubic feet of natural gas supply to meet peak demand without requiring the construction of additional interstate pipeline capacity. These facilities are expected to reduce the likelihood of constraints on WE's and WG's natural gas systems during the highest demand days of winter. The total cost of both projects is estimated to be approximately $370 million , with approximately half being invested by each utility. Commercial operation of the LNG facilities is targeted for the end of 2023. Solar Generation Projects On August 1, 2019, WE, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire an ownership interest in a proposed solar project, Badger Hollow II, that will be located in Iowa County, Wisconsin. Once constructed, WE will own 100 MW of the output of this project. WE's share of the cost of this project is estimated to be $130 million . At its meeting on February 20, 2020, the PSCW approved the acquisition of this project. The approval is still subject to WE's receipt and review of a final written order from the PSCW. Commercial operation of Badger Hollow II is targeted for the end of 2021. In May 2018, WPS, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire ownership interests in two solar projects in Wisconsin. Badger Hollow I is located in Iowa County, Wisconsin, and Two Creeks is located in Manitowoc County, Wisconsin. Once constructed, WPS will own 100 MW of the output of each project for a total of 200 MW. WPS's share of the cost of both projects is estimated to be $256 million . The PSCW approved the acquisition of these two projects in April 2019. Commercial operation of both projects is targeted for the end of 2020. Acquisition of a Wind Energy Generation Facility in Wisconsin In October 2017, WPS, along with two other unaffiliated utilities, entered into an agreement to purchase Forward Wind Energy Center, which consists of 86 wind turbines located in Wisconsin with a total capacity of 138 MW. The FERC approved the transaction in January 2018, and the PSCW approved the transaction in March 2018. The transaction closed in April 2018. See Note 2, Acquisitions , for more information. Natural Gas Storage Facilities in Michigan In January 2017, we signed an agreement for the acquisition of Bluewater. Bluewater owns natural gas storage facilities in Michigan that provide approximately one-third of the current storage needs for the natural gas operations of WE, WPS, and WG. As a result of this agreement, WE, WPS, and WG filed a request with the PSCW in February 2017 for a declaratory ruling on various items associated with the storage facilities. In the filing, WE, WPS, and WG requested that the PSCW review and confirm the reasonableness and prudency of their potential long-term storage service agreements and interstate natural gas transportation contracts related to the storage facilities. WE, WPS, and WG also requested approval to amend our Affiliated Interest Agreement to ensure WBS and our other subsidiaries could provide services to the storage facilities. During June 2017, the PSCW granted, subject to various conditions, these declarations and approvals, and we acquired Bluewater on June 30, 2017. In September 2017, WE, WPS, and WG entered into the long-term service agreements for the natural gas storage, which were approved by the PSCW in November 2017. See Note 2, Acquisitions , for more information. The Peoples Gas Light and Coke Company and North Shore Gas Company Illinois Proceedings In December 2015, the ICC ordered a series of stakeholder workshops to evaluate PGL's SMP, which were completed in March 2016. In July 2016, the ICC initiated a proceeding to review, among other things, the planning, reporting, and monitoring of the program, including the target end date for the program, and issued a final order in January 2018. The order did not have a significant impact on PGL's existing SMP design and execution. An appeal related to the final order was filed by the Illinois AG in April 2018. In June 2019, the Illinois Appellate Court issued its ruling affirming the ICC’s final order. The appeal period has since expired for this ruling. Qualifying Infrastructure Plant Rider In July 2013, Illinois Public Act 98-0057, The Natural Gas Consumer, Safety & Reliability Act, became law. This law provides PGL 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 September 2013, PGL filed with the ICC requesting the proposed rider, which was approved in January 2014. PGL's QIP rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. In March 2019, PGL filed its 2018 reconciliation with the ICC, which, along with the 2017 and 2016 reconciliations, are still pending. In July 2019, the ICC approved a settlement of the 2015 reconciliation, which included a rate base reduction of $7.0 million and a $7.3 million refund to ratepayers. As of December 31, 2019 , all amounts had been refunded. As of December 31, 2019 , 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. Variable Income Tax Adjustment Rider In April 2018, the ICC approved the VITA proposed by PGL and NSG. The VITA recovers or refunds changes in income tax expense resulting from differences in income tax rates and amortization of deferred tax excesses and deficiencies (in accordance with the Tax Legislation) from the amounts used in the last PGL and NSG rate case, effective January 25, 2018. Minnesota Energy Resources Corporation 2018 Minnesota Rate Order In October 2017, MERC initiated a rate proceeding with the MPUC. In December 2018, the MPUC issued a final written order for MERC. The order authorized a retail natural gas rate increase of $3.1 million ( 1.26% ). The rates reflect a 9.7% ROE and a common equity component average of 50.9% . The final rates were implemented on July 1, 2019. The final approved rate increase was lower than the interim rates collected from customers during 2018 and through June 30, 2019. Therefore, MERC refunded $8.2 million to its customers during the second half of 2019. The final order addressed the various impacts of the Tax Legislation, including the remeasurement of deferred tax balances. All of the impacts from the Tax Legislation have been included in base rates. The order also approved MERC's continued use of its decoupling mechanism for residential customers. Effective January 1, 2019, MERC's small commercial and industrial customers are no longer included in the decoupling mechanism. Michigan Gas Utilities Corporation 2021 Rate Application On February 3, 2020, MGU provided notification to the MPSC of its intent to file an application requesting an increase to its natural gas rates. The application is expected to be filed in March 2020 and to request new rates be effective January 1, 2021. MGU is currently in the process of evaluating its rate request. Upper Michigan Energy Resources Corporation Formation of Upper Michigan Energy Resources Corporation In December 2016, both the MPSC and the PSCW approved the operation of UMERC as a stand-alone utility in the Upper Peninsula of Michigan, and UMERC became operational effective January 1, 2017. This utility holds the electric and natural gas distribution assets, previously held by WE and WPS, located in the Upper Peninsula of Michigan. In August 2016, we entered into an agreement with Tilden under which Tilden agreed to purchase electric power from UMERC for its iron ore mine for 20 years , contingent upon UMERC's construction of approximately 180 MW of natural gas-fired generation in the Upper Peninsula of Michigan. In October 2017, the MPSC approved both the agreement with Tilden and UMERC's application for a certificate of necessity to begin construction of the proposed generation. On March 31, 2019, UMERC's new generation solution in the Upper Peninsula began commercial operation, and the agreement with Tilden became effective. The cost of the new units was approximately $242 million ( $255 million with AFUDC), 50% of which is expected to be recovered from Tilden, with the remaining 50% expected to be recovered from UMERC's other utility customers. Tilden remained a customer of WE until the new generation began commercial operation. |
Other Income, Net
Other Income, Net | 12 Months Ended |
Dec. 31, 2019 | |
Other Income and Expenses [Abstract] | |
OTHER INCOME, NET | OTHER INCOME, NET Total other income, net was as follows for the years ended December 31 : (in millions) 2019 2018 2017 AFUDC – Equity $ 14.4 $ 15.2 $ 11.4 Non-service components of net periodic benefit costs 36.2 26.0 9.1 Gains (losses) from investments held in rabbi trust 21.2 (1.8 ) 21.5 Other, net 30.4 30.9 31.7 Other income, net $ 102.2 $ 70.3 $ 73.7 |
Quarterly Financial Information
Quarterly Financial Information (Unaudited) | 12 Months Ended |
Dec. 31, 2019 | |
Quarterly Financial Information Disclosure [Abstract] | |
QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | QUARTERLY FINANCIAL INFORMATION (Unaudited) (in millions, except per share amounts) First Quarter Second Quarter Third Quarter Fourth Quarter Total 2019 Operating revenues $ 2,377.4 $ 1,590.2 $ 1,608.0 $ 1,947.5 $ 7,523.1 Operating income 542.8 314.6 310.9 363.1 1,531.4 Net income attributed to common shareholders 420.1 235.7 234.3 243.9 1,134.0 Earnings per share * Basic $ 1.33 $ 0.75 $ 0.74 $ 0.77 $ 3.60 Diluted 1.33 0.74 0.74 0.77 3.58 2018 Operating revenues $ 2,286.5 $ 1,672.5 $ 1,643.7 $ 2,076.8 $ 7,679.5 Operating income 545.1 330.8 302.7 289.8 1,468.4 Net income attributed to common shareholders 390.1 231.0 233.2 205.0 1,059.3 Earnings per share * Basic $ 1.24 $ 0.73 $ 0.74 $ 0.65 $ 3.36 Diluted 1.23 0.73 0.74 0.65 3.34 * Earnings per share for the individual quarters may not total the year ended earnings per share amount because of changes to the average number of shares outstanding and changes in incremental issuable shares throughout the year. |
New Accounting Pronouncements
New Accounting Pronouncements | 12 Months Ended |
Dec. 31, 2019 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
NEW ACCOUNTING PRONOUNCEMENTS | NEW ACCOUNTING PRONOUNCEMENTS Financial Instruments Credit Losses Effective January 1, 2020, we adopted FASB ASU 2016-13, "Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments," using the modified retrospective transition method. This ASU amends the impairment model to utilize an expected loss methodology in place of the incurred loss methodology for financial instruments. The amendment requires entities to consider a broader range of information to estimate expected credit losses, which may result in earlier recognition of loss. 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. Because our exposure to credit losses for many of our regulated utility customers is mitigated by regulatory mechanisms we have in place, the noncash cumulative effect adjustment we recorded to retained earnings on January 1, 2020, as a result of our adoption of this standard, was not significant. The most significant impact of implementing this ASU will be in the form of additional disclosures that will be required in our quarterly report on Form 10-Q for the quarter ended March 31, 2020. These disclosures are intended to provide information that will help users of our financial statements analyze our exposure to credit risk and understand how we estimate our allowance for credit losses. Cloud Computing In August 2018, the FASB issued ASU 2018-15, Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract. The standard allows entities who are customers in hosting arrangements that are service contracts to apply the existing internal-use software guidance to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. The guidance specifies classification for capitalizing implementation costs and related amortization expense within the financial statements and requires additional disclosures. The adoption of ASU 2018-15, effective January 1, 2020, did not have a significant impact on our financial statements. Disclosure Requirements for Defined Benefit Plans In August 2018, the FASB issued ASU 2018-14, Disclosure Framework: Changes to the Disclosure Requirements for Defined Benefit Plans. The pronouncement modifies the disclosure requirements for defined benefit pension and other postretirement benefit plans. The guidance removes disclosures that are no longer considered cost beneficial, clarifies the specific requirements of disclosures and adds disclosure requirements identified as relevant. The modifications affect annual period disclosures and must be applied on a retrospective basis to all periods presented. The guidance will be effective for annual reporting periods ending after December 15, 2020, with early adoption permitted. We are currently evaluating the effects of this pronouncement on the notes to our financial statements. |
Schedule I - Condensed Parent C
Schedule I - Condensed Parent Company Financial Statements | 12 Months Ended |
Dec. 31, 2019 | |
Condensed Financial Information Disclosure [Abstract] | |
SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS | SCHEDULE I – CONDENSED PARENT COMPANY FINANCIAL STATEMENTS WEC ENERGY GROUP, INC. (PARENT COMPANY ONLY) A. INCOME STATEMENTS Year Ended December 31 (in millions) 2019 2018 2017 Operating expenses $ 4.7 $ 5.0 $ 6.0 Equity in earnings of subsidiaries 1,210.5 1,108.3 1,234.7 Other income, net 6.3 6.8 2.1 Interest expense 122.3 104.1 82.0 Income before income taxes 1,089.8 1,006.0 1,148.8 Income tax benefit 44.2 53.3 54.9 Net income attributed to common shareholders $ 1,134.0 $ 1,059.3 $ 1,203.7 The accompanying Notes to Condensed Parent Company Financial Statements are an integral part of these financial statements. B. STATEMENTS OF COMPREHENSIVE INCOME Year Ended December 31 (in millions) 2019 2018 2017 Net income attributed to common shareholders $ 1,134.0 $ 1,059.3 $ 1,203.7 Other comprehensive income (loss), net of tax Derivatives accounted for as cash flow hedges Net derivative losses, net of tax benefits of $1.3, $0.8, and $0.0, respectively (3.5 ) (2.1 ) — Reclassification of net gains to net income, net of tax (0.8 ) (1.2 ) (1.3 ) Cumulative effect adjustment from adoption of ASU 2018-02 — 1.6 — Cash flow hedges, net (4.3 ) (1.7 ) (1.3 ) Defined benefit plans Pension and OPEB adjustments arising during the period, net of tax 0.4 (0.9 ) (0.1 ) Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax 0.2 0.2 0.2 Cumulative effect adjustment from adoption of ASU 2018-02 — (0.3 ) — Defined benefit plans, net 0.6 (1.0 ) 0.1 Other comprehensive income (loss) from subsidiaries, net of tax 2.2 (2.8 ) 1.2 Other comprehensive loss, net of tax (1.5 ) (5.5 ) — Comprehensive income attributed to common shareholders $ 1,132.5 $ 1,053.8 $ 1,203.7 The accompanying Notes to Condensed Parent Company Financial Statements are an integral part of these financial statements. C. BALANCE SHEETS At December 31 (in millions) 2019 2018 Assets Current assets Cash and cash equivalents $ 0.5 $ 32.8 Accounts receivable from related parties 0.7 4.0 Notes receivable from related parties 22.5 71.0 Prepaid taxes 46.5 — Other — 0.6 Current assets 70.2 108.4 Long-term assets Investments in subsidiaries 13,433.1 12,682.5 Notes receivable from UMERC — 150.0 Other 23.0 31.8 Long-term assets 13,456.1 12,864.3 Total assets $ 13,526.3 $ 12,972.7 Liabilities and Equity Current liabilities Short-term debt $ 334.7 $ 548.4 Current portion of long-term debt 400.0 — Accounts payable to related parties 2.5 7.7 Notes payable to related parties 489.3 398.9 Other 17.9 14.0 Current liabilities 1,244.4 969.0 Long-term liabilities Long-term debt 2,141.6 2,190.8 Other 26.9 24.0 Long-term liabilities 2,168.5 2,214.8 Common shareholders' equity 10,113.4 9,788.9 Total liabilities and equity $ 13,526.3 $ 12,972.7 The accompanying notes to Condensed Parent Company Financial Statements are an integral part of these financial statements. D. STATEMENTS OF CASH FLOWS Year Ended December 31 (in millions) 2019 2018 2017 Operating activities Net income attributed to common shareholders $ 1,134.0 $ 1,059.3 $ 1,203.7 Reconciliation to cash provided by operating activities Equity income in subsidiaries, net of distributions (475.2 ) (419.4 ) (686.1 ) Deferred income taxes 9.1 14.4 89.5 Change in – Accounts receivable from related parties 3.3 (2.1 ) (0.1 ) Prepaid taxes (46.5 ) 17.5 28.4 Accounts payable to related parties (5.2 ) 4.6 (0.5 ) Other current liabilities 1.5 4.7 (1.4 ) Other, net 7.0 5.6 0.9 Net cash provided by operating activities 628.0 684.6 634.4 Investing activities Acquisition of Bluewater — — (226.0 ) Capital contributions to subsidiaries (602.3 ) (448.7 ) (173.4 ) Return of capital from subsidiaries 337.3 290.2 — Short-term notes receivable from related parties, net 48.5 (6.9 ) 167.8 Issuance of long-term notes receivable from UMERC — (100.0 ) (50.0 ) Redemption of long-term notes receivable from UMERC 150.0 — — Other, net (0.6 ) 6.4 4.5 Net cash used in investing activities (67.1 ) (259.0 ) (277.1 ) Financing activities Exercise of stock options 67.0 29.1 30.8 Purchase of common stock (140.1 ) (72.4 ) (71.3 ) Dividends paid on common stock (744.5 ) (697.3 ) (656.5 ) Issuance of long-term debt 350.0 600.0 — Retirement of long-term debt — (300.0 ) — Change in short-term debt (213.7 ) 53.6 173.0 Short-term notes payable to related parties, net 90.4 (6.2 ) 169.5 Other, net (2.3 ) (3.6 ) — Net cash used in financing activities (593.2 ) (396.8 ) (354.5 ) Net change in cash and cash equivalents (32.3 ) 28.8 2.8 Cash and cash equivalents at beginning of year 32.8 4.0 1.2 Cash and cash equivalents at end of year $ 0.5 $ 32.8 $ 4.0 The accompanying Notes to Condensed Parent Company Financial Statements are an integral part of these financial statements. SCHEDULE I – CONDENSED PARENT COMPANY FINANCIAL STATEMENTS WEC ENERGY GROUP, INC. (PARENT COMPANY ONLY) E. NOTES TO PARENT COMPANY FINANCIAL STATEMENTS NOTE 1—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES For Parent Company only presentation, investments in subsidiaries are accounted for using the equity method. We use the cumulative earnings approach for classifying distributions received in the statements of cash flows. The condensed Parent Company financial statements and notes should be read in conjunction with the consolidated financial statements and notes of WEC Energy Group, Inc. appearing in this Annual Report on Form 10-K. NOTE 2—CASH DIVIDENDS RECEIVED FROM SUBSIDIARIES Dividends received from our subsidiaries during the years ended December 31 were as follows: (in millions) 2019 2018 2017 WE $ 360.0 $ 310.0 $ 240.0 We Power 192.5 223.0 181.0 ATC Holding 87.4 105.8 82.6 WG 60.0 50.0 45.0 WECI 25.4 — — UMERC 10.0 — — Wisvest — 0.1 — Total $ 735.3 $ 688.9 $ 548.6 NOTE 3—LONG-TERM DEBT The following table shows the future maturities of our long-term debt outstanding as of December 31, 2019 : (in millions) 2020 $ 400.0 2021 600.0 2022 350.0 2023 — 2024 — Thereafter 1,200.0 Total $ 2,550.0 WECC is our subsidiary and has $50.0 million of long-term notes outstanding. In a Support Agreement between WECC and us, we agreed to make sufficient liquid asset contributions to WECC to permit WECC to service its debt obligations as they become due. NOTE 4—FAIR VALUE MEASUREMENTS The following table shows the financial instruments included on our balance sheets that are not recorded at fair value as of December 31 : 2019 2018 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Long-term notes receivable from UMERC $ — $ — $ 150.0 $ 145.5 Long-term debt, including current portion 2,541.6 2,619.4 2,190.8 2,132.8 The fair values of our long-term notes receivable and long-term debt are categorized within Level 2 of the fair value hierarchy. NOTE 5—SUPPLEMENTAL CASH FLOW INFORMATION (in millions) 2019 2018 2017 Cash paid for interest $ 117.7 $ 102.9 $ 82.5 Cash received for income taxes, net (4.9 ) (85.9 ) (169.9 ) Significant non-cash investing and financing transactions: Issuance of short-term note receivable to Bluewater — — 115.0 Issuance of short-term note receivable to UMERC — — 40.5 Settlement of short-term note payable with Wisvest — 0.9 — Settlement of short-term note payable with Bostco — — 4.8 NOTE 6—SHORT-TERM NOTES RECEIVABLE FROM RELATED PARTIES The following table shows our outstanding short-term notes receivable from related parties as of December 31: (in millions) 2019 2018 Wispark $ 13.5 $ 28.5 UMERC 9.0 42.5 Total $ 22.5 $ 71.0 NOTE 7—SHORT-TERM NOTES PAYABLE TO RELATED PARTIES The following table shows our outstanding short-term notes payable to related parties as of December 31: (in millions) 2019 2018 WBS $ 168.9 $ 123.5 Integrys 166.9 139.5 WECC 111.7 110.3 Bluewater Gas Storage 41.8 25.6 Total $ 489.3 $ 398.9 |
Schedule II - Valuation and Qua
Schedule II - Valuation and Qualifying Accounts | 12 Months Ended |
Dec. 31, 2019 | |
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract] | |
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | SCHEDULE II WEC ENERGY GROUP, INC. VALUATION AND QUALIFYING ACCOUNTS Allowance for Doubtful Accounts (in millions) Balance at Beginning of Period Expense (1) Deferral Net Write-offs (2) Balance at End of Period December 31, 2019 $ 149.2 $ 85.8 $ 11.4 $ (106.4 ) $ 140.0 December 31, 2018 143.2 94.7 (5.5 ) (83.2 ) 149.2 December 31, 2017 108.0 96.7 16.4 (77.9 ) 143.2 (1) Net of recoveries. (2) Represents amounts written off to the reserve, net of adjustments to regulatory assets. |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2019 | |
Accounting Policies [Abstract] | |
Nature Of Operations | WEC Energy Group serves approximately 1.6 million electric customers and 2.9 million natural gas customers, and owns approximately 60% |
Consolidation | As used in these notes, the term "financial statements" refers to the consolidated financial statements. This includes the income statements, statements of comprehensive income, balance sheets, statements of cash flows, and statements of equity, unless otherwise noted. On our financial statements, we consolidate our majority-owned subsidiaries 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 sheet as of December 31, 2019 related to the minority interests at Bishop Hill III, Coyote Ridge, and Upstream held by third parties. |
Segment reporting | Our financial statements include the accounts of WEC Energy Group, a diversified energy holding company, and the accounts of our subsidiaries in the following reportable segments: • Wisconsin segment – Consists of WE, WPS, and WG, which are engaged primarily in the generation of electricity and the distribution of electricity and natural gas in Wisconsin; and UMERC, which generates electricity and distributes electricity and natural gas to customers located in the Upper Peninsula of Michigan. • Illinois segment – Consists of PGL and NSG, which are engaged primarily in the distribution of natural gas in Illinois. • Other states segment – Consists of MERC and MGU, which are engaged primarily in the distribution of natural gas in Minnesota and Michigan, respectively. • Electric transmission segment – Consists of our approximate 60% ownership interest in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions, and our approximate 75% ownership interest in ATC Holdco, which invests in transmission-related projects outside of ATC's traditional footprint. • Non-utility energy infrastructure segment – Consists of We Power, which is principally engaged in the ownership of electric power generating facilities for long-term lease to WE, and Bluewater, which owns underground natural gas storage facilities in Michigan. WECI, which holds our ownership interests in several wind generating facilities, is also included in this segment. See Note 2, Acquisitions, for more information on Bluewater and the WECI wind generating facilities. • Corporate and other segment – Consists of the WEC Energy Group holding company, the Integrys holding company, the PELLC holding company, Wispark, Bostco, Wisvest, WECC, WBS, and PDL. In the first quarter of 2017, we sold substantially all of the remaining assets of Bostco, and, in October 2018, Bostco was dissolved. In 2019, we sold certain PDL solar power generating facilities. See Note 3, Dispositions, for more information on these sales. |
Joint plant and equity method investments | Investments in companies not controlled by us, but over which we have significant influence regarding the operating and financial policies of the investee, are accounted for using the equity method. We use the cumulative earnings approach for classifying distributions received in the statements of cash flows. Under the cumulative earnings approach, we compare the distributions received to cumulative equity method earnings since inception. Any distributions received up to the amount of cumulative equity earnings are considered a return on investment and classified in operating activities. Any excess distributions are considered a return of investment and classified in investing activities. Our financial statements also reflect our proportionate interests in certain jointly owned utility facilities. See Note 7, Jointly Owned Utility Facilities, for more information The carrying amounts of equity method investments are assessed for impairment by comparing the fair values of these investments to their carrying amounts if a fair value assessment was completed or by reviewing for the presence of impairment indicators. If an impairment exists, and it is determined to be other-than-temporary, an impairment loss is recognized equal to the amount by which the carrying amount exceeds the investment's fair value. |
Use of estimates | We prepare our financial statements in conformity with GAAP. We make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates. |
Cash and cash equivalents | Cash and cash equivalents include marketable debt securities with an original maturity of three months or less. |
Operating revenues | The following discussion includes our significant accounting policies related to operating revenues. For additional required disclosures on disaggregation of operating revenues, see Note 4, Operating Revenues . Revenues from Contracts with Customers Electric Utility Operating Revenues Electricity sales to residential and commercial and industrial customers are generally accomplished through requirements contracts, which provide for the delivery of as much electricity as the customer needs. These contracts represent discrete deliveries of electricity and consist of one distinct performance obligation satisfied over time, as the electricity is delivered and consumed by the customer simultaneously. For our Wisconsin residential and commercial and industrial customers and the majority of our Michigan residential and commercial and industrial customers, our performance obligation is bundled to consist of both the sale and the delivery of the electric commodity. In our Michigan service territory, a limited number of residential and commercial and industrial customers can purchase the commodity from a third party. In this case, the delivery of the electricity represents our sole performance obligation. The transaction price of the performance obligations for residential and commercial and industrial customers is valued using the rates, charges, terms, and conditions of service included in the tariffs of our regulated electric utilities, which have been approved by state regulators. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on the quantity of electricity delivered each month. Our retail electric rates in Wisconsin include base amounts for fuel and purchased power costs, which also impact our revenues. The electric fuel rules set by the PSCW allow us to defer, for subsequent rate recovery or refund, under- or over-collections of actual fuel and purchased power costs that exceed a 2% price variance from the costs included in the rates charged to customers. Our electric utilities monitor the deferral of under-collected costs to ensure that it does not cause them to earn a greater ROE than authorized by the PSCW. In contrast, the rates of our Michigan retail electric customers include recovery of fuel and purchased power costs on a one-for-one basis. In addition, the Wisconsin residential tariffs of WE and WPS include a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. Wholesale customers who resell power can choose to either bundle capacity and electricity services together under one contract with a supplier or purchase capacity and electricity separately from multiple suppliers. Furthermore, wholesale customers can choose to have our utilities provide generation to match the customer's load, similar to requirements contracts, or they can purchase specified quantities of electricity and capacity. Contracts with wholesale customers that include capacity bundled with the delivery of electricity contain two performance obligations, as capacity and electricity are often transacted separately in the marketplace at the wholesale level. When recognizing revenue associated with these contracts, the transaction price is allocated to each performance obligation based on its relative standalone selling price. Revenue is recognized as control of each individual component is transferred to the customer. Electricity is the primary product sold by our electric utilities and represents a single performance obligation satisfied over time through discrete deliveries to a customer. Revenue from electricity sales is generally recognized as units are produced and delivered to the customer within the production month. Capacity represents the reservation of an electric generating facility and conveys the ability to call on a plant to produce electricity when needed by the customer. The nature of our performance obligation as it relates to capacity is to stand ready to deliver power. This represents a single performance obligation transferred over time, which generally represents a monthly obligation. Accordingly, capacity revenue is recognized on a monthly basis. The transaction price of the performance obligations for wholesale customers is valued using the rates, charges, terms, and conditions of service, which have been approved by the FERC. These wholesale rates include recovery of fuel and purchased power costs from customers on a one-for-one basis. For the majority of our wholesale customers, the price billed for energy and capacity is a formula-based rate. Formula-based rates initially set a customer's current year rates based on the previous year’s expenses. This is a predetermined formula derived from the utility's costs and a reasonable rate of return. Because these rates are eventually trued up to reflect actual, current-year costs, they represent a form of variable consideration in certain circumstances. The variable consideration is estimated and recognized over time as wholesale customers receive and consume the capacity and electricity services. We are an active participant in the MISO Energy Markets, where we bid our generation into the Day Ahead and Real Time markets and procure electricity for our retail and wholesale customers at prices determined by the MISO Energy Markets. Purchase and sale transactions are recorded using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded as purchased power in cost of sales and net sales in a single hour are recorded as resale revenues on our income statements. For resale revenues, our performance obligation is created only when electricity is sold into the MISO Energy Markets. For all of our customers, consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days . Natural Gas Utility Operating Revenues We recognize natural gas utility operating revenues under requirements contracts with residential, commercial and industrial, and transportation customers served under the tariffs of our regulated utilities. Tariffs provide our customers with the standard terms and conditions, including rates, related to the services offered. Requirements contracts provide for the delivery of as much natural gas as the customer needs. These requirements contracts represent discrete deliveries of natural gas and constitute a single performance obligation satisfied over time. Our performance obligation is both created and satisfied with the transfer of control of natural gas upon delivery to the customer. For most of our customers, natural gas is delivered and consumed by the customer simultaneously. A performance obligation can be bundled to consist of both the sale and the delivery of the natural gas commodity. In certain of our service territories, customers can purchase the commodity from a third party. In this case, the performance obligation only includes the delivery of the natural gas to the customer. The transaction price of the performance obligations for our natural gas customers is valued using the rates, charges, terms, and conditions of service included in the tariffs of our regulated utilities, which have been approved by state regulators. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on natural gas delivered each month. The tariffs of our natural gas utilities include various rate mechanisms that allow them to recover or refund changes in prudently incurred costs from rate case-approved amounts. The rates for all of our natural gas utilities include one-for-one recovery mechanisms for natural gas commodity costs. We defer any difference between actual natural gas costs incurred and costs recovered through rates as a current asset or liability. The deferred balance is returned to or recovered from customers at intervals throughout the year. In addition, the rates of PGL and NSG, and the residential tariffs of WE, WPS, and WG, include riders or other mechanisms for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. The rates of PGL and NSG include riders for cost recovery of both environmental cleanup costs, energy conservation and management program costs, and income tax expense changes resulting from the Tax Legislation. Finally, PGL's rates include a cost recovery mechanism for SMP costs, and similarly, MERC's rates include a rider to recover costs incurred to replace or modify natural gas facilities. Consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days . Other Natural Gas Operating Revenues We have other natural gas operating revenues from Bluewater, which is in our non-utility energy infrastructure segment. Bluewater has entered into long-term service agreements for natural gas storage services with WE, WPS, and WG, and provides service to several unaffiliated customers. All amounts associated with services from affiliates have been eliminated at the consolidated level. Other Non-Utility Operating Revenues 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 deferred revenue, and we continually amortize the deferred carrying costs to revenues over the life of the related lease term that We Power has with WE. During 2019 and 2018, we recorded $25.4 million and $25.3 million , respectively, of revenue related to these deferred carrying costs, which were included in the contract liability balance at the beginning of the period. This contract liability is presented as deferred revenue, net on our balance sheets. Non-utility operating revenues are also derived from servicing appliances for customers at MERC. These contracts customarily have a duration of one year or less and consist of a single performance obligation satisfied over time. We use a time-based output method to recognize revenues monthly for the service fee. Revenues from distributed renewable solar projects consist primarily of sales of renewable energy and SRECs generated by PDL. The sale of SRECs is a distinct performance obligation as they are often sold separately from the renewable energy generated. Although the performance obligation for the sale of renewable energy is recognized over time and the performance obligation for SRECs is recognized at a point-in-time, the timing of revenue recognition is the same, as the generation of renewable energy and sales of SREC's occur concurrently. See Note 3, Dispositions, for more information on the sale of certain of these solar facilities. Wind generation revenues from WECI's ownership interests in wind generation facilities continued to grow with the acquisition of Upstream in January 2019. See Note 2, Acquisitions, for more information on Upstream, the December 2018 acquisition of Coyote Ridge, and other planned future acquisitions. Most of these wind generation facilities have offtake agreements with unaffiliated third parties for all of the energy to be produced by the facility. The contracts consist of one distinct performance obligation satisfied over time, as the electricity is delivered and consumed by the customer simultaneously. We recognize revenue as energy is produced and delivered to the customer within the production month. Upstream's revenue is substantially fixed over 10 years through an agreement with an unaffiliated third party. Other Operating Revenues Alternative Revenues Alternative revenues are created from programs authorized by regulators that allow our utilities to record additional revenues by adjusting rates in the future, usually as a surcharge applied to future billings, in response to past activities or completed events. Alternative revenue programs allow compensation for the effects of weather abnormalities, other external factors, or demand side management initiatives. Alternative revenue programs can also provide incentive awards if the utility achieves certain objectives and in other limited circumstances. We record alternative revenues when the regulator-specified conditions for recognition have been met. We reverse these alternative revenues as the customer is billed, at which time this revenue is presented as revenues from contracts with customers. Below is a summary of the alternative revenue programs at our utilities: • The rates of PGL, NSG, and MERC include decoupling mechanisms. These mechanisms differ by state and allow the utilities to recover or refund the differences between actual and authorized margins for certain customer classes. See Note 25, Regulatory Environment, for more information . • MERC’s rates include a conservation improvement program rider, which includes a financial incentive for meeting energy savings goals. • WE and WPS provide wholesale electric service to customers under market-based rates and FERC formula rates. The customer is charged a base rate each year based upon a formula using prior year actual costs and customer demand. A true-up is calculated based on the difference between the amount billed to customers for the demand component of their rates and what the actual cost of service was for the year. The true-up can result in an amount that we will recover from or refund to the customer. We consider the true-up portion of the wholesale electric revenues to be alternative revenues. |
Materials, supplies and inventories | PGL and NSG price natural gas storage injections at the calendar year average of the costs of natural gas supply purchased. Withdrawals from storage are priced on the LIFO cost method. Inventories stated on a LIFO basis represented approximately 19% and 16% of total inventories at December 31, 2019 and 2018 , respectively. The estimated replacement cost of natural gas in inventory at December 31, 2019 and 2018 , exceeded the LIFO cost by $9.8 million and $72.4 million , respectively. In calculating these replacement amounts, PGL and NSG used a Chicago city-gate natural gas price per Dth of $1.95 at December 31, 2019 , and $3.08 at December 31, 2018 . Substantially all other materials and supplies, natural gas in storage, and fossil fuel inventories are recorded using the weighted-average cost method of accounting. |
Regulatory assets and liabilities | The economic effects of regulation can result in regulated companies recording costs and revenues that are allowed in the rate-making process in a period different from the period they would have been recognized by a nonregulated company. When this occurs, regulatory assets and regulatory liabilities are recorded on the balance sheet. Regulatory assets represent deferred costs probable of recovery from customers that would have otherwise been charged to expense. Regulatory liabilities represent amounts that are expected to be refunded to customers in future rates or future costs already collected from customers in rates. |
Property, plant, and equipment | We record property, plant, and equipment at cost. Cost includes material, labor, overhead, and both debt and equity components of AFUDC. Additions to and significant replacements of property are charged to property, plant, and equipment at cost; minor items are charged to other operation and maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired. We record straight-line depreciation expense over the estimated useful life of utility property using depreciation rates approved by the applicable regulators. Annual utility composite depreciation rates are shown below: Annual Utility Composite Depreciation Rates 2019 2018 2017 WE 3.11% 3.18% 2.95% WPS 2.44% 2.50% 2.55% WG 2.29% 2.30% 2.30% PGL 3.20% 3.25% 3.29% NSG 2.48% 2.45% 2.43% MERC * 2.33% 1.95% 2.51% MGU 2.54% 2.61% 2.61% UMERC 2.87% 2.50% 2.46% * The 2018 rate reflects the impact of a new depreciation study approved by the MPUC in May 2018. The rates approved were effective retroactive to January 2017. An approximate $1.4 million reduction in depreciation expense was recorded in 2018 related to this depreciation study. We depreciate our We Power assets over the estimated useful life of the various property components. The components have useful lives of between 10 to 45 years for PWGS 1 and PWGS 2 and 10 to 55 years for ER 1 and ER 2. We capitalize certain costs related to software developed or obtained for internal use and record these costs to amortization expense over the estimated useful life of the related software, which ranges from 3 to 15 years. If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statement. Third parties reimburse the utilities for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs are recorded as a reduction to property, plant, and equipment. |
AFUDC | AFUDC is included in utility plant accounts and represents the cost of borrowed funds (AFUDC – Debt) used during plant construction, and a return on shareholders' capital (AFUDC – Equity) used for construction purposes. AFUDC – Debt is recorded as a reduction of interest expense, and AFUDC – Equity is recorded in other income, net. The majority of AFUDC is recorded at WE, WPS, WBS, WG, and UMERC. Approximately 50% of WE's, WPS's, WG's, UMERC's, and WBS's retail jurisdictional CWIP expenditures are subject to the AFUDC calculation. The AFUDC calculation for WBS uses the WPS AFUDC retail rate, while our other utilities' AFUDC rates are determined by their respective state commissions, each with specific requirements. Based on these requirements, the other utilities did not record significant AFUDC for 2019 , 2018 , or 2017 . Average AFUDC rates are shown below: 2019 Average AFUDC Retail Rate Average AFUDC Wholesale Rate WE 8.45% 5.11% WPS 7.72% 2.58% WG 8.33% N/A UMERC 6.28% N/A WBS 7.72% N/A |
Cloud Computing Hosting Arrangements that are Service Contracts | We have entered into several cloud computing arrangements that are hosted service contracts as part of projects related to the continuous transformation of technology. These projects include, among other things, developing a centralized repository for data to improve analytics and reporting, targeted ERP systems, a project management tool, and a power generation employee scheduling system. We present prepaid hosting fees that are service contracts in either prepayments or other long-term assets on our balance sheets and amortize them as the hosting services are received. Amortization expense, as well as the fees associated with the hosting arrangements, is recorded in other operation and maintenance expense on our income statements. As of January 1, 2020, we started capitalizing implementation costs related to cloud computing arrangements that are hosted service contracts. We will amortize the implementation costs on a straight-line basis over the cloud computing service arrangement term once the component of the hosted service is ready for its intended use. The presentation of these costs, along with the related amortization, will follow the prepaid hosting fees. |
Goodwill and other intangible assets | Goodwill and other intangible assets with indefinite lives are subject to an annual impairment test. Interim impairment tests are performed when impairment indicators are present. Our reporting units containing goodwill perform annual goodwill impairment tests during the third quarter of each year. The carrying amount of the reporting unit's goodwill is considered not recoverable if the carrying amount of the reporting unit exceeds the reporting unit's fair value. An impairment loss is recorded for the excess of the carrying amount of the goodwill over its implied fair value. See Note 9, Goodwill, for more information . Intangible assets with definite lives are reviewed for impairment on a quarterly basis. |
Impairment of long-lived assets | We periodically assess the recoverability of certain long-lived assets when factors indicate the carrying value of such assets may be impaired or such assets are planned to be sold. These assessments require significant assumptions and judgments by management. The long-lived assets assessed for impairment generally include certain assets within regulated operations that may not be fully recovered from our customers as a result of regulatory decisions that will be made in the future, as well as assets within nonregulated operations that are proposed to be sold or are currently generating operating losses. An impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds the fair value of the asset. The carrying amount of an asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. An impairment loss is measured as the excess of the carrying amount of the asset in comparison to the fair value of the asset. |
Asset retirement obligations | We recognize, at fair value, legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and normal operation of the assets. An ARO liability is recorded, when incurred, for these obligations as long as the fair value can be reasonably estimated, even if the timing or method of settling the obligation is unknown. The associated retirement costs are capitalized as part of the related long-lived asset and are depreciated over the useful life of the asset. The ARO liabilities are accreted each period using the credit-adjusted risk-free interest rates associated with the expected settlement dates of the AROs. These rates are determined when the obligations are incurred. Subsequent changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or a decrease to the carrying amount of the liability and the associated capitalized retirement costs. For our regulated entities, we recognize regulatory assets or liabilities for the timing differences between when we recover an ARO in rates and when we recognize the associated retirement costs. |
Stock-based compensation | In accordance with the shareholder approved Omnibus Stock Incentive Plan, we provide long-term incentives through our equity interests to our non-employee directors, officers, and other key employees. The plan provides for the granting of stock options, restricted stock, performance shares, and other stock-based awards. Awards may be paid in common stock, cash, or a combination thereof. The number of shares of common stock authorized for issuance under the plan is 34.3 million . We recognize stock-based compensation expense on a straight-line basis over the requisite service period. Awards classified as equity awards are measured based on their grant-date fair value. Awards classified as liability awards are recorded at fair value each reporting period. In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which modified certain aspects of the accounting for stock-based compensation awards. This ASU became effective for us on January 1, 2017. Under the new guidance, all excess tax benefits and tax deficiencies are recognized as income tax expense or benefit in the income statement on a prospective basis. Prior to January 1, 2017, these amounts were recorded in additional paid in capital on the balance sheet, and excess tax benefits could only be recognized to the extent they reduced taxes payable. In the first quarter of 2017, we recorded a $15.7 million cumulative-effect adjustment to increase retained earnings for excess tax benefits that had not been recognized in prior years as they did not reduce taxes payable. As allowed under this ASU, we have elected to account for forfeitures as they occur, rather than estimating potential future forfeitures and recording them over the vesting period. Stock Options We grant non-qualified stock options that generally vest on a cliff-basis after three years . The exercise price of a stock option under the plan cannot be less than 100% of our common stock's fair market value on the grant date. Historically, all stock options have been granted with an exercise price equal to the fair market value of our common stock on the date of the grant. Options vest immediately upon retirement, death, or disability; however, they may not be exercised within six months of the grant date except in the event of a change in control. Options expire no later than 10 years from the date of the grant. Our stock options are classified as equity awards. The fair value of our stock options was calculated using a binomial option-pricing model. The following table shows the estimated weighted-average fair value per stock option granted along with the weighted-average assumptions used in the valuation models: 2019 2018 2017 Stock options granted 476,418 710,710 552,215 Estimated weighted-average fair value per stock option $ 8.60 $ 7.71 $ 7.45 Assumptions used to value the options: Risk-free interest rate 2.5% – 2.7% 1.6% – 2.8% 0.7% – 2.5% Dividend yield 3.6 % 3.5 % 3.5 % Expected volatility 17.0 % 18.0 % 19.0 % Expected life (years) 8.5 5.9 6.8 The risk-free interest rate was based on the United States Treasury interest rate with a term consistent with the expected life of the stock options. The dividend yield was based on our dividend rate at the time of the grant and historical stock prices. Expected volatility and expected life assumptions were based on our historical experience. Restricted Shares Restricted shares granted to employees generally have a vesting period of three years with one-third of the award vesting on each anniversary of the grant date. This same vesting schedule is followed for restricted shares that were granted to non-employee directors prior to 2017. Restricted shares granted to certain officers and all non-employee directors after January 1, 2017, fully vest after one year . Our restricted shares are classified as equity awards. Performance Units Officers and other key employees are granted performance units under the WEC Energy Group Performance Unit Plan. Under the plan, the ultimate number of units that will be awarded is dependent on our total shareholder return (stock price appreciation plus dividends) as compared to the total shareholder return of a peer group of companies over three years , as well as other performance metrics as may be determined by the Compensation Committee. Under the terms of the award, participants may earn between 0% and 175% of the performance unit award based on our total shareholder return. Pursuant to the terms of the plan, these percentages can be adjusted upwards or downwards based on our performance against additional performance measures, if any, adopted by the Compensation Committee. Performance units also accrue forfeitable dividend equivalents in the form of additional performance units. All grants of performance units are settled in cash and are accounted for as liability awards accordingly. The fair value of the performance units reflects our estimate of the final expected value of the awards, which is based on our stock price and performance achievement under the terms of the award. Stock-based compensation costs are generally recorded over the performance period, which is three years . |
Stock-based compensation - forfeitures | As allowed under this ASU, we have elected to account for forfeitures as they occur, rather than estimating potential future forfeitures and recording them over the vesting period. |
Earnings per share | We compute basic earnings per share by dividing our net income attributed to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted earnings per share is computed in a similar manner, but includes the exercise and/or conversion of all potentially dilutive securities. Such dilutive securities include in-the-money stock options. There were no securities that had an anti-dilutive effect for the years ended December 31, 2019 , 2018 , and 2017 . |
Leases | In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which revised the previous guidance (Topic 840) regarding accounting for leases. Revisions include requiring a lessee to recognize a lease asset and a lease liability on its balance sheet for each lease, including operating leases with an initial term greater than 12 months. In addition, required quantitative and qualitative disclosures related to lease agreements were expanded. As required, we adopted Topic 842 effective January 1, 2019. We utilized the following practical expedients, which were available under ASU 2016-02, in our adoption of the new lease guidance. • We did not reassess whether any expired or existing contracts were leases or contained leases. • We did not reassess the lease classification for any expired or existing leases (that is, all leases that were classified as operating leases in accordance with Topic 840 continue to be classified as operating leases, and all leases that were classified as capital leases in accordance with Topic 840 are classified as finance leases). • We did not reassess the accounting for initial direct costs for any existing leases. We did not elect the practical expedient allowing entities to account for the nonlease components in lease contracts as part of the single lease component to which they were related. Instead, in accordance with ASC 842-10-15-31, our policy is to account for each lease component separately from the nonlease components of the contract. We did not elect the practical expedient to use hindsight in determining the lease term and in assessing impairment of our right of use assets. No impairment losses were included in the measurement of our right of use assets upon our adoption of Topic 842. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842, which is an amendment to ASU 2016-02. Land easements (also commonly referred to as rights of way) represent the right to use, access or cross another entity's land for a specified purpose. This new guidance permits an entity to elect a transitional practical expedient, to be applied consistently, to not evaluate under Topic 842 land easements that were already in existence or had expired at the time of the entity's adoption of Topic 842. Once Topic 842 is adopted, an entity is required to apply Topic 842 prospectively to all new (or modified) land easements to determine whether the arrangement should be accounted for as a lease. We elected this practical expedient, resulting in none of our land easements being treated as leases upon our adoption of Topic 842. In July 2018, the FASB issued ASU 2018-11, Leases (Topic 842): Targeted Improvements, which amends ASU 2016-02 and allows entities the option to initially apply Topic 842 at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption, if required. We used the optional transition method to apply the new guidance as of January 1, 2019, rather than as of the earliest period presented. We did not require a cumulative-effect adjustment upon adoption of Topic 842. Right of use assets and related lease liabilities related to our operating leases that were recorded upon adoption of Topic 842 were $49.0 million and $48.8 million , respectively. Regarding our power purchase agreement that meets the criteria of a finance lease, while the adoption of Topic 842 changed the classification of expense related to this lease on a prospective basis, it had no impact on the total amount of lease expense recorded, and did not impact the lease asset and related liability amounts recorded on our balance sheets. Significant Judgments and Other Information We are currently party to several easement agreements that allow us access to land we do not own for the purpose of constructing and maintaining certain electric power and natural gas equipment. The majority of payments we make related to easements relate to our wind generating facilities. We have not classified our easements as leases because we view the entire parcel of land specified in our easement agreements to be the identified asset, not just that portion of the parcel that contains our easement. As such, we have concluded that we do not control the use of an identified asset related to our easement agreements, nor do we obtain substantially all of the economic benefits associated with these shared-use assets. As of February 27, 2020 , we have not entered into any material leases that have not yet commenced. See Note 14, Leases, for more information . |
Income taxes | We follow the liability method in accounting for income taxes. Accounting guidance for income taxes requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax balances to reflect tax rate changes. We are required to assess the likelihood that our deferred tax assets would expire before being realized. If we conclude that certain deferred tax assets are likely to expire before being realized, a valuation allowance would be established against those assets. GAAP requires that, if we conclude in a future period that it is more likely than not that some or all of the deferred tax assets would be realized before expiration, we reverse the related valuation allowance in that period. Any change to the allowance, as a result of a change in judgment about the realization of deferred tax assets, is reported in income tax expense. Investment tax credits associated with regulated operations are deferred and amortized over the life of the assets. Production tax credits are recognized in the period in which such credits are generated. The amount of the credit is based upon power production from our qualifying generation facilities. We file a consolidated federal income tax return. Accordingly, we allocate federal current tax expense, benefits, and credits to our subsidiaries based on their separate tax computations and our ability to monetize all credits on our consolidated federal return. See Note 15, Income Taxes , for more information. We recognize interest and penalties accrued, related to unrecognized tax benefits, in income tax expense in our income statements. In February 2018, the FASB issued ASU 2018-02, Income Statement – Reporting Comprehensive Income. The amendments in this update allowed entities to reclassify the income tax effects that are stranded in accumulated other comprehensive income as a result of the Tax Legislation to retained earnings. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2018, with early adoption permitted. We early adopted the amendments in the fourth quarter of 2018 and reclassified the stranded tax effects associated with the Tax Legislation from accumulated other comprehensive income to retained earnings. As of December 31, 2018, our accumulated other comprehensive income decreased $0.6 million as a result of adopting ASU 2018-02. The adoption of this guidance had no impact on our results of operations or cash flows. |
Fair value measurements | Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods. Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. When possible, we base the valuations of our derivative assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally-developed inputs. |
Derivative instruments | We use derivatives as part of our risk management program to manage the risks associated with the price volatility of interest rates, purchased power, generation, and natural gas costs for the benefit of our customers and shareholders. Our approach is non-speculative and designed to mitigate risk. Regulated hedging programs are approved by our state regulators. We record derivative instruments on our balance sheets as assets or liabilities measured at fair value unless they qualify for the normal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities. We classify derivative assets and liabilities as current or long-term on our balance sheets based on the maturities of the underlying contracts. Cash flows from derivative activities are presented in the same category as the item being hedged within operating activities on our statements of cash flows. Derivative accounting rules provide the option to present certain asset and liability derivative positions net on the balance sheets and to net the related cash collateral against these net derivative positions. We elected not to net these items. On our balance sheets, cash collateral provided to others is reflected in other current assets, and cash collateral received is reflected in other current liabilities. |
Guarantees | We follow the guidance of the Guarantees Topic of the FASB ASC, which requires, under certain circumstances, that the guarantor recognize a liability for the fair value of the obligation undertaken in issuing the guarantee at its inception. |
Employee benefits | The costs of pension and OPEB are expensed over the periods during which employees render service. These costs are distributed among our subsidiaries based on current employment status and actuarial calculations, as applicable. Our regulators allow recovery in rates for the utilities' net periodic benefit cost calculated under GAAP. |
Customer deposits and credit balances | When utility customers apply for new service, they may be required to provide a deposit for the service. Customer deposits are recorded within other current liabilities on our balance sheets. Utility customers can elect to be on a budget plan. Under this type of plan, a monthly installment amount is calculated based on estimated annual usage. During the year, the monthly installment amount is reviewed by comparing it to actual usage. If necessary, an adjustment is made to the monthly amount. Annually, the budget plan is reconciled to actual annual usage. Payments in excess of actual customer usage are recorded within other current liabilities on our balance sheets. |
Environmental remediation costs | We are subject to federal and state environmental laws and regulations that in the future may require us to pay for environmental remediation at sites where we have been, or may be, identified as a potentially responsible party. Loss contingencies may exist for the remediation of hazardous substances at various potential sites, including coal combustion product landfill sites and manufactured gas plant sites. See Note 8, Asset Retirement Obligations, for more information regarding coal combustion product landfill sites and Note 23, Commitments and Contingencies , for more information regarding manufactured gas plant sites. We record environmental remediation liabilities when site assessments indicate remediation is probable and we can reasonably estimate the loss or a range of losses. The estimate includes both our share of the liability and any additional amounts that will not be paid by other potentially responsible parties or the government. When possible, we estimate costs using site-specific information but also consider historical experience for costs incurred at similar sites. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws governing the remediation process may change, as well as site conditions, potentially affecting the cost of remediation. Our utilities have received approval to defer certain environmental remediation costs, as well as estimated future costs, through a regulatory asset. The recovery of deferred costs is subject to the applicable state Commission's approval. We review our estimated costs of remediation annually for our manufactured gas plant sites and coal combustion product landfill sites. We adjust the liabilities and related regulatory assets, as appropriate, to reflect the new cost estimates. Any material changes in cost estimates are adjusted throughout the year. |
Customer concentrations of credit risk | We provide regulated electric service to customers in Wisconsin and Michigan and regulated natural gas service to customers in Wisconsin, Illinois, Minnesota, and Michigan. The geographic concentration of our customers did not contribute significantly to our overall exposure to credit risk. We periodically review customers' credit ratings, financial statements, and historical payment performance and require them to provide collateral or other security as needed. Credit risk exposure at WE, WPS, WG, PGL, and NSG is mitigated by their recovery mechanisms for uncollectible expense discussed in Note 1(d), Operating Revenues . As a result, we did not have any significant concentrations of credit risk at December 31, 2019 . In addition, there were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2019 . |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Accounting Policies [Abstract] | |
Schedule of inventory | Our inventory as of December 31 consisted of: (in millions) 2019 2018 Materials and supplies $ 234.2 $ 226.6 Natural gas in storage 227.7 232.9 Fossil fuel 87.9 88.7 Total $ 549.8 $ 548.2 |
Schedule of annual utility composite depreciation rates | Annual utility composite depreciation rates are shown below: Annual Utility Composite Depreciation Rates 2019 2018 2017 WE 3.11% 3.18% 2.95% WPS 2.44% 2.50% 2.55% WG 2.29% 2.30% 2.30% PGL 3.20% 3.25% 3.29% NSG 2.48% 2.45% 2.43% MERC * 2.33% 1.95% 2.51% MGU 2.54% 2.61% 2.61% UMERC 2.87% 2.50% 2.46% * The 2018 rate reflects the impact of a new depreciation study approved by the MPUC in May 2018. The rates approved were effective retroactive to January 2017. An approximate $1.4 million reduction in depreciation expense was recorded in 2018 related to this depreciation study. |
Schedule of public utilities allowance for funds used during construction | Average AFUDC rates are shown below: 2019 Average AFUDC Retail Rate Average AFUDC Wholesale Rate WE 8.45% 5.11% WPS 7.72% 2.58% WG 8.33% N/A UMERC 6.28% N/A WBS 7.72% N/A Our regulated utilities and WBS recorded the following AFUDC for the years ended December 31: (in millions) 2019 2018 2017 AFUDC – Debt WE $ 1.5 $ 1.5 $ 1.2 WPS 2.4 1.9 1.6 WG 0.5 0.2 0.3 UMERC 1.3 2.4 0.1 WBS 0.1 0.2 1.1 Other 0.1 0.7 0.6 Total AFUDC – Debt $ 5.9 $ 6.9 $ 4.9 AFUDC – Equity WE $ 3.7 $ 3.9 $ 3.1 WPS 5.7 4.6 4.1 WG 1.3 0.6 0.9 UMERC 3.3 5.4 0.2 WBS 0.2 0.6 3.0 Other 0.2 0.1 0.1 Total AFUDC – Equity $ 14.4 $ 15.2 $ 11.4 |
Schedule of assumptions used to estimate the fair value of stock options granted | The following table shows the estimated weighted-average fair value per stock option granted along with the weighted-average assumptions used in the valuation models: 2019 2018 2017 Stock options granted 476,418 710,710 552,215 Estimated weighted-average fair value per stock option $ 8.60 $ 7.71 $ 7.45 Assumptions used to value the options: Risk-free interest rate 2.5% – 2.7% 1.6% – 2.8% 0.7% – 2.5% Dividend yield 3.6 % 3.5 % 3.5 % Expected volatility 17.0 % 18.0 % 19.0 % Expected life (years) 8.5 5.9 6.8 |
Acquisitions (Tables)
Acquisitions (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Bluewater | |
Business Acquisition [Line Items] | |
Allocation of purchase price | The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition. The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. Bluewater is included in the non-utility energy infrastructure segment. (in millions) Current assets $ 2.0 Net property, plant, and equipment 217.6 Goodwill 7.3 Current liabilities (0.9 ) Total purchase price $ 226.0 |
WPS | Forward Wind Energy Center | |
Business Acquisition [Line Items] | |
Allocation of purchase price | The table below shows the allocation of the purchase price to the assets acquired at the date of the acquisition, which are included in rate base. (in millions) Current assets $ 0.2 Net property, plant, and equipment 76.9 Total purchase price $ 77.1 |
WECI | Upstream Wind Energy Center | |
Business Acquisition [Line Items] | |
Allocation of purchase price | The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition. (in millions) Current assets $ 1.5 Net property, plant, and equipment 341.6 Other long-term assets * 22.9 Current liabilities (4.6 ) Long-term liabilities (15.0 ) Noncontrolling interest (69.0 ) Total purchase price $ 277.4 * Includes $8.1 million of restricted cash. |
WECI | Coyote Ridge | |
Business Acquisition [Line Items] | |
Allocation of purchase price | The table below shows the allocation of the purchase price to the assets acquired at the date of the acquisition. (in millions) Net property, plant, and equipment $ 66.4 Noncontrolling interest (5.0 ) Total purchase price $ 61.4 |
WECI | Bishop Hill III Wind Energy Center | |
Business Acquisition [Line Items] | |
Allocation of purchase price | The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition. (in millions) Current assets $ 1.4 Net property, plant, and equipment 190.2 Other long-term assets * 4.5 Current liabilities (1.6 ) Long-term liabilities (8.3 ) Noncontrolling interest (18.8 ) Total purchase price $ 167.4 * Represents restricted cash. |
Operating Revenues (Tables)
Operating Revenues (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Disaggregation of Operating Revenues | |
Operating revenues disaggregated by revenue source | Comparable amounts have not been presented for the year ended December 31, 2017, due to our adoption of ASU 2014-09, Revenues from Contracts with Customers, under the modified retrospective method. (in millions) Wisconsin Illinois Other States Total Utility Operations Non-Utility Energy Infrastructure Corporate and Other Reconciling Eliminations WEC Energy Group Consolidated Year ended December 31, 2019 Electric $ 4,307.7 $ — $ — $ 4,307.7 $ — $ — $ — $ 4,307.7 Natural gas 1,324.1 1,332.4 411.6 3,068.1 47.4 — (44.1 ) 3,071.4 Total regulated revenues 5,631.8 1,332.4 411.6 7,375.8 47.4 — (44.1 ) 7,379.1 Other non-utility revenues — 0.1 16.6 16.7 55.2 4.0 (5.7 ) 70.2 Total revenues from contracts with customers 5,631.8 1,332.5 428.2 7,392.5 102.6 4.0 (49.8 ) 7,449.3 Other operating revenues 15.3 24.6 (2.2 ) 37.7 393.3 0.4 (357.6 ) 73.8 Total operating revenues $ 5,647.1 $ 1,357.1 $ 426.0 $ 7,430.2 $ 495.9 $ 4.4 $ (407.4 ) $ 7,523.1 (in millions) Wisconsin Illinois Other States Total Utility Operations Non-Utility Energy Infrastructure Corporate and Other Reconciling Eliminations WEC Energy Group Consolidated Year ended December 31, 2018 Electric $ 4,432.4 $ — $ — $ 4,432.4 $ — $ — $ — $ 4,432.4 Natural gas 1,350.6 1,406.9 428.4 3,185.9 45.4 — (36.4 ) 3,194.9 Total regulated revenues 5,783.0 1,406.9 428.4 7,618.3 45.4 — (36.4 ) 7,627.3 Other non-utility revenues — 0.2 16.1 16.3 34.6 7.9 (5.8 ) 53.0 Total revenues from contracts with customers 5,783.0 1,407.1 444.5 7,634.6 80.0 7.9 (42.2 ) 7,680.3 Other operating revenues 11.7 (7.1 ) (6.3 ) (1.7 ) 388.4 0.8 (388.3 ) (0.8 ) Total operating revenues $ 5,794.7 $ 1,400.0 $ 438.2 $ 7,632.9 $ 468.4 $ 8.7 $ (430.5 ) $ 7,679.5 |
Revenues from contracts with customers | Electric | |
Disaggregation of Operating Revenues | |
Operating revenues disaggregated by revenue source | The following table disaggregates electric utility operating revenues into customer class: Electric Utility Operating Revenues Year Ended December 31 (in millions) 2019 2018 Residential $ 1,608.6 $ 1,636.3 Small commercial and industrial 1,384.6 1,408.6 Large commercial and industrial 871.9 912.2 Other 29.6 29.9 Total retail revenues 3,894.7 3,987.0 Wholesale 189.5 210.1 Resale 163.1 192.2 Steam 23.3 24.1 Other utility revenues 37.1 19.0 Total electric utility operating revenues $ 4,307.7 $ 4,432.4 |
Revenues from contracts with customers | Natural gas | |
Disaggregation of Operating Revenues | |
Operating revenues disaggregated by revenue source | The following tables disaggregate natural gas utility operating revenues into customer class: (in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues Year Ended December 31, 2019 Residential $ 837.9 $ 857.8 $ 258.2 $ 1,953.9 Commercial and industrial 419.9 261.7 148.7 830.3 Total retail revenues 1,257.8 1,119.5 406.9 2,784.2 Transport 72.6 245.3 31.6 349.5 Other utility revenues * (6.3 ) (32.4 ) (26.9 ) (65.6 ) Total natural gas utility operating revenues $ 1,324.1 $ 1,332.4 $ 411.6 $ 3,068.1 (in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues Year Ended December 31, 2018 Residential $ 834.5 $ 877.5 $ 263.3 $ 1,975.3 Commercial and industrial 436.7 266.9 140.0 843.6 Total retail revenues 1,271.2 1,144.4 403.3 2,818.9 Transport 70.8 244.1 31.8 346.7 Other utility revenues * 8.6 18.4 (6.7 ) 20.3 Total natural gas utility operating revenues $ 1,350.6 $ 1,406.9 $ 428.4 $ 3,185.9 * Includes amounts collected from (refunded 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: Year Ended December 31 (in millions) 2019 2018 We Power revenues $ 25.4 $ 25.3 Wind generation revenues 24.0 3.6 Appliance service revenues 16.6 15.9 Distributed renewable solar project revenues 4.0 8.0 Other 0.2 0.2 Total other non-utility operating revenues $ 70.2 $ 53.0 |
Other operating revenues | |
Disaggregation of Operating Revenues | |
Operating revenues disaggregated by revenue source | Other operating revenues consist primarily of the following: Year Ended December 31 (in millions) 2019 2018 Late payment charges $ 43.7 $ 40.3 Alternative revenues * (9.6 ) (45.6 ) Other 39.7 4.5 Total other operating revenues $ 73.8 $ (0.8 ) * Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. Negative amounts can also result from revenues to be refunded to customers subject to decoupling mechanisms and wholesale true-ups, as discussed in Note 1(d), Operating Revenues . |
Regulatory Assets and Liabili_2
Regulatory Assets and Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Schedule of regulatory assets | The following regulatory assets were reflected on our balance sheets as of December 31: (in millions) 2019 2018 See Note Regulatory assets (1) (2) Pension and OPEB costs (3) $ 1,066.6 $ 1,193.5 19 Plant retirements (4) 856.4 832.3 6 Environmental remediation costs (5) 685.5 687.1 23 Income tax related items (6) 457.8 369.1 15 SSR (7) 151.5 316.7 25 AROs 137.5 185.4 8 Uncollectible expense (8) 52.2 38.7 1(d) Derivatives 33.8 17.8 1(q) We Power generation (9) 25.8 43.0 Electric transmission costs 0.3 58.1 25 Other, net 60.2 114.1 Total regulatory assets $ 3,527.6 $ 3,855.8 Balance sheet presentation Other current assets $ 20.9 $ 50.7 Regulatory assets 3,506.7 3,805.1 Total regulatory assets $ 3,527.6 $ 3,855.8 (1) Based on prior and current rate treatment, we believe it is probable that our utilities will continue to recover from customers the regulatory assets in this table. In accordance with GAAP, our regulatory assets do not include the allowance for ROE that is capitalized for regulatory purposes. This allowance was $24.3 million and $18.2 million at December 31, 2019 and 2018 , respectively. (2) As of December 31, 2019 , we had $175.1 million of regulatory assets not earning a return, $29.1 million of regulatory assets earning a return based on short-term interest rates, and $151.5 million of regulatory assets earning a return based on long-term interest rates. The regulatory assets not earning a return primarily relate to certain environmental remediation costs, the recovery of which depends on the timing of the actual expenditures, as well as uncollectible expense, our electric real-time market pricing program, and unamortized loss on reacquired debt. The other regulatory assets in the table either earn a return at the applicable utility's weighted average cost of capital or the cash has not yet been expended, in which case the regulatory assets are offset by liabilities. (3) Primarily represents the unrecognized future pension and OPEB costs related to our defined benefit pension and OPEB plans. We are authorized recovery of these regulatory assets over the average remaining service life of each plan. (4) In accordance with the rate orders issued by the PSCW in December 2019, amounts previously collected from customers for the future removal of our recently retired plants were used to reduce our unrecovered plant balances during December 2019. Any additional removal costs that we incur will increase our plant retirement regulatory assets. (5) As of December 31, 2019 , we had made cash expenditures of $96.3 million related to these environmental remediation costs. The remaining $589.2 million represents our estimated future cash expenditures. (6) For information on the flow through of tax repairs and the regulatory treatment of the impacts of the Tax Legislation in our various jurisdictions, see Note 25, Regulatory Environment . (7) As a result of the rate order WE received from the PSCW in December 2019, the regulatory liability related to its mines deferral was offset against its SSR regulatory asset during December 2019. The rate order also authorized recovery of WE's SSR regulatory asset over a 15-year period that began on January 1, 2020. (8) Represents amounts recoverable from customers related to our uncollectible expense tracking mechanisms and riders. These mechanisms allow us to recover or refund the difference between actual uncollectible write-offs and the amounts recovered in rates. (9) Represents amounts recoverable from customers related to WE's costs of the generating units leased from We Power, including subsequent capital additions. |
Schedule of regulatory liabilities | The following regulatory liabilities were reflected on our balance sheets as of December 31: (in millions) 2019 2018 See Note Regulatory liabilities Income tax related items (1) $ 2,248.8 $ 2,406.6 15 Removal costs (2) 1,181.5 1,329.6 Pension and OPEB benefits (3) 354.9 238.3 19 Energy costs refundable through rate adjustments (4) 89.8 39.6 1(d) Earnings sharing mechanisms (5) 43.5 30.0 25 Electric transmission costs (5) 42.2 9.7 25 Uncollectible expense (6) 39.1 30.5 1(d) Decoupling 36.8 30.5 1(d) Energy efficiency programs (7) 30.7 31.7 Derivatives 6.7 16.4 1(q) Mines deferral (8) — 120.8 Other, net 6.4 4.7 Total regulatory liabilities $ 4,080.4 $ 4,288.4 Balance sheet presentation Other current liabilities $ 87.6 $ 36.8 Regulatory liabilities 3,992.8 4,251.6 Total regulatory liabilities $ 4,080.4 $ 4,288.4 (1) For information on the regulatory treatment of the impacts of the Tax Legislation in our various jurisdictions, see Note 25, Regulatory Environment . (2) Represents amounts collected from customers to cover the future cost of property, plant, and equipment removals that are not legally required. Legal obligations related to the removal of property, plant, and equipment are recorded as AROs. See Note 8, Asset Retirement Obligations, for more information on our legal obligations. (3) Primarily represents the unrecognized future pension and OPEB benefits related to our defined benefit pension and OPEB plans. We will amortize these regulatory liabilities into net periodic benefit cost over the average remaining service life of each plan. (4) Represents an over-collection of energy costs that will be refunded to customers in the future. When the rates we charge to customers include energy costs that are higher than our actual energy costs, any over-collection outside of the allowable energy cost price variance is refunded to customers. (5) Based on orders received from the PSCW, WE was required to apply the refunds due to customers from its earnings sharing mechanism to its electric transmission escrow through 2019. As a result, $38.6 million of WE's earnings sharing refunds were reflected in its electric transmission regulatory liability at December 31, 2019, and $37.2 million of WE's earnings sharing refunds were netted against its electric transmission regulatory asset at December 31, 2018. (6) Represents amounts refundable to customers related to our uncollectible expense tracking mechanisms and riders. These mechanisms allow us to recover or refund the difference between actual uncollectible write-offs and the amounts recovered in rates. (7) Represents amounts refundable to customers related to programs at the utilities designed to meet energy efficiency standards. (8) Represents the deferral of revenues less the associated cost of sales related to Tilden, which were not included in the PSCW's 2015 rate order. As a result of the rate order WE received from the PSCW in December 2019, this regulatory liability was offset against WE's SSR regulatory asset during December 2019. |
Property, Plant, and Equipment
Property, Plant, and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment - Balances | Property, plant, and equipment consisted of the following at December 31: (in millions) 2019 2018 Electric – generation $ 6,858.8 $ 6,410.6 Electric – distribution 7,018.1 6,534.6 Natural gas – distribution, storage, and transmission 11,602.7 10,766.3 Property, plant, and equipment to be retired, net — 174.8 Other 1,696.7 1,649.1 Less: Accumulated depreciation 8,073.7 7,573.6 Net 19,102.6 17,961.8 CWIP 820.4 707.5 Net utility property, plant, and equipment 19,923.0 18,669.3 We Power generation 3,245.7 3,244.4 Renewable generation 716.5 193.3 Natural gas storage 245.9 244.8 Net non-utility energy infrastructure 4,208.1 3,682.5 Corporate services 180.4 171.0 Other 88.8 127.1 Less: Accumulated depreciation 805.0 731.5 Net 3,672.3 3,249.1 CWIP 24.8 82.5 Net non-utility and other property, plant, and equipment 3,697.1 3,331.6 Total property, plant, and equipment $ 23,620.1 $ 22,000.9 |
Schedule of changes to our severance liability | Activity related to this severance liability for the years ended December 31 was as follows: (in millions) 2019 2018 Severance liability at January 1 $ 15.7 $ 29.4 Severance payments (7.2 ) (10.7 ) Other (6.4 ) (3.0 ) Total severance liability at December 31 $ 2.1 $ 15.7 |
Jointly Owned Utility Facilit_2
Jointly Owned Utility Facilities (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Jointly Owned Utility Plant, Net Ownership Amount [Abstract] | |
Schedule of Jointly Owned Utility Plants | Information related to jointly owned utility facilities at December 31, 2019 was as follows: We Power WPS (in millions, except for percentages and MW) Elm Road Generating Station Units 1 and 2 Weston Unit 4 Columbia Energy Center Units 1 and 2 (2) Forward Wind Energy Center Ownership 83.34 % 70.0 % 27.6 % 44.6 % Share of rated capacity (MW) (1) 1,054.3 386.0 313.9 8.4 In-service date 2010 and 2011 2008 1975 and 1978 2008 Property, plant, and equipment $ 2,447.9 $ 663.2 $ 422.3 $ 118.7 Accumulated depreciation $ (416.1 ) $ (232.4 ) $ (129.5 ) $ (46.4 ) CWIP $ 0.8 $ 5.3 $ 1.8 $ 0.1 (1) Capacity for our electric generation facilities is based on rated capacity, which is the net power output under average operating conditions with equipment in an average state of repair as of a given month in a given year. Values are primarily based on the net dependable expected capacity ratings for summer 2020 established by tests and may change slightly from year to year. The summer period is the most relevant for capacity planning purposes. This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand. (2) Columbia Energy Center is jointly owned by Wisconsin Power and Light, Madison Gas and Electric, and WPS. In October 2016, Wisconsin Power and Light received an order from the PSCW approving amendments to the Columbia Energy Center joint operating agreement between the parties allowing WPS and Madison Gas and Electric to forgo certain capital expenditures at the Columbia Energy Center. As a result, Wisconsin Power and Light will incur these capital expenditures in exchange for a proportional increase in its ownership share of the Columbia Energy Center. Based upon the additional capital expenditures Wisconsin Power and Light expects to incur through June 1, 2020, WPS's ownership interest would decrease to 27.5% |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of changes to asset retirement obligations | The following table shows changes to our AROs during the years ended December 31: (in millions) 2019 2018 2017 Balance as of January 1 $ 461.4 $ 573.7 $ 557.7 Accretion 22.1 28.0 27.5 Additions and revisions to estimated cash flows 39.1 (1) (104.5 ) (2) 26.5 Liabilities settled (39.1 ) (35.8 ) (38.0 ) Balance as of December 31 $ 483.5 $ 461.4 $ 573.7 (1) AROs increased $40.1 million in 2019, primarily due to new natural gas distribution lines being placed into service at PGL. Also in 2019, AROs increased $10.7 million as a result of AROs being recorded for the legal requirement to dismantle, at retirement, the wind generation projects known as Upstream and Coyote Ridge. See Note 2, Acquisitions, for more information on Upstream and Coyote Ridge. AROs decreased $7.3 million due to revisions made to estimated cash flows for the abatement of asbestos at WE. (2) AROs decreased $127.3 million in 2018 due to revisions made to estimated cash flows primarily for changes in the cost to retire natural gas distribution pipe at PGL. Also in 2018, AROs increased $10.7 million as a result of revisions made to estimated cash flows for the abatement of asbestos at WPS's Pulliam power plant, and a $10.9 million ARO was recorded for the legal requirement to dismantle, at retirement, the wind generation projects known as Forward Wind Energy Center and Bishop Hill III. See Note 2, Acquisitions, for more information on Forward Wind Energy Center and Bishop Hill III. |
Goodwill (Tables)
Goodwill (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Schedule of changes to goodwill balances by segment | The table below shows changes to our goodwill balances by segment during the years ended December 31, 2019 and 2018 : Wisconsin Illinois Other States Non-Utility Energy Infrastructure Total (in millions) 2019 2018 2019 2018 2019 2018 2019 2018 2019 2018 Goodwill balance as of January 1 $ 2,104.3 $ 2,104.3 $ 758.7 $ 758.7 $ 183.2 $ 183.2 $ 6.6 $ 7.3 $ 3,052.8 $ 3,053.5 Adjustment to Bluewater purchase price allocation (1) — — — — — — — (0.7 ) — (0.7 ) Goodwill balance as of December 31 (2) $ 2,104.3 $ 2,104.3 $ 758.7 $ 758.7 $ 183.2 $ 183.2 $ 6.6 $ 6.6 $ 3,052.8 $ 3,052.8 (1) See Note 2, Acquisitions, for more information on the acquisition of Bluewater. (2) We had no accumulated impairment losses related to our goodwill as of December 31, 2019 . |
Common Equity (Tables)
Common Equity (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Stockholders' Equity Note [Abstract] | |
Schedule of stock-based compensation expense and related deferred tax benefit recognized in income | The following table summarizes our pre-tax stock-based compensation expense and the related tax benefit recognized in income for the years ended December 31: (in millions) 2019 2018 2017 Stock options $ 4.4 $ 5.2 $ 3.4 Restricted stock 7.1 10.7 5.4 Performance units 38.7 20.2 20.2 Stock-based compensation expense $ 50.2 $ 36.1 $ 29.0 Related tax benefit $ 13.8 $ 9.9 $ 11.6 |
Schedule of stock option activity | The following is a summary of our stock option activity during 2019 : Stock Options Number of Options Weighted-Average Exercise Price Weighted-Average Remaining Contractual Life (in years) Aggregate Intrinsic Value (in millions) Outstanding as of January 1, 2019 4,452,533 $ 48.86 Granted 476,418 $ 68.18 Exercised (1,609,948 ) $ 41.63 Forfeited (69,085 ) $ 62.33 Outstanding as of December 31, 2019 3,249,918 $ 54.98 6.3 $ 121.0 Exercisable as of December 31, 2019 1,744,386 $ 46.92 4.8 $ 79.0 |
Schedule of restricted stock activity | The following restricted stock activity occurred during 2019 : Restricted Shares Number of Shares Weighted-Average Grant Date Fair Value Outstanding and unvested as of January 1, 2019 234,627 $ 61.01 Granted 97,343 $ 68.18 Released (192,291 ) $ 60.76 Forfeited (5,570 ) $ 62.99 Outstanding and unvested as of December 31, 2019 134,109 $ 66.48 |
Schedule of shares repurchased | The following is a summary of shares purchased to fulfill exercised stock options and restricted stock awards during the years ended December 31 : (in millions) 2019 2018 2017 Shares purchased 1.8 1.1 1.1 Cost of shares purchased $ 140.1 $ 72.4 $ 71.3 |
Schedule of dividends declared | During the year ended December 31, 2019 , our Board of Directors declared common stock dividends which are summarized below: Date Declared Date Payable Per Share Period January 17, 2019 March 1, 2019 $0.59 First quarter April 18, 2019 June 1, 2019 $0.59 Second quarter July 18, 2019 September 1, 2019 $0.59 Third quarter October 17, 2019 December 1, 2019 $0.59 Fourth quarter |
Preferred Stock (Tables)
Preferred Stock (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Class of Stock Disclosures [Abstract] | |
Schedule of preferred stock by class | The following table shows preferred stock authorized and outstanding at December 31, 2019 and 2018 : (in millions, except share and per share amounts) Shares Authorized Shares Outstanding Redemption Price Per Share Total WEC Energy Group $.01 par value Preferred Stock 15,000,000 — — $ — WE $100 par value, Six Per Cent. Preferred Stock 45,000 44,498 — 4.4 $100 par value, Serial Preferred Stock 3.60% Series 2,286,500 260,000 $ 101 26.0 $25 par value, Serial Preferred Stock 5,000,000 — — — WPS $100 par value, Preferred Stock 1,000,000 — — — PGL $100 par value, Cumulative Preferred Stock 430,000 — — — NSG $100 par value, Cumulative Preferred Stock 160,000 — — — Total $ 30.4 |
Short-Term Debt and Lines of _2
Short-Term Debt and Lines of Credit (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Short-term Debt [Abstract] | |
Short-term notes payable balances and their corresponding weighted-average interest rates | The following table shows our short-term borrowings and their corresponding weighted-average interest rates as of December 31: (in millions, except percentages) 2019 2018 Commercial paper Amount outstanding at December 31 $ 830.8 $ 1,440.1 Average interest rate on amounts outstanding at December 31 2.00 % 2.92 % |
Schedule of revolving credit facilities | The information in the table below relates to our revolving credit facilities used to support our commercial paper borrowing program, including remaining available capacity under these facilities as of December 31 : (in millions) Maturity 2019 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 830.8 Available capacity under existing agreements $ 1,966.9 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Debt Disclosure [Abstract] | |
Schedule of long-term debt instruments | The following table is a summary of our long-term debt outstanding (excluding finance/capital leases) as of December 31: (in millions) 2019 2018 Long-term debt Maturity Date Weighted Average Interest Rate Balance Weighted Average Interest Rate Balance WEC Energy Group Senior Notes (unsecured) (1) 2020-2033 3.47 % $ 2,050.0 3.54 % $ 1,700.0 WEC Energy Group Junior Notes (unsecured) (1) (2) 2067 4.50 % 500.0 4.85 % 500.0 WE Debentures (unsecured) 2021-2095 4.26 % 2,785.0 4.50 % 2,735.0 WPS Senior Notes (unsecured) 2021-2049 4.04 % 1,625.0 4.21 % 1,325.0 WG Debentures (unsecured) 2024-2046 3.65 % 640.0 4.04 % 490.0 Integrys Senior Notes (unsecured) 2020 4.17 % 250.0 4.17 % 250.0 Integrys Junior Notes (unsecured) (3) 2073 6.00 % 400.0 6.00 % 400.0 PGL First and Refunding Mortgage Bonds (secured) (4) 2024-2047 3.59 % 1,520.0 3.88 % 1,195.0 NSG First Mortgage Bonds (secured) (5) 2027-2043 3.81 % 132.0 3.81 % 132.0 MERC Senior Notes (unsecured) 2027-2047 3.51 % 120.0 3.51 % 120.0 MGU Senior Notes (unsecured) 2027-2047 3.51 % 90.0 3.51 % 90.0 UMERC Senior Notes (unsecured) 2029 3.26 % 160.0 N/A — Bluewater Gas Storage Senior Notes (unsecured) (6) 2020-2047 3.76 % 120.3 3.76 % 122.7 ATC Holding Senior Notes (unsecured) 2025-2030 4.05 % 475.0 4.34 % 240.0 We Power Subsidiaries Notes (secured, nonrecourse) (6) (7) 2020-2041 5.57 % 1,005.2 5.56 % 1,037.9 WECC Notes (unsecured) 2028 6.94 % 50.0 6.94 % 50.0 Total 11,922.5 10,387.6 Integrys acquisition fair value adjustment 14.3 20.6 Unamortized debt issuance costs (52.9 ) (44.7 ) Unamortized discount, net and other (25.6 ) (27.8 ) Total long-term debt, including current portion (8) 11,858.3 10,335.7 Current portion of long-term debt (686.9 ) (360.1 ) Total long-term debt $ 11,171.4 $ 9,975.6 (1) In connection with our outstanding 2007 Junior Notes, we executed an RCC, which we amended on June 29, 2015, for the benefit of persons that buy, hold, or sell a specified series of our long-term indebtedness (covered debt). Our 6.20% Senior Notes due April 1, 2033 have been designated as the covered debt under the RCC. The RCC provides that we may not redeem, defease, or purchase, and that our subsidiaries may not purchase, any 2007 Junior Notes on or before May 15, 2037, unless, subject to certain limitations described in the RCC, we have received a specified amount of proceeds from the sale of qualifying securities. (2) Variable interest rate reset quarterly. The rates were 4.02% and 4.73% as of December 31, 2019 and 2018 , respectively. On July 12, 2018 we executed two interest rate swaps that provided a fixed rate of 4.9765% on $250.0 million of the outstanding notes. The effective rates of 4.50% and 4.85% as of December 31, 2019 and 2018 , respectively, were blended rates of the variable and fixed portions. (3) Effective August 2023, Integrys's $400.0 million of 2013 6.00% Junior Subordinated Notes due 2073 will bear interest at the three-month LIBOR plus 322 basis points and will reset quarterly. (4) PGL's First Mortgage Bonds are subject to the terms and conditions of PGL's First Mortgage Indenture dated January 2, 1926, as supplemented. Under the terms of the Indenture, substantially all property owned by PGL is pledged as collateral for these outstanding debt securities. PGL has used certain First Mortgage Bonds to secure tax exempt interest rates. The Illinois Finance Authority has issued Tax Exempt Bonds, and the proceeds from the sale of these bonds were loaned to PGL. In return, PGL issued equal principal amounts of certain collateralized First Mortgage Bonds. The mandatory reset date for PGL's $50.0 million of 1.875% Bonds, series WW, is August 1, 2020. (5) NSG's First Mortgage Bonds are subject to the terms and conditions of NSG's First Mortgage Indenture dated April 1, 1955, as supplemented. Under the terms of the Indenture, substantially all property owned by NSG is pledged as collateral for these outstanding debt securities. (6) The long-term debt of Bluewater and We Power's subsidiaries amortizes on a mortgage-style basis. (7) We Power's subsidiaries' senior notes are secured by a collateral assignment of the leases between We Power's subsidiaries and WE related to PWGS and ERGS, as applicable. (8) The amount of long-term debt on our balance sheets includes finance/capital lease obligations of $45.9 million and $23.3 million at December 31, 2019 and 2018 |
Current maturities of long-term debt | The following table shows the long-term debt securities (excluding finance leases) maturing within one year of December 31, 2019 : (in millions) Interest Rate Maturity Date * Principal Amount WEC Energy Group Senior Notes (unsecured) 2.45% June $ 400.0 Integrys Senior Notes (unsecured) 4.17% November 250.0 Bluewater Gas Storage Senior Notes (unsecured) 3.76% Semi-annually 2.5 We Power Subsidiaries Notes – PWGS (secured, nonrecourse) 4.91% Monthly 6.6 We Power Subsidiaries Notes – ERGS (secured, nonrecourse) 5.209% Semi-annually 12.6 We Power Subsidiaries Notes – ERGS (secured, nonrecourse) 4.673% Semi-annually 9.7 We Power Subsidiaries Notes – PWGS (secured, nonrecourse) 6.00% Monthly 5.5 Total $ 686.9 * Maturity dates listed as semi-annually and monthly are associated with debt that amortizes on a mortgage-style basis. |
Schedule of maturities of long-term debt | The following table shows the future maturities of our long-term debt outstanding (excluding obligations under finance leases) as of December 31, 2019 : (in millions) Payments 2020 $ 686.9 2021 1,338.8 2022 390.8 2023 42.8 2024 570.0 Thereafter 8,893.2 Total $ 11,922.5 |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Leases [Abstract] | |
Schedule of lease expense and supplemental cash flow information for leases | The components of lease expense and supplemental cash flow information related to our leases for the years ended December 31 are as follows: (in millions) 2019 2018 2017 Finance/capital lease expense (1) $ 8.2 $ 7.7 $ 7.2 Operating lease expense (2) 5.5 5.6 6.4 Short-term lease expense (2) 0.6 1.5 0.8 Total lease expense $ 14.3 $ 14.8 $ 14.4 Other information Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from finance/capital leases (3) $ 3.3 $ 7.7 $ 7.2 Operating cash flows from operating leases $ 6.0 $ 6.5 $ 7.1 Financing cash flows from finance leases (3) $ 4.9 Non-cash activities: Right of use assets obtained in exchange for finance lease liabilities $ 27.2 Right of use assets obtained in exchange for operating lease liabilities $ 49.0 Weighted-average remaining lease term – finance leases 31.5 years Weighted-average remaining lease term – operating leases 12.9 years Weighted-average discount rate – finance lease (4) 6.7 % Weighted average discount rate – operating leases (4) 4.4 % (1) For the year ended December 31, 2019 , finance lease expense included amortization of right of use assets in the amount of $4.9 million (included in depreciation and amortization expense) and interest on lease liabilities of $3.3 million (included in interest expense). For the years ended December 31, 2018 and 2017 , total capital lease expense related to the long-term power purchase agreement was included in cost of sales. (2) Operating and short-term lease expense were included as a component of operation and maintenance for the years ended December 31, 2019 , 2018 , and 2017 . (3) Prior to our adoption of Topic 842 on January 1, 2019, all cash flows related to the finance lease were recorded as a component of operating cash flows. (4) Because our operating leases do not provide an implicit rate of return, we used the fully collateralized incremental borrowing rates based upon information available for similarly rated companies in determining the present value of lease payments for our operating leases. For our power purchase agreement that meets the definition of a finance lease, the rate implicit in the lease was readily determinable. For our solar land leases that are finance leases, we used the fully collateralized incremental borrowing rates based upon information available for similarly rated companies in determining the present value of lease payments. |
Schedule of finance and operating lease right of use asset | The following table summarizes our finance lease right of use assets, which were included in property, plant and equipment on our balance sheets at December 31: (in millions) 2019 2018 Long-term power purchase commitment Under finance/capital lease $ 140.3 $ 140.3 Accumulated amortization (126.6 ) (120.9 ) Total long-term power purchase commitment $ 13.7 $ 19.4 Two Creeks land leases Under finance leases $ 7.7 $ — Accumulated amortization (0.1 ) — Total Two Creeks land leases $ 7.6 $ — Badger Hollow I land leases Under finance leases $ 19.5 $ — Accumulated amortization (0.2 ) — Total Badger Hollow I land leases $ 19.3 $ — Total finance lease right of use assets/capital lease asset $ 40.6 $ 19.4 |
Schedule of future minimum lease payments for operating and finance leases | Future minimum lease payments under our operating leases and our finance leases, and the present value of our net minimum lease payments as of December 31, 2019 , were as follows: (in millions) Total Operating Leases Power Purchase Commitment Two Creeks Badger Hollow I Total Finance Leases 2020 $ 6.8 $ 8.8 $ 0.2 $ 0.3 $ 9.3 2021 4.8 9.4 0.2 0.7 10.3 2022 4.8 4.2 0.2 0.7 5.1 2023 4.9 — 0.2 0.7 0.9 2024 4.8 — 0.2 0.7 0.9 Thereafter 30.1 — 22.8 53.4 76.2 Total minimum lease payments 56.2 22.4 23.8 56.5 102.7 Less: Interest (14.8 ) (4.0 ) (16.1 ) (36.7 ) (56.8 ) Present value of minimum lease payments 41.4 18.4 7.7 19.8 45.9 Less: Short-term lease liabilities (4.4 ) (6.3 ) — — (6.3 ) Long-term lease liabilities $ 37.0 $ 12.1 $ 7.7 $ 19.8 $ 39.6 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | |
Summary of income tax expense | The following table is a summary of income tax expense for the years ended December 31: (in millions) 2019 2018 2017 Current tax expense (benefit) $ (37.9 ) $ (127.5 ) $ 111.8 Deferred income taxes, net 167.7 300.1 274.4 Investment tax credit, net (4.8 ) (2.8 ) (2.7 ) Total income tax expense $ 125.0 $ 169.8 $ 383.5 |
Statutory rate reconciliation | The provision for income taxes for each of the years ended December 31 differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes as a result of the following: 2019 2018 2017 (2) Effective Effective Effective (in millions) Amount Tax Rate Amount Tax Rate Amount Tax Rate Statutory federal income tax $ 264.4 21.0 % $ 258.1 21.0 % $ 555.5 35.0 % State income taxes net of federal tax benefit 80.4 6.4 % 71.8 5.8 % 100.8 6.4 % Tax repairs (1) (122.8 ) (9.8 )% (120.7 ) (9.8 )% — — % Federal excess deferred tax amortization (34.9 ) (2.8 )% (16.8 ) (1.4 )% — — % Wind production tax credits (34.1 ) (2.7 )% (12.1 ) (1.0 )% (16.8 ) (1.1 )% Excess tax benefits – stock options (15.8 ) (1.3 )% (5.9 ) (0.5 )% (10.0 ) (0.6 )% Investment tax credit restored (4.8 ) (0.4 )% (2.8 ) (0.2 )% (2.7 ) (0.2 )% AFUDC – Equity (3.0 ) (0.2 )% (3.2 ) (0.3 )% (4.0 ) (0.3 )% Federal tax reform — — % — — % (226.9 ) (14.3 )% Other, net (4.4 ) (0.3 )% 1.4 0.2 % (12.4 ) (0.8 )% Total income tax expense $ 125.0 9.9 % $ 169.8 13.8 % $ 383.5 24.1 % (1) In accordance with a settlement agreement with the PSCW, WE flowed through the tax benefit of its repair related deferred tax liabilities in 2018 and 2019, to maintain certain regulatory asset balances at their December 31, 2017 levels. The flow through treatment of the repair related deferred tax liabilities offsets the negative income statement impact of holding the regulatory assets level, resulting in no change to net income. See Note 25, Regulatory Environment, for more information about the impact of the Tax Legislation and the Wisconsin rate order. (2) In 2017, the net impact of tax reform in the amount of $206.7 million is represented in both the Federal tax reform and State income taxes net of federal tax benefit lines above. |
Components of deferred income taxes classified as net current assets and net long-term liabilities | The components of deferred income taxes as of December 31 were as follows: (in millions) 2019 2018 Deferred tax assets Tax gross up – regulatory items $ 519.8 $ 579.2 Deferred revenues 106.3 129.3 Future tax benefits 101.0 70.6 Other 159.8 194.4 Total deferred tax assets 886.9 973.5 Valuation allowance (2.3 ) (11.4 ) Net deferred tax assets $ 884.6 $ 962.1 Deferred tax liabilities Property-related $ 3,609.0 $ 3,436.9 Investment in affiliates 531.7 420.6 Deferred costs – Plant retirements 232.0 176.0 Employee benefits and compensation 131.4 121.2 Other 149.8 195.5 Total deferred tax liabilities 4,653.9 4,350.2 Deferred tax liability, net $ 3,769.3 $ 3,388.1 |
Components of deferred tax assets associated with federal and state tax benefit carryforwards | The components of net deferred tax assets associated with federal and state tax benefit carryforwards as of December 31, 2019 and 2018 are summarized in the tables below: 2019 (in millions) Gross Value Deferred Tax Effect Valuation Allowance Earliest Year of Expiration Future tax benefits as of December 31, 2019 Federal tax credit $ — $ 75.4 $ — 2037 State net operating loss 287.1 17.6 (2.3 ) 2023 Other state benefits — 8.0 — 2019 Balance as of December 31, 2019 $ 287.1 $ 101.0 $ (2.3 ) 2018 (in millions) Gross Value Deferred Tax Effect Valuation Allowance Earliest Year of Expiration Future tax benefits as of December 31, 2018 Federal foreign tax credit $ — $ 9.7 $ (9.7 ) 2018 Other federal tax credit — 39.3 (1.7 ) 2038 State net operating loss 275.9 17.0 — 2023 Other state benefits — 4.6 — 2018 Balance as of December 31, 2018 $ 275.9 $ 70.6 $ (11.4 ) |
Reconciliation of the beginning and ending amount of unrecognized tax benefits | A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows: (in millions) 2019 2018 Balance as of January 1 $ 20.0 $ 17.3 Additions for tax positions of prior years 1.9 2.8 Additions based on tax positions related to the current year 0.2 0.1 Reductions for tax positions of prior years (4.2 ) (0.2 ) Balance as of December 31 $ 17.9 $ 20.0 |
Summary of income tax examinations | As of December 31, 2019 , with a few exceptions, we were subject to examination by federal and state or local tax authorities for the 2015 through 2019 tax years in our major operating jurisdictions as follows: Jurisdiction Years Federal 2015–2019 Illinois 2015–2019 Michigan 2015–2019 Minnesota 2015–2019 Wisconsin 2015–2019 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Fair Value Disclosures [Abstract] | |
Schedule of fair value of assets and liabilities measured on a recurring basis categorized by level within the fair value hierarchy | The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy: December 31, 2019 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 1.4 $ 2.0 $ — $ 3.4 FTRs — — 3.1 3.1 Coal contracts — 0.4 — 0.4 Total derivative assets $ 1.4 $ 2.4 $ 3.1 $ 6.9 Investments held in rabbi trust $ 85.3 $ — $ — $ 85.3 Derivative liabilities Natural gas contracts $ 21.4 $ 1.3 $ — $ 22.7 Coal contracts — 0.2 — 0.2 Interest rate swaps — 6.0 — 6.0 Total derivative liabilities $ 21.4 $ 7.5 $ — $ 28.9 December 31, 2018 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 6.3 $ 1.8 $ — $ 8.1 FTRs — — 7.4 7.4 Coal contracts — 0.4 — 0.4 Total derivative assets $ 6.3 $ 2.2 $ 7.4 $ 15.9 Investments held in rabbi trust $ 65.0 $ — $ — $ 65.0 Derivative liabilities Natural gas contracts $ 4.7 $ 0.8 $ — $ 5.5 Coal contracts — 0.1 — 0.1 Interest rate swaps — 2.3 — 2.3 Total derivative liabilities $ 4.7 $ 3.2 $ — $ 7.9 |
Reconciliation of changes in fair value of items categorized as level 3 measurements | The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy at December 31 : (in millions) 2019 2018 2017 Balance at the beginning of the period $ 7.4 $ 4.4 $ 5.1 Purchases 12.8 18.4 13.8 Settlements (17.1 ) (15.4 ) (14.5 ) Balance at the end of the period $ 3.1 $ 7.4 $ 4.4 |
Schedule of carrying value and estimated fair value of financial instruments not recorded at fair value | The following table shows the financial instruments included on our balance sheets that are not recorded at fair value at December 31 : 2019 2018 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock of subsidiary $ 30.4 $ 29.5 $ 30.4 $ 28.3 Long-term debt, including current portion * 11,858.3 13,035.9 10,335.7 10,554.9 * The carrying amount of long-term debt excludes finance and capital lease obligations of $45.9 million and $23.3 million at December 31, 2019 and 2018 , respectively. |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of derivative assets and liabilities | The following table shows our derivative assets and derivative liabilities, along with their classification on our balance sheets. None of our derivatives are designated as hedging instruments, with the exception of our interest rate swaps, which have been designated as cash flow hedges. December 31, 2019 December 31, 2018 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Other current Natural gas contracts $ 3.4 $ 21.8 $ 7.7 $ 5.3 FTRs 3.1 — 7.4 — Coal contracts 0.2 0.2 0.2 0.1 Interest rate swaps — 2.8 — 0.4 Total other current 6.7 24.8 15.3 5.8 Other long-term Natural gas contracts — 0.9 0.4 0.2 Coal contracts 0.2 — 0.2 — Interest rate swaps — 3.2 — 1.9 Total other long-term 0.2 4.1 0.6 2.1 Total $ 6.9 $ 28.9 $ 15.9 $ 7.9 |
Schedule of estimated notional sales volumes and realized gains (losses) | Our estimated notional sales volumes and realized gains (losses) were as follows for the years ended: December 31, 2019 December 31, 2018 December 31, 2017 (in millions) Volumes Gains (Losses) Volumes Gains Volumes Gains (Losses) Natural gas contracts 183.9 Dth $ (27.1 ) 173.2 Dth $ 24.6 123.1 Dth $ (8.0 ) Petroleum products contracts — gallons — 6.0 gallons 1.6 18.0 gallons (1.3 ) FTRs 31.2 MWh 16.3 30.5 MWh 15.9 36.2 MWh 14.0 Total $ (10.8 ) $ 42.1 $ 4.7 |
Schedule of net derivative instruments | The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets: December 31, 2019 December 31, 2018 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 6.9 $ 28.9 $ 15.9 $ 7.9 Gross amount not offset on the balance sheet (1.4 ) (21.4 ) (1) (4.0 ) (2) (4.9 ) (3) Net amount $ 5.5 $ 7.5 $ 11.9 $ 3.0 (1) Includes cash collateral posted of $20.0 million . (2) Includes cash collateral received of $0.2 million . (3) Includes cash collateral posted of $1.1 million . |
Schedule of cash flow hedges recorded in other comprehensive loss and earnings | The table below shows the amounts related to these cash flow hedges recorded in other comprehensive loss and in earnings, along with our total interest expense on the income statements, for the years ended December 31 : (in millions) 2019 2018 2017 Derivative losses recognized in other comprehensive loss $ (4.8 ) $ (2.9 ) $ — Net derivative gains reclassified from accumulated other comprehensive loss to interest expense 1.1 1.6 2.2 Total interest expense line item on the income statements 501.5 445.1 415.7 |
Guarantees (Tables)
Guarantees (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Guarantees [Abstract] | |
Schedule of outstanding guarantees | The following table shows our outstanding guarantees: Expiration (in millions) Total Amounts Committed at December 31, 2019 Less Than 1 Year 1 to 3 Years Over 3 Years Guarantees Guarantees supporting transactions of subsidiaries (1) $ 31.4 $ 10.2 $ 0.2 $ 21.0 Standby letters of credit (2) 103.0 1.2 0.2 101.6 Surety bonds (3) 9.9 9.9 — — Other guarantees (4) 11.7 0.9 — 10.8 Total guarantees $ 156.0 $ 22.2 $ 0.4 $ 133.4 (1) Consists of $4.0 million , $6.2 million , and $21.2 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 $11.7 million related to other indemnifications, for which a liability of $10.8 million related to workers compensation coverage was recorded on our balance sheets. |
Employee Benefits (Tables)
Employee Benefits (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Retirement Benefits [Abstract] | |
Reconciliation of the changes in the plans' benefit obligations and fair value of assets | The following tables provide a reconciliation of the changes in our plans' benefit obligations and fair value of assets: Pension Benefits OPEB Benefits (in millions) 2019 2018 2019 2018 Change in benefit obligation Obligation at January 1 $ 2,927.2 $ 3,163.7 $ 608.2 $ 818.5 Service cost 47.0 47.1 16.3 23.7 Interest cost 120.4 114.3 25.7 29.9 Participant contributions — — 12.3 15.5 Plan amendments — — (4.0 ) (3.5 ) Actuarial loss (gain) 269.3 (171.8 ) (60.7 ) (222.6 ) Benefit payments (240.2 ) (226.1 ) (42.3 ) (55.4 ) Federal subsidy on benefits paid N/A N/A 1.3 1.0 Transfer — — 1.8 1.1 Obligation at December 31 $ 3,123.7 $ 2,927.2 $ 558.6 $ 608.2 Change in fair value of plan assets Fair value at January 1 $ 2,690.8 $ 2,966.8 $ 771.7 $ 841.5 Actual return on plan assets 494.1 (122.2 ) 134.3 (35.2 ) Employer contributions 62.3 72.3 3.6 5.3 Participant contributions — — 12.3 15.5 Benefit payments (240.2 ) (226.1 ) (42.3 ) (55.4 ) Fair value at December 31 $ 3,007.0 $ 2,690.8 $ 879.6 $ 771.7 Funded status at December 31 $ (116.7 ) $ (236.4 ) $ 321.0 $ 163.5 |
Amounts recognized on the balance sheets at December 31 related to the funded status of the benefit plans | The amounts recognized on our balance sheets at December 31 related to the funded status of the benefit plans were as follows: Pension Benefits OPEB Benefits (in millions) 2019 2018 2019 2018 Other long-term assets $ 188.8 $ 139.1 $ 341.7 $ 210.8 Pension and OPEB obligations 305.5 375.5 20.7 47.3 Total net (liabilities) assets $ (116.7 ) $ (236.4 ) $ 321.0 $ 163.5 |
Information for pension plans with an accumulated benefit obligation in excess of plan assets | The following table shows information for pension plans with an accumulated benefit obligation in excess of plan assets. Amounts presented are as of December 31: (in millions) 2019 2018 Projected benefit obligation $ 1,810.1 $ 1,930.8 Accumulated benefit obligation 1,754.2 1,882.2 Fair value of plan assets 1,504.6 1,572.7 |
Amounts that had not yet been recognized in the entity's net periodic benefit cost | The following table shows the amounts that have not yet been recognized in our net periodic benefit cost as of December 31: Pension Benefits OPEB Benefits (in millions) 2019 2018 2019 2018 Pre-tax accumulated other comprehensive loss (1) Net actuarial loss (gain) $ 10.6 $ 14.5 $ (1.6 ) $ (1.6 ) Prior service credits — — (0.1 ) (0.1 ) Total $ 10.6 $ 14.5 $ (1.7 ) $ (1.7 ) Net regulatory assets (liabilities) (2) Net actuarial loss (gain) $ 1,067.7 $ 1,184.1 $ (266.6 ) $ (133.0 ) Prior service costs (credits) 2.7 4.9 (88.6 ) (100.0 ) Total $ 1,070.4 $ 1,189.0 $ (355.2 ) $ (233.0 ) (1) Amounts related to the nonregulated entities are included in accumulated other comprehensive loss. (2) Amounts related to the utilities and WBS are recorded as net regulatory assets or liabilities. |
Estimated amounts that will be amortized into net periodic benefit cost | The following table shows the estimated amounts that will be amortized into net periodic benefit cost during 2020 : (in millions) Pension Benefits OPEB Benefits Net actuarial loss (gain) $ 97.1 $ (21.5 ) Prior service costs (credits) 1.6 (15.0 ) Total 2020 – estimated amortization $ 98.7 $ (36.5 ) |
Schedule of the components of net periodic benefit cost | The components of net periodic benefit cost (credit) (including amounts capitalized to our balance sheets) for the years ended December 31 were as follows: Pension Benefits OPEB Benefits (in millions) 2019 2018 2017 2019 2018 2017 Service cost $ 47.0 $ 47.1 $ 44.6 $ 16.3 $ 23.7 $ 24.1 Interest cost 120.4 114.3 121.8 25.7 29.9 32.9 Expected return on plan assets (193.3 ) (196.5 ) (195.7 ) (54.7 ) (59.5 ) (55.5 ) Plan settlement 11.5 1.0 9.0 — — — Amortization of prior service cost (credit) 2.2 2.7 2.9 (15.4 ) (15.4 ) (12.3 ) Amortization of net actuarial loss 77.3 94.0 86.1 (6.6 ) 1.0 3.1 Net periodic benefit cost (credit) $ 65.1 $ 62.6 $ 68.7 $ (34.7 ) $ (20.3 ) $ (7.7 ) |
Weighted-average assumptions used to determine benefit obligations and net periodic benefit cost for the plans | The weighted-average assumptions used to determine the benefit obligations for the plans were as follows for the years ended December 31: Pension Benefits OPEB Benefits 2019 2018 2019 2018 Discount rate 3.41% 4.30% 3.39% 4.27% Rate of compensation increase 4.00% 3.66% N/A N/A Assumed medical cost trend rate (Pre 65) N/A N/A 6.00% 6.25% Ultimate trend rate (Pre 65) N/A N/A 5.00% 5.00% Year ultimate trend rate is reached (Pre 65) N/A N/A 2028 2024 Assumed medical cost trend rate (Post 65) N/A N/A 5.91% 6.01% Ultimate trend rate (Post 65) N/A N/A 5.00% 5.00% Year ultimate trend rate is reached (Post 65) N/A N/A 2028 2028 The weighted-average assumptions used to determine the net periodic benefit cost for the plans were as follows for the years ended December 31: Pension Benefits 2019 2018 2017 Discount rate 4.21% 3.71% 4.11% Expected return on plan assets 7.12% 7.12% 7.11% Rate of compensation increase 3.66% 3.66% 3.60% OPEB Benefits 2019 2018 2017 Discount rate 4.27% 3.63% 4.04% Expected return on plan assets 7.25% 7.25% 7.25% Assumed medical cost trend rate (Pre 65) 6.25% 6.50% 7.00% Ultimate trend rate (Pre 65) 5.00% 5.00% 5.00% Year ultimate trend rate is reached (Pre 65) 2024 2024 2021 Assumed medical cost trend rate (Post 65) 6.01% 6.09% 7.00% Ultimate trend rate (Post 65) 5.00% 5.00% 5.00% Year ultimate trend rate is reached (Post 65) 2028 2028 2021 |
Effects of a one-percentage-point change in assumed health care cost trend rates | For the year ended December 31, 2019 , a one-percentage-point change in assumed health care cost trend rates would have had the following effects: (in millions) 1% Increase 1% Decrease Effect on total of service and interest cost components of net periodic postretirement health care benefit cost $ 4.7 $ (3.8 ) Effect on health care component of the accumulated postretirement benefit obligations 43.5 (36.5 ) |
Investments recorded at fair value, by asset class | The following tables provide the fair values of our investments by asset class: December 31, 2019 Pension Plan Assets OPEB Assets (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Asset Class Equity securities: United States equity $ 335.6 $ — $ — $ 335.6 $ 103.0 $ — $ — $ 103.0 International equity 321.6 0.7 — 322.3 107.3 0.2 — 107.5 Fixed income securities: * United States bonds 94.3 887.4 — 981.7 119.1 165.9 — 285.0 International bonds 51.5 87.0 — 138.5 24.6 8.5 — 33.1 $ 803.0 $ 975.1 $ — $ 1,778.1 $ 354.0 $ 174.6 $ — $ 528.6 Investments measured at net asset value $ 1,228.9 $ 351.0 Total $ 803.0 $ 975.1 $ — $ 3,007.0 $ 354.0 $ 174.6 $ — $ 879.6 * This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries. December 31, 2018 Pension Plan Assets OPEB Assets (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Asset Class Equity securities: United States equity $ 281.7 $ — $ — $ 281.7 $ 88.2 $ — $ — $ 88.2 International equity 279.7 0.7 — 280.4 92.2 0.2 — 92.4 Fixed income securities: * United States bonds 123.7 838.8 — 962.5 119.6 150.8 — 270.4 International bonds 16.1 85.5 — 101.6 7.1 8.9 — 16.0 $ 701.2 $ 925.0 $ — $ 1,626.2 $ 307.1 $ 159.9 $ — $ 467.0 Investments measured at net asset value $ 1,064.6 $ 304.7 Total $ 701.2 $ 925.0 $ — $ 2,690.8 $ 307.1 $ 159.9 $ — $ 771.7 * This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries. |
Reconciliation of changes in the fair value of plan assets categorized as Level 3 measurements | The following table sets forth a reconciliation of changes in the fair value of pension and OPEB plan assets categorized as Level 3 in the fair value hierarchy: Private Equity and Real Estate International Equity (in millions) Pension OPEB Pension OPEB Beginning balance at January 1, 2018 $ 100.1 $ 7.7 $ 0.8 $ 0.2 Realized and unrealized gains (losses) 8.0 1.1 (0.1 ) — Purchases 18.3 1.5 — — Liquidations (1.7 ) (0.2 ) — — Transfers out of level 3 (124.7 ) (10.1 ) (0.7 ) (0.2 ) Ending balance at December 31, 2018 $ — $ — $ — $ — |
Schedule of expected future benefit payments | The following table shows the payments, reflecting expected future service, that we expect to make for pension and OPEB over the next 10 years: (in millions) Pension Benefits OPEB Benefits 2020 $ 236.9 $ 37.1 2021 236.7 34.7 2022 228.4 35.6 2023 226.8 36.1 2024 218.8 36.1 2025-2029 1,004.2 179.5 |
Investment in Transmission Af_2
Investment in Transmission Affiliates (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Schedule of changes to our investment in ATC | The following tables provide a reconciliation of the changes in our investments in ATC and ATC Holdco: 2019 (in millions) ATC ATC Holdco Total Balance at January 1 $ 1,625.3 $ 40.0 $ 1,665.3 Add: Earnings (loss) from equity method investment * 132.8 (5.2 ) 127.6 Add: Capital contributions 51.3 1.3 52.6 Less: Distributions 124.7 — 124.7 Balance at December 31 $ 1,684.7 $ 36.1 $ 1,720.8 * In November 2019, the FERC issued an order that addressed the complaints related to ATC's allowed ROE. Due to the numerous rehearing requests filed related to this order, our financials continue to include a $41.9 million liability for potential future refunds that ATC may be required to provide, resulting in reduced equity earnings from ATC. This liability reflects a 10.38% ROE for all periods covered by the complaints. 2018 (in millions) ATC ATC Holdco Total Balance at January 1 $ 1,515.8 $ 37.6 $ 1,553.4 Add: Earnings (loss) from equity method investment 139.6 (2.9 ) 136.7 Add: Capital contributions 48.2 5.3 53.5 Less: Distributions 78.2 — 78.2 Less: Other 0.1 — 0.1 Balance at December 31 $ 1,625.3 $ 40.0 $ 1,665.3 2017 (in millions) ATC ATC Holdco Total Balance at January 1 $ 1,443.9 (1) $ — $ 1,443.9 Add: Earnings (loss) from equity method investment 166.0 (11.7 ) 154.3 Add: Capital contributions 60.3 49.3 109.6 Less: Distributions 154.2 (2) — 154.2 Less: Other 0.2 — 0.2 Balance at December 31 $ 1,515.8 $ 37.6 $ 1,553.4 (1) Distributions of $35.2 million , received in the first quarter of 2017, were approved and recorded as a receivable from ATC in other current assets at December 31, 2016 . (2) Of this amount, $39.9 million was recorded as a receivable from ATC in other current assets at December 31, 2017 . |
Schedule of significant related party transactions with ATC | The following table summarizes our significant related party transactions with ATC during the years ended December 31: (in millions) 2019 2018 2017 Charges to ATC for services and construction $ 25.9 $ 21.8 $ 17.1 Charges from ATC for network transmission services 348.1 338.1 349.3 Refund from ATC related to a FERC audit — 22.0 — Refund from ATC per FERC ROE order — — 28.3 |
Schedule of receivables and payables with ATC | As of December 31, 2019 and 2018 , our balance sheets included the following receivables and payables for services received from or provided to ATC: (in millions) 2019 2018 Accounts receivable for services provided to ATC $ 3.5 $ 3.4 Accounts payable for services received from ATC 29.0 28.2 Amounts due from ATC for transmission infrastructure upgrades 2.8 (1) 29.4 (2) (1) In connection with WPS's construction of its two new solar projects, Badger Hollow I and Two Creeks, WPS was required to initially fund the construction of the transmission infrastructure upgrades needed for the new generation. ATC owns these transmission assets and will reimburse WPS for these costs after the new generation has been placed in service. (2) In connection with UMERC's construction of the new natural gas-fired generation in the Upper Peninsula of Michigan, UMERC was required to initially fund the construction of the transmission infrastructure upgrades owned by ATC that were needed for the new generation. In the second quarter of 2019, ATC fully reimbursed UMERC for these costs. |
Schedule of summarized income statement data for ATC | Summarized financial data for ATC is included in the tables below: Year Ended December 31 (in millions) 2019 2018 2017 Income statement data Operating revenues $ 744.4 $ 690.5 $ 721.7 Operating expenses 373.5 358.7 345.0 Other expense, net 110.5 108.3 104.1 Net income $ 260.4 $ 223.5 $ 272.6 |
Schedule of summarized balance sheet data for ATC | (in millions) December 31, 2019 December 31, 2018 Balance sheet data Current assets $ 84.7 $ 87.2 Noncurrent assets 5,244.2 4,928.8 Total assets $ 5,328.9 $ 5,016.0 Current liabilities $ 502.6 $ 640.0 Long-term debt 2,312.8 2,014.0 Other noncurrent liabilities 298.9 295.3 Shareholders' equity 2,214.6 2,066.7 Total liabilities and shareholders' equity $ 5,328.9 $ 5,016.0 |
Segment Information (Tables)
Segment Information (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Segment Reporting [Abstract] | |
Schedule of information concerning our reportable segments | The following tables show summarized financial information related to our reportable segments for the years ended December 31, 2019 , 2018 , and 2017 . Utility Operations 2019 (in millions) Wisconsin Illinois Other States Total Utility Operations Electric Transmission Non-Utility Energy Infrastructure Corporate and Other Reconciling Eliminations WEC Energy Group Consolidated External revenues $ 5,647.1 $ 1,357.1 $ 426.0 $ 7,430.2 $ — $ 88.5 $ 4.4 $ — $ 7,523.1 Intersegment revenues — — — — — 407.4 — (407.4 ) — Other operation and maintenance 1,591.3 461.1 98.5 2,150.9 — 19.7 14.0 0.2 2,184.8 Depreciation and amortization 617.0 181.3 27.5 825.8 — 92.0 24.3 (15.8 ) 926.3 Operating income (loss) 1,189.6 291.9 65.3 1,546.8 — 366.6 (34.4 ) (347.6 ) 1,531.4 Equity in earnings of transmission affiliates — — — — 127.6 — — — 127.6 Interest expense 572.0 59.0 8.5 639.5 13.1 62.1 140.9 (354.1 ) 501.5 Capital expenditures and asset acquisitions 1,378.6 624.9 109.1 2,112.6 — 389.9 26.5 — 2,529.0 Total assets * 23,934.8 6,932.5 1,237.8 32,105.1 1,723.1 3,654.1 814.0 (3,344.5 ) 34,951.8 * Total assets at December 31, 2019 reflect an elimination of $1,896.7 million for all lease activity between We Power and WE. Utility Operations 2018 (in millions) Wisconsin Illinois Other States Total Utility Operations Electric Transmission Non-Utility Energy Infrastructure Corporate and Other Reconciling Eliminations WEC Energy Group Consolidated External revenues $ 5,794.7 $ 1,400.0 $ 438.2 $ 7,632.9 $ — $ 37.9 $ 8.7 $ — $ 7,679.5 Intersegment revenues — — — — — 430.5 — (430.5 ) — Other operation and maintenance 2,076.1 472.3 101.0 2,649.4 — 12.6 1.8 (393.3 ) 2,270.5 Depreciation and amortization 546.6 170.3 24.1 741.0 — 75.7 29.1 — 845.8 Operating income (loss) 800.2 255.8 68.8 1,124.8 — 365.8 (22.2 ) — 1,468.4 Equity in earnings of transmission affiliates — — — — 136.7 — — — 136.7 Interest expense 200.7 51.2 8.7 260.6 0.3 63.7 125.8 (5.3 ) 445.1 Capital expenditures and asset acquisitions 1,466.1 547.1 103.6 2,116.8 — 260.6 39.7 — 2,417.1 Total assets * 23,407.0 6,483.3 1,147.9 31,038.2 1,665.3 3,227.2 959.6 (3,414.5 ) 33,475.8 * Total assets at December 31, 2018 reflect an elimination of $1,968.5 million for all lease activity between We Power and WE. Utility Operations 2017 (in millions) Wisconsin Illinois Other States Total Utility Operations Electric Transmission Non-Utility Energy Infrastructure Corporate and Other Reconciling Eliminations WEC Energy Group Consolidated External revenues $ 5,829.2 $ 1,355.5 $ 411.2 $ 7,595.9 $ — $ 38.9 $ 13.7 $ — $ 7,648.5 Intersegment revenues — — — — — 446.3 — (446.3 ) — Other operation and maintenance 1,923.2 464.2 101.1 2,488.5 — 7.3 1.4 (441.1 ) 2,056.1 Depreciation and amortization 523.9 152.6 24.8 701.3 — 71.4 25.9 — 798.6 Operating income (loss) 1,055.2 279.9 54.4 1,389.5 — 400.5 (13.9 ) — 1,776.1 Equity in earnings of transmission affiliates — — — — 154.3 — — — 154.3 Interest expense 193.7 45.0 8.7 247.4 — 62.8 107.3 (1.8 ) 415.7 Capital expenditures 1,152.3 545.2 74.5 1,772.0 — 35.4 152.1 — 1,959.5 Total assets * 22,237.1 6,144.7 1,067.8 29,449.6 1,593.4 2,992.8 953.6 (3,398.9 ) 31,590.5 * Total assets at December 31, 2017 reflect an elimination of $2,038.1 million for all lease activity between We Power and WE. |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of minimum future commitments related to purchase obligations | The following table shows our minimum future commitments related to these purchase obligations as of December 31, 2019 , including those of our subsidiaries. Payments Due By Period (in millions) Date Contracts Extend Through Total Amounts Committed 2020 2021 2022 2023 2024 Later Years Electric utility: Nuclear 2033 $ 8,319.0 $ 475.1 $ 501.1 $ 531.2 $ 563.0 $ 596.8 $ 5,651.8 Coal supply and transportation 2024 983.2 306.9 255.7 223.4 196.5 0.7 — Purchased power 2051 428.3 88.9 58.5 51.5 46.5 43.4 139.5 Natural gas utility: Supply and transportation 2048 1,652.3 344.8 285.5 224.6 131.2 70.8 595.4 Non-utility energy infrastructure: Purchased power 2061 173.6 7.7 8.8 8.6 8.8 8.9 130.8 Natural gas storage and transportation 2048 13.6 7.7 2.7 1.3 0.8 0.1 1.0 Total $ 11,570.0 $ 1,231.1 $ 1,112.3 $ 1,040.6 $ 946.8 $ 720.7 $ 6,518.5 |
Schedule of regulatory assets and reserves related to manufactured gas plant sites | We have established the following regulatory assets and reserves for manufactured gas plant sites as of December 31: (in millions) 2019 2018 Regulatory assets $ 685.5 $ 687.1 Reserves for future environmental remediation 589.2 616.4 |
Supplemental Cash Flow Inform_2
Supplemental Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Supplemental Cash Flow Information [Abstract] | |
Schedule of supplemental cash flow information | Year Ended December 31 (in millions) 2019 2018 2017 Cash paid for interest, net of amount capitalized $ 485.9 $ 441.5 $ 413.7 Cash paid (received) for income taxes, net (24.9 ) 16.3 (5.2 ) Significant non-cash investing and financing transactions: Accounts payable related to construction costs 159.9 65.9 169.2 Capital contributions from noncontrolling interest 21.0 — — Receivable related to corporate-owned life insurance proceeds — 7.7 — Portion of Bostco real estate holdings sale financed with note receivable * — — 7.0 * See Note 3, Dispositions, for more information on this sale. |
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 at December 31 to the total of these amounts shown on the statements of cash flows: (in millions) 2019 2018 2017 Cash and cash equivalents $ 37.5 $ 84.5 $ 38.9 Restricted cash included in other current assets — 2.5 — Restricted cash included in other long term assets 44.8 59.1 19.7 Cash, cash equivalents, and restricted cash $ 82.3 $ 146.1 $ 58.6 |
Regulatory Environment (Tables)
Regulatory Environment (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Regulated Operations [Abstract] | |
Schedule of decisions in regulatory order | 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 are being amortized in 2020 and approximately $39 million will be amortized in 2021. The unprotected deferred tax benefits related to the unrecovered balances of WE's recently retired plants and its SSR regulatory asset are being 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 will be made to customers evenly over two years , with half being returned in 2020 and the remainder 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. |
Other Income, Net (Tables)
Other Income, Net (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Other Income and Expenses [Abstract] | |
Schedule of other income, net | Total other income, net was as follows for the years ended December 31 : (in millions) 2019 2018 2017 AFUDC – Equity $ 14.4 $ 15.2 $ 11.4 Non-service components of net periodic benefit costs 36.2 26.0 9.1 Gains (losses) from investments held in rabbi trust 21.2 (1.8 ) 21.5 Other, net 30.4 30.9 31.7 Other income, net $ 102.2 $ 70.3 $ 73.7 |
Quarterly Financial Informati_2
Quarterly Financial Information (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule of Quarterly Financial Information (unaudited) | (in millions, except per share amounts) First Quarter Second Quarter Third Quarter Fourth Quarter Total 2019 Operating revenues $ 2,377.4 $ 1,590.2 $ 1,608.0 $ 1,947.5 $ 7,523.1 Operating income 542.8 314.6 310.9 363.1 1,531.4 Net income attributed to common shareholders 420.1 235.7 234.3 243.9 1,134.0 Earnings per share * Basic $ 1.33 $ 0.75 $ 0.74 $ 0.77 $ 3.60 Diluted 1.33 0.74 0.74 0.77 3.58 2018 Operating revenues $ 2,286.5 $ 1,672.5 $ 1,643.7 $ 2,076.8 $ 7,679.5 Operating income 545.1 330.8 302.7 289.8 1,468.4 Net income attributed to common shareholders 390.1 231.0 233.2 205.0 1,059.3 Earnings per share * Basic $ 1.24 $ 0.73 $ 0.74 $ 0.65 $ 3.36 Diluted 1.23 0.73 0.74 0.65 3.34 * Earnings per share for the individual quarters may not total the year ended earnings per share amount because of changes to the average number of shares outstanding and changes in incremental issuable shares throughout the year. |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies Nature of Operations (Details) | Dec. 31, 2019 |
Electric | |
Product Information | |
Number of customers | 1,600,000 |
Natural gas | |
Product Information | |
Number of customers | 2,900,000 |
ATC | |
Product Information | |
Equity method investment, ownership interest (as a percent) | 60.00% |
ATC HoldCo | |
Product Information | |
Equity method investment, ownership interest (as a percent) | 75.00% |
Summary of Significant Accoun_5
Summary of Significant Accounting Policies Cash and Cash Equivalents (Details) | 12 Months Ended |
Dec. 31, 2019 | |
Accounting Policies [Abstract] | |
Maximum term of original maturity to classify instrument as cash equivalent | 3 months |
Summary of Significant Accoun_6
Summary of Significant Accounting Policies Operating Revenues (Details) $ in Millions | 1 Months Ended | 12 Months Ended | |
Jan. 31, 2019 | Dec. 31, 2019USD ($)contractperformance_obligations | Dec. 31, 2018USD ($) | |
Upstream | |||
Disaggregation of Operating Revenues | |||
Number of years Upstream will receive fixed payment | 10 years | ||
Electric | |||
Disaggregation of Operating Revenues | |||
Number of performance obligations | 1 | ||
Percent fuel costs can vary from the rate case approved costs before deferral is required | 2.00% | ||
Number of days payment is due | 30 days | ||
Electric | Wholesale | |||
Disaggregation of Operating Revenues | |||
Number of performance obligations | 2 | ||
Number of contracts | contract | 1 | ||
Natural gas | |||
Disaggregation of Operating Revenues | |||
Number of days payment is due | 30 days | ||
Other non-utility revenues | We Power revenues | |||
Disaggregation of Operating Revenues | |||
Revenues amortized from deferred revenue during the period | $ | $ 25.4 | $ 25.3 | |
Other non-utility revenues | Appliance service repairs | Maximum | |||
Disaggregation of Operating Revenues | |||
Duration of contract for remaining performance obligations in contract | 1 year | ||
Other non-utility revenues | Wind generation revenues | |||
Disaggregation of Operating Revenues | |||
Number of performance obligations | 1 | ||
Other non-utility revenues | Wind generation revenues | Upstream | |||
Disaggregation of Operating Revenues | |||
Number of years Upstream will receive fixed payment | 10 years |
Summary of Significant Accoun_7
Summary of Significant Accounting Policies Materials, Supplies, and Inventories (Details) $ in Millions | Dec. 31, 2019USD ($)$ / Dekatherm | Dec. 31, 2018USD ($)$ / Dekatherm |
Inventory | ||
Materials and supplies | $ 234.2 | $ 226.6 |
Natural gas in storage | 227.7 | 232.9 |
Fossil fuel | 87.9 | 88.7 |
Total | $ 549.8 | $ 548.2 |
Percentage of LIFO inventory | 19.00% | 16.00% |
PGL and NSG | ||
Inventory | ||
Excess of replacement or current costs over stated LIFO value | $ 9.8 | $ 72.4 |
Natural gas price benchmark | $ / Dekatherm | 1.95 | 3.08 |
Summary of Significant Accoun_8
Summary of Significant Accounting Policies Property, Plant and Equipment (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
PWGS | Minimum | |||
Property, plant, and equipment | |||
Estimated useful life | 10 years | ||
PWGS | Maximum | |||
Property, plant, and equipment | |||
Estimated useful life | 45 years | ||
ERGS | Minimum | |||
Property, plant, and equipment | |||
Estimated useful life | 10 years | ||
ERGS | Maximum | |||
Property, plant, and equipment | |||
Estimated useful life | 55 years | ||
Software | Minimum | |||
Property, plant, and equipment | |||
Estimated useful life | 3 years | ||
Software | Maximum | |||
Property, plant, and equipment | |||
Estimated useful life | 15 years | ||
WE | |||
Property, plant, and equipment | |||
Annual utility composite depreciation rate (as a percent) | 3.11% | 3.18% | 2.95% |
WPS | |||
Property, plant, and equipment | |||
Annual utility composite depreciation rate (as a percent) | 2.44% | 2.50% | 2.55% |
WG | |||
Property, plant, and equipment | |||
Annual utility composite depreciation rate (as a percent) | 2.29% | 2.30% | 2.30% |
PGL | |||
Property, plant, and equipment | |||
Annual utility composite depreciation rate (as a percent) | 3.20% | 3.25% | 3.29% |
NSG | |||
Property, plant, and equipment | |||
Annual utility composite depreciation rate (as a percent) | 2.48% | 2.45% | 2.43% |
MERC | |||
Property, plant, and equipment | |||
Annual utility composite depreciation rate (as a percent) | 2.33% | 1.95% | 2.51% |
Reduction in Depreciation Expense Related to Depreciation Study | $ 1.4 | ||
MGU | |||
Property, plant, and equipment | |||
Annual utility composite depreciation rate (as a percent) | 2.54% | 2.61% | 2.61% |
UMERC | |||
Property, plant, and equipment | |||
Annual utility composite depreciation rate (as a percent) | 2.87% | 2.50% | 2.46% |
Summary of Significant Accoun_9
Summary of Significant Accounting Policies AFUDC (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Allowance for Funds Used During Construction | |||
AFUDC - Debt | $ 5.9 | $ 6.9 | $ 4.9 |
AFUDC – Equity | $ 14.4 | 15.2 | 11.4 |
WE | |||
Allowance for Funds Used During Construction | |||
Percentage of retail jurisdictional construction work in progress expenditure subject to public utilities allowance for funds used during construction calculation | 50.00% | ||
AFUDC - Debt | $ 1.5 | 1.5 | 1.2 |
AFUDC – Equity | $ 3.7 | 3.9 | 3.1 |
WPS | |||
Allowance for Funds Used During Construction | |||
Percentage of retail jurisdictional construction work in progress expenditure subject to public utilities allowance for funds used during construction calculation | 50.00% | ||
AFUDC - Debt | $ 2.4 | 1.9 | 1.6 |
AFUDC – Equity | $ 5.7 | 4.6 | 4.1 |
WG | |||
Allowance for Funds Used During Construction | |||
Percentage of retail jurisdictional construction work in progress expenditure subject to public utilities allowance for funds used during construction calculation | 50.00% | ||
AFUDC - Debt | $ 0.5 | 0.2 | 0.3 |
AFUDC – Equity | $ 1.3 | 0.6 | 0.9 |
UMERC | |||
Allowance for Funds Used During Construction | |||
Percentage of retail jurisdictional construction work in progress expenditure subject to public utilities allowance for funds used during construction calculation | 50.00% | ||
AFUDC - Debt | $ 1.3 | 2.4 | 0.1 |
AFUDC – Equity | $ 3.3 | 5.4 | 0.2 |
WBS | |||
Allowance for Funds Used During Construction | |||
Percentage of retail jurisdictional construction work in progress expenditure subject to public utilities allowance for funds used during construction calculation | 50.00% | ||
AFUDC - Debt | $ 0.1 | 0.2 | 1.1 |
AFUDC – Equity | 0.2 | 0.6 | 3 |
Other | |||
Allowance for Funds Used During Construction | |||
AFUDC - Debt | 0.1 | 0.7 | 0.6 |
AFUDC – Equity | $ 0.2 | $ 0.1 | $ 0.1 |
Retail operations | WE | |||
Allowance for Funds Used During Construction | |||
Average AFUDC rate (as a percent) | 8.45% | ||
Retail operations | WPS | |||
Allowance for Funds Used During Construction | |||
Average AFUDC rate (as a percent) | 7.72% | ||
Retail operations | WG | |||
Allowance for Funds Used During Construction | |||
Average AFUDC rate (as a percent) | 8.33% | ||
Retail operations | UMERC | |||
Allowance for Funds Used During Construction | |||
Average AFUDC rate (as a percent) | 6.28% | ||
Retail operations | WBS | |||
Allowance for Funds Used During Construction | |||
Average AFUDC rate (as a percent) | 7.72% | ||
Wholesale operations | WE | |||
Allowance for Funds Used During Construction | |||
Average AFUDC rate (as a percent) | 5.11% | ||
Wholesale operations | WPS | |||
Allowance for Funds Used During Construction | |||
Average AFUDC rate (as a percent) | 2.58% |
Summary of Significant Accou_10
Summary of Significant Accounting Policies Stock-Based Compensation (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Number of shares authorized for issuance | 34,300,000 | |||
Stock options | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Vesting period (in years) | 3 years | |||
Minimum exercise price of stock option as a percent of common stock fair value on the grant date | 100.00% | |||
Period after the grant date during which stock options can't be exercised (in months) | 6 months | |||
Maximum term of awards (in years) | 10 years | |||
Stock options granted (in shares) | 476,418 | 710,710 | 552,215 | |
Estimated weighted-average fair value per stock option (in dollars per share) | $ 8.60 | $ 7.71 | $ 7.45 | |
Risk-free interest rate, minimum (as a percent) | 2.50% | 1.60% | 0.70% | |
Risk-free interest rate, maximum (as a percent) | 2.70% | 2.80% | 2.50% | |
Dividend yield (as a percent) | 3.60% | 3.50% | 3.50% | |
Expected volatility (as a percent) | 17.00% | 18.00% | 19.00% | |
Expected life (in years) | 8 years 6 months | 5 years 10 months 24 days | 6 years 9 months 18 days | |
Restricted stock | Employees | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Vesting period (in years) | 3 years | |||
Percentage to vest each year after grant date | 33.00% | |||
Restricted stock | Directors | Granted prior to January 1, 2017 | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Vesting period (in years) | 3 years | |||
Percentage to vest each year after grant date | 33.00% | |||
Restricted stock | Directors | Granted after January 1, 2017 | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Vesting period (in years) | 1 year | |||
Restricted stock | Certain Officers | Granted after January 1, 2017 | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Vesting period (in years) | 1 year | |||
Performance units | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Vesting period (in years) | 3 years | |||
Performance units | Minimum | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Payout ratio (as a percent) | 0.00% | |||
Performance units | Maximum | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Payout ratio (as a percent) | 175.00% | |||
ASU 2016-09 | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Cumulative effect adjustment from new accounting principle | $ 15.7 |
Summary of Significant Accou_11
Summary of Significant Accounting Policies Earnings Per Share (Details) - shares | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Stock options | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Antidilutive securities excluded from computation of earnings per share | 0 | 0 | 0 |
Summary of Significant Accou_12
Summary of Significant Accounting Policies Leases (Details) $ in Millions | 1 Months Ended | ||
Jan. 31, 2019USD ($) | Dec. 31, 2019USD ($) | Jan. 01, 2019USD ($)land_easement | |
Leases [Abstract] | |||
Impairment losses recorded upon adoption of ASU 2016-02 | $ 0 | ||
Number of land easements treated as leases upon adoption of ASU 2016-02 | land_easement | 0 | ||
Operating lease right of use assets | $ 41.4 | $ 49 | |
Operating lease liabilities | $ 41.4 | $ 48.8 | |
Finance lease expense impact of adoption of ASU 2016-02 | $ 0 |
Summary of Significant Accou_13
Summary of Significant Accounting Policies Income Taxes (Details) $ in Millions | Dec. 31, 2017USD ($) |
ASU 2018-02 Reclassification from AOCI, Tax Effect | |
Income taxes | |
Cumulative effect adjustment from adoption of ASU 2018-02 | $ 0.6 |
Summary of Significant Accou_14
Summary of Significant Accounting Policies Customer Concentrations of Credit Risk (Details) - Customer Concentration Risk | 12 Months Ended |
Dec. 31, 2019customer | |
Customer concentrations of credit risk | |
Number of customers that account for more than 10% of revenues | 0 |
Threshold percentage of revenues from major customers | 10.00% |
Acquisitions - Thunderhead (Det
Acquisitions - Thunderhead (Details) - Thunderhead Wind Energy LLC $ in Millions | 1 Months Ended | ||
Aug. 31, 2019MW | Feb. 19, 2020USD ($) | Dec. 31, 2019USD ($) | |
Business Acquisition [Line Items] | |||
Capacity of generation unit | MW | 300 | ||
Duration of offtake agreement for the sale of energy produced | 12 years | ||
Bonus depreciation percentage | 100.00% | ||
WECI | |||
Business Acquisition [Line Items] | |||
Ownership interest in wind generating facility acquired | 80.00% | ||
Acquisition purchase price | $ 338 | ||
Subsequent event | WECI | |||
Business Acquisition [Line Items] | |||
Acquisition purchase price | $ 43 | ||
Additional ownership interest acquired | 10.00% |
Acquisitions - Upstream (Detail
Acquisitions - Upstream (Details) - Upstream $ in Millions | 1 Months Ended | |
Jan. 31, 2019USD ($)MW | Feb. 19, 2020USD ($) | |
Business Acquisition [Line Items] | ||
Capacity of generation unit | MW | 202.5 | |
Cash and restricted cash acquired | $ 9.2 | |
Number of years Upstream will receive fixed payment | 10 years | |
Bonus depreciation percentage | 100.00% | |
Allocation of the purchase price | ||
Restricted cash | $ 8.1 | |
WECI | ||
Business Acquisition [Line Items] | ||
Ownership interest in wind generating facility acquired | 80.00% | |
Acquisition purchase price | $ 268.2 | |
Allocation of the purchase price | ||
Current assets | 1.5 | |
Net property, plant, and equipment | 341.6 | |
Other long-term assets | 22.9 | |
Current liabilities | (4.6) | |
Long-term liabilities | (15) | |
Noncontrolling interest | (69) | |
Total purchase price | $ 277.4 | |
Subsequent event | ||
Business Acquisition [Line Items] | ||
Additional ownership interest acquired | 10.00% | |
Subsequent event | WECI | ||
Business Acquisition [Line Items] | ||
Acquisition purchase price | $ 31 |
Acquisitions - Coyote Ridge (De
Acquisitions - Coyote Ridge (Details) - Coyote Ridge $ in Millions | 1 Months Ended | |
Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($)MW | |
Business Acquisition [Line Items] | ||
Capacity of generation unit | MW | 96.7 | |
Duration of offtake agreement for the sale of energy produced | 12 years | |
Bonus depreciation percentage | 100.00% | |
Percent of tax benefits entitled to | 99.00% | |
Duration of receiving 99% of tax benefits | 11 years | |
WECI | ||
Business Acquisition [Line Items] | ||
Ownership interest in wind generating facility acquired | 80.00% | |
Acquisition purchase price | $ 61.4 | |
Additional investment in Coyote Ridge | $ 84 | |
Total investment in Coyote Ridge | $ 145.4 | |
Allocation of the purchase price | ||
Net property, plant, and equipment | 66.4 | |
Noncontrolling interest | (5) | |
Total purchase price | $ 61.4 |
Acquisitions - Blooming Grove (
Acquisitions - Blooming Grove (Details) - Subsequent event - Blooming Grove Wind Energy Center $ in Millions | Feb. 19, 2020USD ($) | Jan. 27, 2020USD ($)MW |
Business Acquisition [Line Items] | ||
Capacity of generation unit | MW | 250 | |
Bonus depreciation percentage | 100.00% | |
WECI | ||
Business Acquisition [Line Items] | ||
Ownership interest in wind generating facility acquired | 80.00% | |
Acquisition purchase price | $ | $ 44 | $ 345 |
Additional ownership interest acquired | 10.00% |
Acquisitions - Bishop Hill III
Acquisitions - Bishop Hill III (Details) - Bishop Hill III Wind Energy Center $ in Millions | 1 Months Ended | |
Aug. 31, 2018USD ($)MW | Dec. 31, 2018USD ($) | |
Business Acquisition [Line Items] | ||
Capacity of generation unit | MW | 132.1 | |
Additional ownership interest acquired | 10.00% | |
Duration of offtake agreement for the sale of energy produced | 22 years | |
Bonus depreciation percentage | 100.00% | |
Allocation of the purchase price | ||
Other long-term assets | $ 4.5 | |
WECI | ||
Business Acquisition [Line Items] | ||
Ownership interest in wind generating facility acquired | 80.00% | |
Acquisition purchase price | $ 144.7 | $ 18.2 |
Allocation of the purchase price | ||
Current assets | 1.4 | |
Net property, plant, and equipment | 190.2 | |
Other long-term assets | 4.5 | |
Current liabilities | (1.6) | |
Long-term liabilities | (8.3) | |
Noncontrolling interest | (18.8) | |
Total purchase price | $ 167.4 |
Acquisitions - Forward Wind Ene
Acquisitions - Forward Wind Energy Center (Details) - Forward Wind Energy Center $ in Millions | 1 Months Ended |
Apr. 30, 2018USD ($)wind_turbinesutilityMW | |
Business Acquisition [Line Items] | |
Number of wind turbines at Forward Wind Energy Center | wind_turbines | 86 |
Capacity of generation unit | MW | 138 |
Allocation of the purchase price | |
Total purchase price | $ 172.9 |
WPS | |
Business Acquisition [Line Items] | |
Number of utilities along with WPS that entered in an agreement to purchase Forward Wind Energy Center | utility | 2 |
Ownership interest in wind generating facility acquired | 44.60% |
Transactions costs | $ 1.9 |
Percentage of Forward Wind Energy Center's output purchased by WPS | 44.60% |
Allocation of the purchase price | |
Current assets | $ 0.2 |
Net property, plant, and equipment | 76.9 |
Total purchase price | $ 77.1 |
Acquisitions - Bluewater - Purc
Acquisitions - Bluewater - Purchase Price Allocation (Details) - Bluewater $ in Millions | 1 Months Ended |
Jun. 30, 2017USD ($) | |
Business Acquisition [Line Items] | |
Current assets | $ 2 |
Net property, plant, and equipment | 217.6 |
Goodwill | 7.3 |
Current liabilities | (0.9) |
Total purchase price | $ 226 |
Dispositions (Details)
Dispositions (Details) - Corporate and Other $ in Millions | 12 Months Ended |
Dec. 31, 2019USD ($)solar_projects | |
Dispositions | |
Number of PDL Solar Power facilities sold | solar_projects | 4 |
Proceeds from sale | $ 26.3 |
Income tax expense | |
Dispositions | |
After-tax gain on sale | $ 6.5 |
Operating Revenues - Disaggrega
Operating Revenues - Disaggregation Of Operating Revenues by Segment (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Disaggregation of Operating Revenues | |||||||||||
Operating revenues | $ 1,947.5 | $ 1,608 | $ 1,590.2 | $ 2,377.4 | $ 2,076.8 | $ 1,643.7 | $ 1,672.5 | $ 2,286.5 | $ 7,523.1 | $ 7,679.5 | $ 7,648.5 |
Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | 7,449.3 | 7,680.3 | |||||||||
Other operating revenues | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Operating revenues | 73.8 | (0.8) | |||||||||
Total regulated revenues | Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | 7,379.1 | 7,627.3 | |||||||||
Electric | Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | 4,307.7 | 4,432.4 | |||||||||
Natural gas | Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | 3,071.4 | 3,194.9 | |||||||||
Natural gas | Transferred over time | Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | 3,068.1 | 3,185.9 | |||||||||
Other non-utility revenues | Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | 70.2 | 53 | |||||||||
Total Utility Operations | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Operating revenues | 7,430.2 | 7,632.9 | |||||||||
Total Utility Operations | Other operating revenues | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Operating revenues | 37.7 | (1.7) | |||||||||
Total Utility Operations | Transferred over time | Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | 7,392.5 | 7,634.6 | |||||||||
Total Utility Operations | Total regulated revenues | Transferred over time | Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | 7,375.8 | 7,618.3 | |||||||||
Total Utility Operations | Electric | Transferred over time | Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | 4,307.7 | 4,432.4 | |||||||||
Total Utility Operations | Natural gas | Transferred over time | Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | 3,068.1 | 3,185.9 | |||||||||
Total Utility Operations | Other non-utility revenues | Transferred over time | Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | 16.7 | 16.3 | |||||||||
Wisconsin | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Operating revenues | 5,647.1 | 5,794.7 | |||||||||
Wisconsin | Other operating revenues | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Operating revenues | 15.3 | 11.7 | |||||||||
Wisconsin | Transferred over time | Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | 5,631.8 | 5,783 | |||||||||
Wisconsin | Total regulated revenues | Transferred over time | Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | 5,631.8 | 5,783 | |||||||||
Wisconsin | Electric | Transferred over time | Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | 4,307.7 | 4,432.4 | |||||||||
Wisconsin | Natural gas | Transferred over time | Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | 1,324.1 | 1,350.6 | |||||||||
Wisconsin | Other non-utility revenues | Transferred over time | Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | 0 | 0 | |||||||||
Illinois | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Operating revenues | 1,357.1 | 1,400 | |||||||||
Illinois | Other operating revenues | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Operating revenues | 24.6 | (7.1) | |||||||||
Illinois | Transferred over time | Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | 1,332.5 | 1,407.1 | |||||||||
Illinois | Total regulated revenues | Transferred over time | Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | 1,332.4 | 1,406.9 | |||||||||
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 | 1,332.4 | 1,406.9 | |||||||||
Illinois | Other non-utility revenues | Transferred over time | Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | 0.1 | 0.2 | |||||||||
Other States | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Operating revenues | 426 | 438.2 | |||||||||
Other States | Other operating revenues | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Operating revenues | (2.2) | (6.3) | |||||||||
Other States | Transferred over time | Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | 428.2 | 444.5 | |||||||||
Other States | Total regulated revenues | Transferred over time | Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | 411.6 | 428.4 | |||||||||
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 | 411.6 | 428.4 | |||||||||
Other States | Other non-utility revenues | Transferred over time | Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | 16.6 | 16.1 | |||||||||
Non-Utility Energy Infrastructure | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Operating revenues | 495.9 | 468.4 | |||||||||
Non-Utility Energy Infrastructure | Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | 102.6 | 80 | |||||||||
Non-Utility Energy Infrastructure | Other operating revenues | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Operating revenues | 393.3 | 388.4 | |||||||||
Non-Utility Energy Infrastructure | Total regulated revenues | Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | 47.4 | 45.4 | |||||||||
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 | 47.4 | 45.4 | |||||||||
Non-Utility Energy Infrastructure | Other non-utility revenues | Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | 55.2 | 34.6 | |||||||||
Corporate and Other | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Operating revenues | 4.4 | 8.7 | |||||||||
Corporate and Other | Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | 4 | 7.9 | |||||||||
Corporate and Other | Other operating revenues | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Operating revenues | 0.4 | 0.8 | |||||||||
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 | 4 | 7.9 | |||||||||
Reconciling Eliminations | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Operating revenues | (407.4) | (430.5) | |||||||||
Reconciling Eliminations | Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | (49.8) | (42.2) | |||||||||
Reconciling Eliminations | Other operating revenues | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Operating revenues | (357.6) | (388.3) | |||||||||
Reconciling Eliminations | Total regulated revenues | Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | (44.1) | (36.4) | |||||||||
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 | (44.1) | (36.4) | |||||||||
Reconciling Eliminations | Other non-utility revenues | Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | $ (5.7) | $ (5.8) |
Operating Revenues - Disaggre_2
Operating Revenues - Disaggregation of Electric Utility Operating Revenues by Customer Class (Details) - Revenues from contracts with customers - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | $ 7,449.3 | $ 7,680.3 |
Electric | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 4,307.7 | 4,432.4 |
Wisconsin | Transferred over time | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 5,631.8 | 5,783 |
Wisconsin | Electric | Transferred over time | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 4,307.7 | 4,432.4 |
Wisconsin | Electric | Transferred over time | Total retail revenues | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 3,894.7 | 3,987 |
Wisconsin | Electric | Transferred over time | Residential | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 1,608.6 | 1,636.3 |
Wisconsin | Electric | Transferred over time | Small commercial and industrial | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 1,384.6 | 1,408.6 |
Wisconsin | Electric | Transferred over time | Large commercial and industrial | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 871.9 | 912.2 |
Wisconsin | Electric | Transferred over time | Other | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 29.6 | 29.9 |
Wisconsin | Electric | Transferred over time | Wholesale | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 189.5 | 210.1 |
Wisconsin | Electric | Transferred over time | Resale | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 163.1 | 192.2 |
Wisconsin | Electric | Transferred over time | Steam | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 23.3 | 24.1 |
Wisconsin | Electric | Transferred over time | Other utility revenues | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | $ 37.1 | $ 19 |
Operating Revenues - Disaggre_3
Operating Revenues - Disaggregation of Natural Gas Utility Operating Revenues by Customer Class (Details) - Revenues from contracts with customers - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | $ 7,449.3 | $ 7,680.3 |
Natural gas | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 3,071.4 | 3,194.9 |
Natural gas | Transferred over time | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 3,068.1 | 3,185.9 |
Natural gas | Transferred over time | Total retail revenues | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 2,784.2 | 2,818.9 |
Natural gas | Transferred over time | Residential | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 1,953.9 | 1,975.3 |
Natural gas | Transferred over time | Commercial and industrial | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 830.3 | 843.6 |
Natural gas | Transferred over time | Transport | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 349.5 | 346.7 |
Natural gas | Transferred over time | Other utility revenues | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | (65.6) | 20.3 |
Wisconsin | Transferred over time | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 5,631.8 | 5,783 |
Wisconsin | Natural gas | Transferred over time | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 1,324.1 | 1,350.6 |
Wisconsin | Natural gas | Transferred over time | Total retail revenues | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 1,257.8 | 1,271.2 |
Wisconsin | Natural gas | Transferred over time | Residential | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 837.9 | 834.5 |
Wisconsin | Natural gas | Transferred over time | Commercial and industrial | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 419.9 | 436.7 |
Wisconsin | Natural gas | Transferred over time | Transport | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 72.6 | 70.8 |
Wisconsin | Natural gas | Transferred over time | Other utility revenues | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | (6.3) | 8.6 |
Illinois | Transferred over time | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 1,332.5 | 1,407.1 |
Illinois | Natural gas | Transferred over time | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 1,332.4 | 1,406.9 |
Illinois | Natural gas | Transferred over time | Total retail revenues | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 1,119.5 | 1,144.4 |
Illinois | Natural gas | Transferred over time | Residential | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 857.8 | 877.5 |
Illinois | Natural gas | Transferred over time | Commercial and industrial | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 261.7 | 266.9 |
Illinois | Natural gas | Transferred over time | Transport | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 245.3 | 244.1 |
Illinois | Natural gas | Transferred over time | Other utility revenues | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | (32.4) | 18.4 |
Other States | Transferred over time | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 428.2 | 444.5 |
Other States | Natural gas | Transferred over time | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 411.6 | 428.4 |
Other States | Natural gas | Transferred over time | Total retail revenues | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 406.9 | 403.3 |
Other States | Natural gas | Transferred over time | Residential | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 258.2 | 263.3 |
Other States | Natural gas | Transferred over time | Commercial and industrial | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 148.7 | 140 |
Other States | Natural gas | Transferred over time | Transport | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 31.6 | 31.8 |
Other States | Natural gas | Transferred over time | Other utility revenues | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | $ (26.9) | $ (6.7) |
Operating Revenues - Other Non-
Operating Revenues - Other Non-Utility Operating Revenues (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | $ 7,449.3 | $ 7,680.3 |
Other non-utility revenues | We Power revenues | ||
Disaggregation of Operating Revenues | ||
Contract with Customer, Liability, Revenue Recognized | 25.4 | 25.3 |
Other non-utility revenues | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 70.2 | 53 |
Other non-utility revenues | Revenues from contracts with customers | We Power revenues | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 25.3 | |
Other non-utility revenues | Revenues from contracts with customers | Distributed renewable solar project revenues | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 4 | 8 |
Other non-utility revenues | Revenues from contracts with customers | Other | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 0.2 | 0.2 |
Transferred over time | Other non-utility revenues | Revenues from contracts with customers | Wind generation revenues | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 24 | 3.6 |
Transferred over time | Other non-utility revenues | Revenues from contracts with customers | Appliance service repairs | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | $ 16.6 | $ 15.9 |
Operating Revenues - Other Oper
Operating Revenues - Other Operating Revenues (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Disaggregation of Operating Revenues | |||||||||||
Operating revenues | $ 1,947.5 | $ 1,608 | $ 1,590.2 | $ 2,377.4 | $ 2,076.8 | $ 1,643.7 | $ 1,672.5 | $ 2,286.5 | $ 7,523.1 | $ 7,679.5 | $ 7,648.5 |
Other operating revenues | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Operating revenues | 73.8 | (0.8) | |||||||||
Other operating revenues | Late payment charges | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Operating revenues | 43.7 | 40.3 | |||||||||
Other operating revenues | Alternative revenues | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Operating revenues | (9.6) | (45.6) | |||||||||
Other operating revenues | Other | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Operating revenues | $ 39.7 | $ 4.5 |
Regulatory Assets and Liabili_3
Regulatory Assets and Liabilities - Regulatory Assets (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Regulatory assets | ||
Current assets | $ 20.9 | $ 50.7 |
Regulatory assets | 3,506.7 | 3,805.1 |
Total regulatory assets | 3,527.6 | 3,855.8 |
Allowance for return on equity capitalized for regulatory purposes | 24.3 | 18.2 |
Regulatory assets not earning a return | 175.1 | |
Regulatory assets earning a return based on short-term interest rates | 29.1 | |
Regulatory assets earning a return based on long-term interest rates | 151.5 | |
Estimated future cash expenditures for environmental remediation | 589.2 | 616.4 |
Pension and OPEB costs | ||
Regulatory assets | ||
Total regulatory assets | 1,066.6 | 1,193.5 |
Plant retirements | ||
Regulatory assets | ||
Total regulatory assets | 856.4 | 832.3 |
Environmental remediation costs | ||
Regulatory assets | ||
Total regulatory assets | 685.5 | 687.1 |
Cash expenditures for environmental remediation costs | 96.3 | |
Estimated future cash expenditures for environmental remediation | 589.2 | |
Income tax related items | ||
Regulatory assets | ||
Total regulatory assets | 457.8 | 369.1 |
System support resource (SSR) | ||
Regulatory assets | ||
Total regulatory assets | 151.5 | 316.7 |
Asset retirement obligations (AROs) | ||
Regulatory assets | ||
Total regulatory assets | 137.5 | 185.4 |
Uncollectible expense | ||
Regulatory assets | ||
Total regulatory assets | 52.2 | 38.7 |
Derivatives | ||
Regulatory assets | ||
Total regulatory assets | 33.8 | 17.8 |
We Power generation | ||
Regulatory assets | ||
Total regulatory assets | 25.8 | 43 |
Electric transmission costs | ||
Regulatory assets | ||
Total regulatory assets | 0.3 | 58.1 |
Refunds due to customers offset against electric transmission regulatory asset | 37.2 | |
Other, net | ||
Regulatory assets | ||
Total regulatory assets | $ 60.2 | $ 114.1 |
Regulatory Assets and Liabili_4
Regulatory Assets and Liabilities - Regulatory Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Regulatory liabilities | ||
Current liabilities | $ 87.6 | $ 36.8 |
Regulatory liabilities | 3,992.8 | 4,251.6 |
Total regulatory liabilities | 4,080.4 | 4,288.4 |
Income tax related items | ||
Regulatory liabilities | ||
Total regulatory liabilities | 2,248.8 | 2,406.6 |
Removal costs | ||
Regulatory liabilities | ||
Total regulatory liabilities | 1,181.5 | 1,329.6 |
Pension and OPEB costs | ||
Regulatory liabilities | ||
Total regulatory liabilities | 354.9 | 238.3 |
Energy costs refundable through rate adjustments | ||
Regulatory liabilities | ||
Total regulatory liabilities | 89.8 | 39.6 |
Earnings sharing mechanisms | ||
Regulatory liabilities | ||
Total regulatory liabilities | 43.5 | 30 |
Electric transmission costs | ||
Regulatory liabilities | ||
Total regulatory liabilities | 42.2 | 9.7 |
Refunds due to customers offset against electric transmission regulatory liability | 38.6 | |
Uncollectible expense | ||
Regulatory liabilities | ||
Total regulatory liabilities | 39.1 | 30.5 |
Decoupling | ||
Regulatory liabilities | ||
Total regulatory liabilities | 36.8 | 30.5 |
Energy efficiency programs | ||
Regulatory liabilities | ||
Total regulatory liabilities | 30.7 | 31.7 |
Derivatives | ||
Regulatory liabilities | ||
Total regulatory liabilities | 6.7 | 16.4 |
Mines deferral | ||
Regulatory liabilities | ||
Total regulatory liabilities | 0 | 120.8 |
Other, net | ||
Regulatory liabilities | ||
Total regulatory liabilities | $ 6.4 | $ 4.7 |
Property, Plant, and Equipmen_2
Property, Plant, and Equipment - Balances (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Property, plant, and equipment | ||
Accumulated depreciation | $ 8,878.7 | $ 8,515.9 |
Net property, plant, and equipment | 23,620.1 | 22,000.9 |
Utility operations | ||
Property, plant, and equipment | ||
Accumulated depreciation | 8,073.7 | 7,573.6 |
Net | 19,102.6 | 17,961.8 |
CWIP | 820.4 | 707.5 |
Net property, plant, and equipment | 19,923 | 18,669.3 |
Utility operations | Electric - generation | ||
Property, plant, and equipment | ||
Property, plant, and equipment | 6,858.8 | 6,410.6 |
Utility operations | Electric - distribution | ||
Property, plant, and equipment | ||
Property, plant, and equipment | 7,018.1 | 6,534.6 |
Utility operations | Natural gas - distribution, storage, and transmission | ||
Property, plant, and equipment | ||
Property, plant, and equipment | 11,602.7 | 10,766.3 |
Utility operations | Property, plant, and equipment to be retired, net | ||
Property, plant, and equipment | ||
Property, plant, and equipment to be retired, net | 0 | 174.8 |
Utility operations | Other | ||
Property, plant, and equipment | ||
Property, plant, and equipment | 1,696.7 | 1,649.1 |
Non-utility operations | ||
Property, plant, and equipment | ||
Accumulated depreciation | 805 | 731.5 |
Net | 3,672.3 | 3,249.1 |
CWIP | 24.8 | 82.5 |
Net property, plant, and equipment | 3,697.1 | 3,331.6 |
Non-utility operations | Other | ||
Property, plant, and equipment | ||
Property, plant, and equipment | 88.8 | 127.1 |
Non-utility operations | We Power generation | ||
Property, plant, and equipment | ||
Property, plant, and equipment | 3,245.7 | 3,244.4 |
Non-utility operations | Renewable generation | ||
Property, plant, and equipment | ||
Property, plant, and equipment | 716.5 | 193.3 |
Non-utility operations | Natural gas storage | ||
Property, plant, and equipment | ||
Property, plant, and equipment | 245.9 | 244.8 |
Non-utility operations | Corporate services | ||
Property, plant, and equipment | ||
Property, plant, and equipment | 180.4 | 171 |
Non-Utility Energy Infrastructure | Non-utility operations | ||
Property, plant, and equipment | ||
Property, plant, and equipment | $ 4,208.1 | $ 3,682.5 |
Property, Plant, and Equipmen_3
Property, Plant, and Equipment - Plant Retirements (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | |
Plant To Be Retired | ||
Net book value of plant classified as a regulatory asset | $ 3,527.6 | $ 3,855.8 |
Deferred tax liabilities | 3,609 | 3,436.9 |
Pleasant Prairie power plant | ||
Plant To Be Retired | ||
Net book value of plant, representing book value less cost of removal and accumulated depreciation | 615.1 | |
Previously deferred unprotected tax benefit | 20.6 | |
Net book value of plant classified as a regulatory asset | 594.5 | |
Deferred tax liabilities | 172.1 | |
Pleasant Prairie power plant's book value to be securitized | 100 | |
Presque Isle power plant | ||
Plant To Be Retired | ||
Net book value of plant, representing book value less cost of removal and accumulated depreciation | 162.7 | |
Previously deferred unprotected tax benefit | 6.4 | |
Net book value of plant classified as a regulatory asset | 156.3 | |
Deferred tax liabilities | 46.5 | |
Pulliam power plant | ||
Plant To Be Retired | ||
Net book value of plant classified as a regulatory asset | 36.3 | |
Wisconsin | ||
Restructuring Reserve [Roll Forward] | ||
Severance liability, balance at beginning of period | 15.7 | 29.4 |
Severance payments | (7.2) | (10.7) |
Other | (6.4) | (3) |
Severance liability, balance at end of period | 2.1 | $ 15.7 |
Edgewater Unit 4 | ||
Plant To Be Retired | ||
Net book value of plant classified as a regulatory asset | $ 5.3 |
Jointly Owned Utility Facilit_3
Jointly Owned Utility Facilities (Details) $ in Millions | Dec. 31, 2019USD ($)MW | Aug. 01, 2019MW | May 31, 2018solar_projects |
Elm Road Generating Station Units 1 and 2 | We Power | |||
Jointly Owned Electric Generating Facilities | |||
Ownership (as a percentage) | 83.34% | ||
Share of rated capacity (MW) (1) | MW | 1,054.3 | ||
Property, plant, and equipment | $ 2,447.9 | ||
Accumulated depreciation | (416.1) | ||
Construction Work in Progress | $ 0.8 | ||
Weston 4 | WPS | |||
Jointly Owned Electric Generating Facilities | |||
Ownership (as a percentage) | 70.00% | ||
Share of rated capacity (MW) (1) | MW | 386 | ||
Property, plant, and equipment | $ 663.2 | ||
Accumulated depreciation | (232.4) | ||
Construction Work in Progress | $ 5.3 | ||
Columbia Energy Center Units 1 and 2 | WPS | |||
Jointly Owned Electric Generating Facilities | |||
Future Ownership Interest of Columbia | 27.50% | ||
Ownership (as a percentage) | 27.60% | ||
Share of rated capacity (MW) (1) | MW | 313.9 | ||
Property, plant, and equipment | $ 422.3 | ||
Accumulated depreciation | (129.5) | ||
Construction Work in Progress | $ 1.8 | ||
Forward Wind Energy Center | WPS | |||
Jointly Owned Electric Generating Facilities | |||
Ownership (as a percentage) | 44.60% | ||
Share of rated capacity (MW) (1) | MW | 8.4 | ||
Property, plant, and equipment | $ 118.7 | ||
Accumulated depreciation | (46.4) | ||
Construction Work in Progress | $ 0.1 | ||
Badger Hollow and Two Creeks Solar Farms | WPS | |||
Jointly Owned Electric Generating Facilities | |||
Number Of Solar Projects Acquisition Approval Requested | solar_projects | 2 | ||
Capacity Of Solar Project Owned By Entity | MW | 200 | ||
Badger Hollow Solar Farm I | WPS | |||
Jointly Owned Electric Generating Facilities | |||
Construction Work in Progress | $ 32.5 | ||
Capacity Of Solar Project Owned By Entity | MW | 100 | ||
Two Creeks Solar Project | WPS | |||
Jointly Owned Electric Generating Facilities | |||
Construction Work in Progress | $ 87.3 | ||
Capacity Of Solar Project Owned By Entity | MW | 100 | ||
Badger Hollow Solar Farm II | WE | |||
Jointly Owned Electric Generating Facilities | |||
Capacity of Solar Project Approval Was Requested for from the PSCW | MW | 100 |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Changes to asset retirement obligations | |||
Balance as of January 1 | $ 461.4 | $ 573.7 | $ 557.7 |
Accretion | 22.1 | 28 | 27.5 |
Additions and revisions to estimated cash flows | 39.1 | (104.5) | 26.5 |
Liabilities settled | (39.1) | (35.8) | (38) |
Balance as of December 31 | 483.5 | 461.4 | $ 573.7 |
PGL | |||
Changes to asset retirement obligations | |||
ARO increase (decrease) due to revisions made to estimated cash flows | (127.3) | ||
ARO additions | 40.1 | ||
Upstream and Coyote Ridge | |||
Changes to asset retirement obligations | |||
ARO additions | 10.7 | ||
WE | |||
Changes to asset retirement obligations | |||
ARO increase (decrease) due to revisions made to estimated cash flows | $ (7.3) | ||
Pulliam power plant | |||
Changes to asset retirement obligations | |||
ARO increase (decrease) due to revisions made to estimated cash flows | 10.7 | ||
Forward Wind Energy Center and Bishop Hill III | |||
Changes to asset retirement obligations | |||
ARO additions | $ 10.9 |
Goodwill (Details)
Goodwill (Details) - USD ($) $ in Millions | Jul. 01, 2019 | Dec. 31, 2019 | Dec. 31, 2018 |
Goodwill | |||
Accumulated impairment losses | $ 0 | ||
Goodwill impairment loss | $ 0 | ||
Changes to goodwill balances by segment | |||
Goodwill balance as of January 1 | 3,052.8 | $ 3,053.5 | |
Adjustment to Bluewater purchase price allocation | 0 | (0.7) | |
Goodwill balance as of December 31 | 3,052.8 | 3,052.8 | |
Wisconsin | |||
Changes to goodwill balances by segment | |||
Goodwill balance as of January 1 | 2,104.3 | 2,104.3 | |
Adjustment to Bluewater purchase price allocation | 0 | 0 | |
Goodwill balance as of December 31 | 2,104.3 | 2,104.3 | |
Illinois | |||
Changes to goodwill balances by segment | |||
Goodwill balance as of January 1 | 758.7 | 758.7 | |
Adjustment to Bluewater purchase price allocation | 0 | 0 | |
Goodwill balance as of December 31 | 758.7 | 758.7 | |
Other States | |||
Changes to goodwill balances by segment | |||
Goodwill balance as of January 1 | 183.2 | 183.2 | |
Adjustment to Bluewater purchase price allocation | 0 | 0 | |
Goodwill balance as of December 31 | 183.2 | 183.2 | |
Non-Utility Energy Infrastructure | |||
Changes to goodwill balances by segment | |||
Goodwill balance as of January 1 | 6.6 | 7.3 | |
Adjustment to Bluewater purchase price allocation | 0 | (0.7) | |
Goodwill balance as of December 31 | $ 6.6 | $ 6.6 |
Common Equity - Stock-Based Com
Common Equity - Stock-Based Compensation Expense (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Stock-based compensation expense | $ 50.2 | $ 36.1 | $ 29 |
Related tax benefit | 13.8 | 9.9 | 11.6 |
Stock options | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Stock-based compensation expense | 4.4 | 5.2 | 3.4 |
Restricted stock | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Stock-based compensation expense | 7.1 | 10.7 | 5.4 |
Performance units | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Stock-based compensation expense | $ 38.7 | $ 20.2 | $ 20.2 |
Common Equity - Stock Options (
Common Equity - Stock Options (Details) - Stock options - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Options Activity | ||||
Outstanding, shares, beginning balance | 3,249,918 | 4,452,533 | ||
Granted, shares | 476,418 | 710,710 | 552,215 | |
Exercised, shares | (1,609,948) | |||
Forfeited, shares | (69,085) | |||
Outstanding, shares, ending balance | 3,249,918 | 4,452,533 | ||
Options - Weighted Average Exercise Price | ||||
Outstanding, Weighted-Average Exercise Price, Beginning | $ 54.98 | $ 48.86 | ||
Granted, Weighted-Average Exercise Price | 68.18 | |||
Exercised, Weighted-Average Exercise Price | 41.63 | |||
Forfeited, Weighted-Average Exercise Price | 62.33 | |||
Outstanding, Weighted-Average Exercise Price, Ending | $ 54.98 | $ 48.86 | ||
Options - Additional Disclosures | ||||
Outstanding, Weighted-Average Remaining Contractual Life (Years) | 6 years 3 months 18 days | |||
Outstanding, Aggregate Intrinsic Value | $ 121 | |||
Exercisable, shares | 1,744,386 | |||
Exercisable, Weighted-Average Exercise Price (in dollars per share) | $ 46.92 | |||
Exercisable, Weighted-Average Remaining Contractual Life (Years) | 4 years 9 months 18 days | |||
Exercisable, Aggregate Intrinsic Value | $ 79 | |||
Intrinsic value of options exercised | 62.4 | $ 32.4 | $ 33.8 | |
Tax benefit from option exercises | 17.1 | $ 8.9 | $ 13.5 | |
Compensation cost not yet recognized | $ 2.1 | |||
Weighted-average period over which unrecognized compensation cost is expected to be recognized | 1 year 7 months 6 days | |||
Estimated weighted-average fair value per stock option (in dollars per share) | $ 8.60 | $ 7.71 | $ 7.45 | |
Subsequent event | ||||
Options Activity | ||||
Granted, shares | 512,139 | |||
Options - Weighted Average Exercise Price | ||||
Granted, Weighted-Average Exercise Price | $ 91.49 | |||
Options - Additional Disclosures | ||||
Estimated weighted-average fair value per stock option (in dollars per share) | $ 10.82 |
Common Equity - Restricted Shar
Common Equity - Restricted Shares (Details) - Restricted stock - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Restricted Stock Activity | ||||
Outstanding, shares, beginning of period | 134,109 | 234,627 | ||
Granted, shares | 97,343 | |||
Released, shares | (192,291) | |||
Forfeited, shares | (5,570) | |||
Outstanding, shares, end of period | 134,109 | 234,627 | ||
Restricted Stock Weighted-Average Grant Date Fair Value | ||||
Outstanding, weighted-average grant date fair value, beginning of period | $ 66.48 | $ 61.01 | ||
Granted, weighted-average grant date fair value | 68.18 | |||
Released, weighted-average grant date fair value | 60.76 | |||
Forfeited, weighted-average grant date fair value | 62.99 | |||
Outstanding, weighted-average grant date fair value, end of period | $ 66.48 | $ 61.01 | ||
Restricted Stock - Additional Disclosures | ||||
Intrinsic value of released restricted shares | $ 13.4 | $ 7.9 | $ 5.4 | |
Tax benefit from released restricted shares | 3.7 | $ 2.2 | $ 2.1 | |
Compensation cost not yet recognized | $ 2.4 | |||
Weighted-average period over which unrecognized compensation cost is expected to be recognized | 1 year 7 months 6 days | |||
Subsequent event | ||||
Restricted Stock Activity | ||||
Granted, shares | 84,540 | |||
Restricted Stock Weighted-Average Grant Date Fair Value | ||||
Granted, weighted-average grant date fair value | $ 91.49 |
Common Equity - Performance Uni
Common Equity - Performance Units (Details) - Performance units - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Performance units granted | 148,036 | 217,560 | 237,650 | |
Intrinsic value of settled performance units | $ 18.7 | $ 9.7 | $ 6.7 | |
Tax benefit from distribution of performance units | $ 4.4 | $ 2.2 | $ 2.1 | |
Performance units outstanding | 539,475 | |||
Liability recorded on balance sheet | $ 58.1 | |||
Compensation cost not yet recognized | $ 20.5 | |||
Weighted-average period over which unrecognized compensation cost is expected to be recognized | 1 year 7 months 6 days | |||
Subsequent event | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Performance units granted | 140,455 | |||
Intrinsic value of settled performance units | $ 34.2 | |||
Tax benefit from distribution of performance units | $ 8.4 |
Common Equity - Dividend Restri
Common Equity - Dividend Restrictions (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2019USD ($)period | Dec. 31, 2018 | |
Dividend Payment Restrictions [Line Items] | ||
Junior notes minimum interest deferral payment period (in periods) | period | 1 | |
Junior notes maximum interest payment deferral period (in years) | 10 years | |
Restricted net assets of consolidated subsidiaries | $ 7,400 | |
Undistributed earnings of investees accounted for by the equity method | $ 363 | |
WE | ||
Dividend Payment Restrictions [Line Items] | ||
Maximum debt to capitalization ratio | 65.00% | |
WE | 3.60% Serial Preferred Stock | ||
Dividend Payment Restrictions [Line Items] | ||
Dividend rate (as a percent) | 3.60% | 3.60% |
WE | 3.60% Serial Preferred Stock | Minimum | Common stock equity to total capitalization is between 25% and 20% | ||
Dividend Payment Restrictions [Line Items] | ||
Percentage of common equity to total capitalization required to be maintained | 20.00% | |
WE | 3.60% Serial Preferred Stock | Maximum | Common stock equity to total capitalization is between 25% and 20% | ||
Dividend Payment Restrictions [Line Items] | ||
Percentage of net income for which dividends can be declared | 75.00% | |
Percentage of common equity to total capitalization required to be maintained | 25.00% | |
WE | 3.60% Serial Preferred Stock | Maximum | Common stock equity to total capitalization is less than 20% | ||
Dividend Payment Restrictions [Line Items] | ||
Percentage of net income for which dividends can be declared | 50.00% | |
Percentage of common equity to total capitalization required to be maintained | 20.00% | |
WE | Public Service Commission of Wisconsin | Minimum | ||
Dividend Payment Restrictions [Line Items] | ||
Common equity ratio required to be maintained (as a percent) | 52.50% | |
WPS | ||
Dividend Payment Restrictions [Line Items] | ||
Maximum debt to capitalization ratio | 65.00% | |
WPS | Public Service Commission of Wisconsin | Minimum | ||
Dividend Payment Restrictions [Line Items] | ||
Common equity ratio required to be maintained (as a percent) | 52.50% | |
WG | Public Service Commission of Wisconsin | Minimum | ||
Dividend Payment Restrictions [Line Items] | ||
Common equity ratio required to be maintained (as a percent) | 52.50% | |
UMERC | ||
Dividend Payment Restrictions [Line Items] | ||
Maximum debt to capitalization ratio | 65.00% | |
ATC Holding LLC | ||
Dividend Payment Restrictions [Line Items] | ||
Maximum debt to capitalization ratio | 65.00% | |
Bluewater Gas Storage, LLC | ||
Dividend Payment Restrictions [Line Items] | ||
Maximum debt to capitalization ratio | 65.00% |
Common Equity - Share Repurchas
Common Equity - Share Repurchase Program (Details) - USD ($) shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Stockholders' Equity Note [Abstract] | |||
New shares of common stock issued | 0 | 0 | 0 |
Shares purchased | 1.8 | 1.1 | 1.1 |
Cost of shares purchased | $ 140.1 | $ 72.4 | $ 71.3 |
Common Equity - Common Stock Di
Common Equity - Common Stock Dividends (Details) - $ / shares | 3 Months Ended | 12 Months Ended | |||||||
Mar. 31, 2020 | Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Dividends Paid and Payable [Line Items] | |||||||||
Dividends per share (in dollars per share) | $ 0.59 | $ 0.59 | $ 0.59 | $ 0.59 | $ 2.36 | $ 2.21 | $ 2.08 | ||
Subsequent event | |||||||||
Dividends Paid and Payable [Line Items] | |||||||||
Dividends per share (in dollars per share) | $ 0.6325 | ||||||||
Annualized dividend (in dollars per share) | $ 2.53 | ||||||||
Subsequent event | Minimum | |||||||||
Dividends Paid and Payable [Line Items] | |||||||||
Target dividend payout ratio (as a percent) | 65.00% | ||||||||
Subsequent event | Maximum | |||||||||
Dividends Paid and Payable [Line Items] | |||||||||
Target dividend payout ratio (as a percent) | 70.00% |
Preferred Stock (Details)
Preferred Stock (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | ||
Total preferred stock value issued | $ 30.4 | $ 30.4 |
WEC Energy Group | $.01 par value Preferred Stock | ||
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | ||
Par or stated value per share | $ 0.01 | $ 0.01 |
Shares authorized | 15,000,000 | 15,000,000 |
Shares outstanding | 0 | 0 |
Redemption price per share | $ 0 | $ 0 |
Total preferred stock value issued | $ 0 | $ 0 |
WE | $100 par value, Six Per Cent. Preferred Stock | ||
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | ||
Par or stated value per share | $ 100 | $ 100 |
Dividend rate (as a percent) | 6.00% | 6.00% |
Shares authorized | 45,000 | 45,000 |
Shares outstanding | 44,498 | 44,498 |
Redemption price per share | $ 0 | $ 0 |
Total preferred stock value issued | $ 4.4 | $ 4.4 |
WE | $100 par value, Serial Preferred Stock, 3.60% series | ||
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | ||
Par or stated value per share | $ 100 | $ 100 |
Dividend rate (as a percent) | 3.60% | 3.60% |
Shares authorized | 2,286,500 | 2,286,500 |
Shares outstanding | 260,000 | 260,000 |
Redemption price per share | $ 101 | $ 101 |
Total preferred stock value issued | $ 26 | $ 26 |
WE | $25 par value, Serial Preferred Stock | ||
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | ||
Par or stated value per share | $ 25 | $ 25 |
Shares authorized | 5,000,000 | 5,000,000 |
Shares outstanding | 0 | 0 |
Redemption price per share | $ 0 | $ 0 |
Total preferred stock value issued | $ 0 | $ 0 |
WPS | $100 par value, Preferred Stock | ||
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | ||
Par or stated value per share | $ 100 | $ 100 |
Shares authorized | 1,000,000 | 1,000,000 |
Shares outstanding | 0 | 0 |
Redemption price per share | $ 0 | $ 0 |
Total preferred stock value issued | $ 0 | $ 0 |
PGL | $100 par value, Cumulative Preferred Stock | ||
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | ||
Par or stated value per share | $ 100 | $ 100 |
Shares authorized | 430,000 | 430,000 |
Shares outstanding | 0 | 0 |
Redemption price per share | $ 0 | $ 0 |
Total preferred stock value issued | $ 0 | $ 0 |
NSG | $100 par value, Cumulative Preferred Stock | ||
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | ||
Par or stated value per share | $ 100 | $ 100 |
Shares authorized | 160,000 | 160,000 |
Shares outstanding | 0 | 0 |
Redemption price per share | $ 0 | $ 0 |
Total preferred stock value issued | $ 0 | $ 0 |
Short-Term Debt and Lines of _3
Short-Term Debt and Lines of Credit - Outstanding Amounts (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Short-term Debt [Line Items] | ||
Commercial paper | $ 830.8 | $ 1,440.1 |
WE | ||
Short-term Debt [Line Items] | ||
Maximum debt to capitalization ratio | 65.00% | |
WPS | ||
Short-term Debt [Line Items] | ||
Maximum debt to capitalization ratio | 65.00% | |
WG | ||
Short-term Debt [Line Items] | ||
Maximum debt to capitalization ratio | 65.00% | |
PGL | ||
Short-term Debt [Line Items] | ||
Maximum debt to capitalization ratio | 65.00% | |
WEC Energy Group | ||
Short-term Debt [Line Items] | ||
Commercial paper | $ 334.7 | 548.4 |
Maximum debt to capitalization ratio | 70.00% | |
Commercial paper | ||
Short-term Debt [Line Items] | ||
Commercial paper | $ 830.8 | $ 1,440.1 |
Average interest rate on amount outstanding | 2.00% | 2.92% |
Average amount outstanding during the year | $ 1,039.2 | |
Weighted Average interest rate during the year | 2.58% |
Short-Term Debt and Lines of _4
Short-Term Debt and Lines of Credit - Credit Facilities (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2019USD ($)extension | Dec. 31, 2018USD ($) | |
Line of Credit Facility [Line Items] | ||
Short-term credit capacity | $ 2,800 | |
Commercial paper | 830.8 | $ 1,440.1 |
Available capacity under existing agreements | $ 1,966.9 | |
Number of extensions available on a credit facility | extension | 2 | |
Length of credit facility extension | 1 year | |
WE | Credit facility maturing October 2022 | ||
Line of Credit Facility [Line Items] | ||
Short-term credit capacity | $ 500 | |
Number of extensions available on a credit facility | extension | 2 | |
Length of credit facility extension | 1 year | |
WPS | Credit facility maturing October 2022 | ||
Line of Credit Facility [Line Items] | ||
Short-term credit capacity | $ 400 | |
Number of extensions available on a credit facility | extension | 2 | |
Length of credit facility extension | 1 year | |
WG | Credit facility maturing October 2022 | ||
Line of Credit Facility [Line Items] | ||
Short-term credit capacity | $ 350 | |
Number of extensions available on a credit facility | extension | 2 | |
Length of credit facility extension | 1 year | |
PGL | Credit facility maturing October 2022 | ||
Line of Credit Facility [Line Items] | ||
Short-term credit capacity | $ 350 | |
Number of extensions available on a credit facility | extension | 2 | |
Length of credit facility extension | 1 year | |
WEC Energy Group | ||
Line of Credit Facility [Line Items] | ||
Commercial paper | $ 334.7 | 548.4 |
WEC Energy Group | Credit facility maturing October 2022 | ||
Line of Credit Facility [Line Items] | ||
Short-term credit capacity | $ 1,200 | |
Number of extensions available on a credit facility | extension | 2 | |
Length of credit facility extension | 1 year | |
Letter of Credit | ||
Line of Credit Facility [Line Items] | ||
Letters of credit issued inside credit facilities | $ 2.3 | |
Commercial paper | ||
Line of Credit Facility [Line Items] | ||
Commercial paper | $ 830.8 | $ 1,440.1 |
Long-Term Debt (Details)
Long-Term Debt (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2019USD ($)number_of_interest_rate_swaps | Dec. 31, 2018USD ($) | |
Debt Instrument [Line Items] | ||
Total | $ 11,922.5 | $ 10,387.6 |
Integrys acquisition fair value adjustment | 14.3 | 20.6 |
Unamortized debt issuance costs | (52.9) | (44.7) |
Unamortized discount, net and other | (25.6) | (27.8) |
Long-term debt, including current portion | 11,858.3 | 10,335.7 |
Current portion of long-term debt | (686.9) | (360.1) |
Total long-term debt | 11,171.4 | 9,975.6 |
Finance lease obligation | 45.9 | 23.3 |
Future maturities of long-term debt outstanding | ||
2020 | 686.9 | |
2021 | 1,338.8 | |
2022 | 390.8 | |
2023 | 42.8 | |
2024 | 570 | |
Thereafter | 8,893.2 | |
Total | $ 11,922.5 | $ 10,387.6 |
WE | ||
Debt Instrument [Line Items] | ||
Weighted Average Interest Rate | 4.26% | 4.50% |
Unsecured debt | $ 2,785 | $ 2,735 |
WE | WE Debentures (unsecured), 2.05% due 2024 | ||
Debt Instrument [Line Items] | ||
Debt instrument interest rate stated percentage rate | 2.05% | |
Proceeds from issuance of debt | $ 300 | |
WE | WE Debentures (unsecured), 4.25% due 2019 | ||
Debt Instrument [Line Items] | ||
Debt instrument interest rate stated percentage rate | 4.25% | |
Repayments of Unsecured Debt | $ 250 | |
WPS | ||
Debt Instrument [Line Items] | ||
Weighted Average Interest Rate | 4.04% | 4.21% |
Senior notes | $ 1,625 | $ 1,325 |
WPS | WPS Senior Notes (unsecured), 3.30% due 2049 | ||
Debt Instrument [Line Items] | ||
Debt instrument interest rate stated percentage rate | 3.30% | |
Proceeds from issuance of debt | $ 300 | |
WG | ||
Debt Instrument [Line Items] | ||
Weighted Average Interest Rate | 3.65% | 4.04% |
Unsecured debt | $ 640 | $ 490 |
WG | WG Debentures (unsecured), 2.38% due 2024 | ||
Debt Instrument [Line Items] | ||
Debt instrument interest rate stated percentage rate | 2.38% | |
Proceeds from issuance of debt | $ 150 | |
Integrys Holding Inc | ||
Debt Instrument [Line Items] | ||
Weighted Average Interest Rate | 4.17% | 4.17% |
Senior notes | $ 250 | $ 250 |
Integrys Holding Inc | Integrys Junior Notes (unsecured), 6.00% due 2073 | ||
Debt Instrument [Line Items] | ||
Weighted Average Interest Rate | 6.00% | 6.00% |
Unsecured debt | $ 400 | $ 400 |
Debt instrument interest rate stated percentage rate | 6.00% | |
Debt Instrument, Basis Spread on Variable Rate | 3.22% | |
PGL | ||
Debt Instrument [Line Items] | ||
Weighted Average Interest Rate | 3.59% | 3.88% |
Secured debt | $ 1,520 | $ 1,195 |
PGL | PGL Series WW Bonds (secured), 1.875% due 2033 | ||
Debt Instrument [Line Items] | ||
Secured debt | $ 50 | |
Debt instrument interest rate stated percentage rate | 1.875% | |
PGL | PGL Series GGG (secured), 2.96% due 2029 | ||
Debt Instrument [Line Items] | ||
Debt instrument interest rate stated percentage rate | 2.96% | |
Proceeds from issuance of debt | $ 275 | |
PGL | PGL First and Refunding Mortgage Bonds (secured), 4.63% due 2019 | ||
Debt Instrument [Line Items] | ||
Debt instrument interest rate stated percentage rate | 4.63% | |
Repayments of Secured Debt | $ 75 | |
PGL | PGL Series HHH (secured), 2.64% due 2024 | ||
Debt Instrument [Line Items] | ||
Debt instrument interest rate stated percentage rate | 2.64% | |
Proceeds from issuance of debt | $ 75 | |
PGL | PGL Series III (secured), 3.06% due 2031 | ||
Debt Instrument [Line Items] | ||
Debt instrument interest rate stated percentage rate | 3.06% | |
Proceeds from issuance of debt | $ 50 | |
NSG | ||
Debt Instrument [Line Items] | ||
Weighted Average Interest Rate | 3.81% | 3.81% |
Secured debt | $ 132 | $ 132 |
MERC | ||
Debt Instrument [Line Items] | ||
Weighted Average Interest Rate | 3.51% | 3.51% |
Senior notes | $ 120 | $ 120 |
MGU | ||
Debt Instrument [Line Items] | ||
Weighted Average Interest Rate | 3.51% | 3.51% |
Senior notes | $ 90 | $ 90 |
UMERC | ||
Debt Instrument [Line Items] | ||
Weighted Average Interest Rate | 3.26% | |
Senior notes | $ 160 | $ 0 |
UMERC | UMERC Senior Notes (unsecured), 3.26% due 2029 | ||
Debt Instrument [Line Items] | ||
Debt instrument interest rate stated percentage rate | 3.26% | |
Proceeds from issuance of debt | $ 160 | |
Bluewater Gas Storage, LLC | ||
Debt Instrument [Line Items] | ||
Weighted Average Interest Rate | 3.76% | 3.76% |
Senior notes | $ 120.3 | $ 122.7 |
ATC Holding LLC | ||
Debt Instrument [Line Items] | ||
Weighted Average Interest Rate | 4.05% | 4.34% |
Senior notes | $ 475 | $ 240 |
ATC Holding LLC | ATC Holding Senior Notes (unsecured), 3.75% due 2029 | ||
Debt Instrument [Line Items] | ||
Debt instrument interest rate stated percentage rate | 3.75% | |
Proceeds from issuance of debt | $ 235 | |
We Power | ||
Debt Instrument [Line Items] | ||
Weighted Average Interest Rate | 5.57% | 5.56% |
Secured debt | $ 1,005.2 | $ 1,037.9 |
WECC | ||
Debt Instrument [Line Items] | ||
Weighted Average Interest Rate | 6.94% | 6.94% |
Unsecured debt | $ 50 | $ 50 |
WEC Energy Group | ||
Debt Instrument [Line Items] | ||
Weighted Average Interest Rate | 3.47% | 3.54% |
Senior notes | $ 2,050 | $ 1,700 |
Current portion of long-term debt | (400) | 0 |
Total long-term debt | 2,141.6 | $ 2,190.8 |
Future maturities of long-term debt outstanding | ||
2020 | 400 | |
2021 | 600 | |
2022 | 350 | |
2023 | 0 | |
2024 | 0 | |
Thereafter | $ 1,200 | |
WEC Energy Group | WEC Energy Group senior notes (unsecured), 6.20% due 2033 | ||
Debt Instrument [Line Items] | ||
Debt instrument interest rate stated percentage rate | 6.20% | |
WEC Energy Group | WEC Energy Group Junior Notes (unsecured), 3.53% due 2067 | ||
Debt Instrument [Line Items] | ||
Weighted Average Interest Rate | 4.50% | 4.85% |
Unsecured debt | $ 500 | $ 500 |
Debt instrument interest rate stated percentage rate | 4.02% | 4.73% |
WEC Energy Group | WEC Senior Notes (unsecured), 3.10% due 2022 | ||
Debt Instrument [Line Items] | ||
Debt instrument interest rate stated percentage rate | 3.10% | |
Proceeds from issuance of debt | $ 350 | |
WEC Energy Group | Interest rate swaps | ||
Debt Instrument [Line Items] | ||
Number of interest rate swaps executed | number_of_interest_rate_swaps | 2 | |
Interest rate swap fixed interest rate | 4.9765% | |
Interest rate swap notional value | $ 250 |
Long-Term Debt Schedule of curr
Long-Term Debt Schedule of current maturities of long-term debt (Details) $ in Millions | Dec. 31, 2019USD ($) |
Current maturities of long-term debt [Line Items] | |
Total | $ 686.9 |
WEC Energy Group | |
Current maturities of long-term debt [Line Items] | |
Total | $ 400 |
WEC Energy Group Senior Notes (unsecured) | WEC Energy Group | |
Current maturities of long-term debt [Line Items] | |
Debt Instrument, Interest Rate, Stated Percentage | 2.45% |
Senior Notes, Current | $ 400 |
Integrys Senior Notes (unsecured) | Integrys Holding Inc | |
Current maturities of long-term debt [Line Items] | |
Debt Instrument, Interest Rate, Stated Percentage | 4.17% |
Senior Notes, Current | $ 250 |
Bluewater Gas Storage Senior Notes (unsecured) | Bluewater Gas Storage, LLC | |
Current maturities of long-term debt [Line Items] | |
Debt Instrument, Interest Rate, Stated Percentage | 3.76% |
Senior Notes, Current | $ 2.5 |
4.91% We Power Subsidiaries Notes - PWGS (secured, nonrecourse) | We Power | |
Current maturities of long-term debt [Line Items] | |
Debt Instrument, Interest Rate, Stated Percentage | 4.91% |
Secured Debt, Current | $ 6.6 |
5.209%We Power Subsidiaries Notes - ERGS (secured, nonrecourse) | We Power | |
Current maturities of long-term debt [Line Items] | |
Debt Instrument, Interest Rate, Stated Percentage | 5.209% |
Secured Debt, Current | $ 12.6 |
4.673% We Power Subsidiaries Notes - ERGS (secured, nonrecourse) | We Power | |
Current maturities of long-term debt [Line Items] | |
Debt Instrument, Interest Rate, Stated Percentage | 4.673% |
Secured Debt, Current | $ 9.7 |
6.00% We Power Subsidiaries Notes - PWGS (secured, nonrecourse) | We Power | |
Current maturities of long-term debt [Line Items] | |
Debt Instrument, Interest Rate, Stated Percentage | 6.00% |
Secured Debt, Current | $ 5.5 |
Leases - Power Purchase Commitm
Leases - Power Purchase Commitment (Details) | 12 Months Ended | |
Dec. 31, 2019USD ($)MW | Dec. 31, 2018USD ($) | |
Lessee, Lease, Description [Line Items] | ||
Finance lease obligation | $ 45,900,000 | $ 23,300,000 |
Power Purchase Contract | ||
Lessee, Lease, Description [Line Items] | ||
Power purchase contract period | 25 years | |
Firm capacity from power purchase contract (in megawatts) | MW | 236 | |
Minimum energy requirements over remaining term of power purchase contract (in megawatts) | MW | 0 | |
Power purchase contract renewal period | 10 years | |
Maximum regulatory asset for power purchase contract | $ 78,500,000 | |
Regulatory asset at end of life of power purchase contract | 0 | |
Finance lease obligation | 18,400,000 | |
Finance lease obligation at end of life of power purchase contract | $ 0 |
Leases - Two Creeks Solar Proje
Leases - Two Creeks Solar Project (Details) | 12 Months Ended | |
Dec. 31, 2019USD ($)aextension | Dec. 31, 2018USD ($) | |
Lessee, Lease, Description [Line Items] | ||
Finance lease obligation | $ 45,900,000 | $ 23,300,000 |
Two Creeks Solar Project | ||
Lessee, Lease, Description [Line Items] | ||
Solar land lease acreage | a | 600 | |
Lease initial term | 30 years | |
Number of contract extensions | extension | 2 | |
Renewal term | 10 years | |
Lease extended term | 50 years | |
Finance lease obligation | $ 7,700,000 | |
Finance lease obligation at end of life of solar land contract | $ 0 |
Leases - Badger Hollow Solar Fa
Leases - Badger Hollow Solar Farm I (Details) | Dec. 31, 2019USD ($)a | Dec. 31, 2018USD ($) |
Lessee, Lease, Description [Line Items] | ||
Finance lease obligation | $ 45,900,000 | $ 23,300,000 |
Badger Hollow Solar Farm I | ||
Lessee, Lease, Description [Line Items] | ||
Solar land lease acreage | a | 1,400 | |
Lease initial term | 25 years | |
Renewal term | 25 years | |
Finance lease obligation | $ 19,800,000 | |
Finance lease obligation at end of life of solar land contract | $ 0 |
Leases - Lease Expense and Supp
Leases - Lease Expense and Supplemental Cash Flow Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Lease expense | |||
Lease expense | $ 14.3 | $ 14.8 | $ 14.4 |
Operating lease expense | 5.5 | 5.6 | 6.4 |
Short-term lease expense | 0.6 | 1.5 | 0.8 |
Amortization of finance lease right of use assets | 4.9 | ||
Interest on finance lease liabilities | 3.3 | ||
Other information | |||
Operating cash flows from finance/capital leases | 3.3 | 7.7 | 7.2 |
Operating cash flows from operating leases | 6 | 6.5 | 7.1 |
Financing cash flows from finance leases | 4.9 | ||
Right-of-use asset obtained in exchange for finance lease liabilities | 27.2 | ||
Right of use assets obtained in exchange for operating lease liabilities | $ 49 | ||
Weighted average remaining lease term - finance leases | 31 years 6 months | ||
Weighted average remaining lease term - operating leases | 12 years 10 months 24 days | ||
Weighted average discount rate - finance leases | 6.70% | ||
Weighted average discount rate - operating leases | 4.40% | ||
Finance and capital leases | |||
Lease expense | |||
Lease expense | $ 8.2 | $ 7.7 | $ 7.2 |
Leases - Right of Use Assets (D
Leases - Right of Use Assets (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Jan. 01, 2019 | Dec. 31, 2018 |
Right of use assets | |||
Total finance lease right of use asset/capital lease asset | $ 40.6 | $ 19.4 | |
Operating lease right of use assets | 41.4 | $ 49 | |
Power Purchase Contract | |||
Right of use assets | |||
Under finance/capital lease | 140.3 | 140.3 | |
Accumulated amortization | (126.6) | (120.9) | |
Total finance lease right of use asset/capital lease asset | 13.7 | 19.4 | |
Two Creeks Solar Project | |||
Right of use assets | |||
Under finance/capital lease | 7.7 | 0 | |
Accumulated amortization | (0.1) | 0 | |
Total finance lease right of use asset/capital lease asset | 7.6 | 0 | |
Badger Hollow Solar Farm I | |||
Right of use assets | |||
Under finance/capital lease | 19.5 | 0 | |
Accumulated amortization | (0.2) | 0 | |
Total finance lease right of use asset/capital lease asset | $ 19.3 | $ 0 |
Leases - Future Minimum Lease P
Leases - Future Minimum Lease Payments (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Jan. 01, 2019 | Dec. 31, 2018 |
Total operating leases | |||
2020 | $ 6.8 | ||
2021 | 4.8 | ||
2022 | 4.8 | ||
2023 | 4.9 | ||
2024 | 4.8 | ||
Thereafter | 30.1 | ||
Total minimum lease payments | 56.2 | ||
Less: interest | (14.8) | ||
Present value of minimum lease payments | 41.4 | $ 48.8 | |
Less: short-term lease liabilities | (4.4) | ||
Long-term lease liabilities | 37 | ||
Finance leases | |||
2020 | 9.3 | ||
2021 | 10.3 | ||
2022 | 5.1 | ||
2023 | 0.9 | ||
2024 | 0.9 | ||
Therafter | 76.2 | ||
Total minimum lease payments | 102.7 | ||
Less: interest | (56.8) | ||
Present value of minimum lease payments | 45.9 | $ 23.3 | |
Less: short-term lease liabilities | (6.3) | ||
Long-term lease liabilities | 39.6 | ||
Capital lease | |||
Short-term liabilities under capital lease | 4.9 | ||
Long-term liabilities under capital lease | 18.4 | ||
Power Purchase Contract | |||
Finance leases | |||
2020 | 8.8 | ||
2021 | 9.4 | ||
2022 | 4.2 | ||
2023 | 0 | ||
2024 | 0 | ||
Therafter | 0 | ||
Total minimum lease payments | 22.4 | ||
Less: interest | (4) | ||
Present value of minimum lease payments | 18.4 | ||
Less: short-term lease liabilities | (6.3) | ||
Long-term lease liabilities | 12.1 | ||
Two Creeks Solar Project | |||
Finance leases | |||
2020 | 0.2 | ||
2021 | 0.2 | ||
2022 | 0.2 | ||
2023 | 0.2 | ||
2024 | 0.2 | ||
Therafter | 22.8 | ||
Total minimum lease payments | 23.8 | ||
Less: interest | (16.1) | ||
Present value of minimum lease payments | 7.7 | ||
Less: short-term lease liabilities | 0 | ||
Long-term lease liabilities | 7.7 | ||
Badger Hollow Solar Farm I | |||
Finance leases | |||
2020 | 0.3 | ||
2021 | 0.7 | ||
2022 | 0.7 | ||
2023 | 0.7 | ||
2024 | 0.7 | ||
Therafter | 53.4 | ||
Total minimum lease payments | 56.5 | ||
Less: interest | (36.7) | ||
Present value of minimum lease payments | 19.8 | ||
Less: short-term lease liabilities | 0 | ||
Long-term lease liabilities | $ 19.8 |
Income Taxes - Summary of incom
Income Taxes - Summary of income tax expense (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |||
Current tax expense (benefit) | $ (37.9) | $ (127.5) | $ 111.8 |
Deferred income taxes, net | 167.7 | 300.1 | 274.4 |
Investment tax credit, net | (4.8) | (2.8) | (2.7) |
Total income tax expense | $ 125 | $ 169.8 | $ 383.5 |
Income Taxes - Statutory rate r
Income Taxes - Statutory rate reconciliation (Details) $ in Millions | Jan. 01, 2018 | Dec. 31, 2019USD ($)change | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) |
Effective Income Tax Rate Reconciliation, Amount [Abstract] | ||||
Statutory federal income tax | $ 264.4 | $ 258.1 | $ 555.5 | |
State income taxes net of federal tax benefit | 80.4 | 71.8 | 100.8 | |
Tax repairs | (122.8) | (120.7) | 0 | |
Federal excess deferred tax amortization | (34.9) | (16.8) | 0 | |
Wind production tax credits | (34.1) | (12.1) | (16.8) | |
Excess tax benefits - stock options | (15.8) | (5.9) | (10) | |
Investment tax credit restored | (4.8) | (2.8) | (2.7) | |
AFUDC - Equity | (3) | (3.2) | (4) | |
Federal tax reform | 0 | 0 | (226.9) | |
Other, net | (4.4) | 1.4 | (12.4) | |
Total income tax expense | $ 125 | $ 169.8 | 383.5 | |
Net impact of tax cuts and jobs act of 2017 | $ 206.7 | |||
Effective Income Tax Rate Reconciliation, Percent [Abstract] | ||||
Statutory federal income tax | 21.00% | 21.00% | 21.00% | 35.00% |
State income taxes net of federal tax benefit | 6.40% | 5.80% | 6.40% | |
Tax repairs | (9.80%) | (9.80%) | 0.00% | |
Federal excess deferred tax amortization | (2.80%) | (1.40%) | 0.00% | |
Wind production tax credits | (2.70%) | (1.00%) | (1.10%) | |
Excess tax benefits - stock options | (1.30%) | (0.50%) | (0.60%) | |
Investment tax credit restored | (0.40%) | (0.20%) | (0.20%) | |
AFUDC - Equity | (0.20%) | (0.30%) | (0.30%) | |
Feceral tax reform | 0.00% | 0.00% | (14.30%) | |
Other, net | (0.30%) | 0.20% | (0.80%) | |
Total income tax expense | 9.90% | 13.80% | 24.10% | |
2018 and 2019 rates | WE | Public Service Commission of Wisconsin (PSCW) | ||||
Income taxes | ||||
Income statement impact of flow through of repair related deferred tax liabilities | change | 0 |
Income Taxes - Components of de
Income Taxes - Components of deferred tax assets and liabilities (Details) - USD ($) $ in Millions | Jan. 01, 2018 | Dec. 31, 2017 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 |
Components of deferred income taxes classified as net current assets and net long-term liabilities [Abstract] | |||||
Statutory federal income tax | 21.00% | 21.00% | 21.00% | 35.00% | |
Estimated tax benefit related to the remeasurement of deferred income taxes from tax legislation | $ 2,657 | ||||
Net impact of tax cuts and jobs act of 2017 | $ 206.7 | ||||
Non-current | |||||
Tax gross up - regulatory items | $ 519.8 | $ 579.2 | |||
Deferred revenues | 106.3 | 129.3 | |||
Future tax benefits | 101 | 70.6 | |||
Other | 159.8 | 194.4 | |||
Total deferred tax assets | 886.9 | 973.5 | |||
Valuation allowance | (2.3) | (11.4) | |||
Net deferred tax assets | 884.6 | 962.1 | |||
Non-current | |||||
Property-related | 3,609 | 3,436.9 | |||
Investment in affiliates | 531.7 | 420.6 | |||
Deferred costs - Plant retirements | 232 | 176 | |||
Employee benefits and compensation | 131.4 | 121.2 | |||
Other | 149.8 | 195.5 | |||
Total deferred tax liabilities | 4,653.9 | 4,350.2 | |||
Deferred tax liability, net | $ 3,769.3 | $ 3,388.1 |
Income Taxes - Components of ne
Income Taxes - Components of net deferred tax assets (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Income taxes | ||
Balance carryforwards, gross value | $ 287.1 | $ 275.9 |
Future tax benefits, deferred tax effect | 101 | 70.6 |
Valuation allowance | (2.3) | (11.4) |
Foreign tax authority | ||
Income taxes | ||
Tax credit carryforwards, gross value | 0 | |
Federal foreign tax credit, deferred tax effect | 9.7 | |
Tax credit carryforward, valuation allowance | (9.7) | |
Domestic tax authority | ||
Income taxes | ||
Tax credit carryforwards, gross value | 0 | 0 |
Tax credit carryforwards, deferred tax effect | 75.4 | 39.3 |
Tax credit carryforward, valuation allowance | 0 | (1.7) |
State and local jurisdiction | ||
Income taxes | ||
Tax credit carryforwards, gross value | 0 | 0 |
Operating loss carryforwards, gross value | 287.1 | 275.9 |
Tax credit carryforwards, deferred tax effect | 8 | 4.6 |
State net operating loss, deferred tax effect | 17.6 | 17 |
Tax credit carryforward, valuation allowance | 0 | 0 |
Operating loss carryforwards, valuation allowance | $ (2.3) | $ 0 |
Income Taxes - Reconciliation o
Income Taxes - Reconciliation of unrecognized tax benefits (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Reconciliation of the beginning and ending amount of unrecognized tax benefits | |||
Balance of unrecognized tax benefits, January 1 | $ 20 | $ 17.3 | |
Additions for tax positions of prior years | 1.9 | 2.8 | |
Additions based on tax positions related to the current year | 0.2 | 0.1 | |
Reductions for tax positions of prior years | (4.2) | (0.2) | |
Balance of unrecognized tax benefits, December 31 | 17.9 | 20 | $ 17.3 |
Income Taxes | |||
Deferred tax assets, uncertainty in income taxes | 2 | 2 | |
Net amount of unrecognized tax benefits having impact on the effective tax rate for continuing operations | 15.9 | 18 | |
Interest expense in the consolidated income statements | 0.1 | 0.5 | 0.6 |
Penalties in the consolidated income statements | 0 | 0 | $ 0 |
Accrued interest on the consolidated balance sheets | 0.8 | 0.7 | |
Accrued penalties on the consolidated balance sheets | 0 | $ 0 | |
Unrecognized tax benefits, decrease resulting from statute of limitations | $ 11.4 |
Fair Value Measurements - Asset
Fair Value Measurements - Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Assets | ||
Derivative assets | $ 6.9 | $ 15.9 |
Liabilities | ||
Derivative liabilities | 28.9 | 7.9 |
Fair value measurements on a recurring basis | ||
Assets | ||
Derivative assets | 6.9 | 15.9 |
Investments held in rabbi trust | 85.3 | 65 |
Liabilities | ||
Derivative liabilities | 28.9 | 7.9 |
Fair value measurements on a recurring basis | Level 1 | ||
Assets | ||
Derivative assets | 1.4 | 6.3 |
Investments held in rabbi trust | 85.3 | 65 |
Liabilities | ||
Derivative liabilities | 21.4 | 4.7 |
Fair value measurements on a recurring basis | Level 2 | ||
Assets | ||
Derivative assets | 2.4 | 2.2 |
Investments held in rabbi trust | 0 | 0 |
Liabilities | ||
Derivative liabilities | 7.5 | 3.2 |
Fair value measurements on a recurring basis | Level 3 | ||
Assets | ||
Derivative assets | 3.1 | 7.4 |
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 | 3.4 | 8.1 |
Liabilities | ||
Derivative liabilities | 22.7 | 5.5 |
Fair value measurements on a recurring basis | Natural gas contracts | Level 1 | ||
Assets | ||
Derivative assets | 1.4 | 6.3 |
Liabilities | ||
Derivative liabilities | 21.4 | 4.7 |
Fair value measurements on a recurring basis | Natural gas contracts | Level 2 | ||
Assets | ||
Derivative assets | 2 | 1.8 |
Liabilities | ||
Derivative liabilities | 1.3 | 0.8 |
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 | 3.1 | 7.4 |
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 | 3.1 | 7.4 |
Fair value measurements on a recurring basis | Coal contracts | ||
Assets | ||
Derivative assets | 0.4 | 0.4 |
Liabilities | ||
Derivative liabilities | 0.2 | 0.1 |
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 | 0.4 | 0.4 |
Liabilities | ||
Derivative liabilities | 0.2 | 0.1 |
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 | 6 | 2.3 |
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 | 6 | 2.3 |
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 Gains (Losses) on Investments (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | ||
Net unrealized gains included in earnings related to investments | $ 18.7 | $ 18.8 |
Fair Value Measurements - Level
Fair Value Measurements - Level 3 Reconciliation (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Level 3 rollforward | |||
Balance at the beginning of the period | $ 7.4 | $ 4.4 | $ 5.1 |
Purchases | 12.8 | 18.4 | 13.8 |
Settlements | (17.1) | (15.4) | (14.5) |
Balance at the end of period | $ 3.1 | $ 7.4 | $ 4.4 |
Fair Value Measurements - Finan
Fair Value Measurements - Financial Instruments (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Fair value of financial instruments | ||
Preferred stock of subsidiary | $ 30.4 | $ 30.4 |
Long-term debt, including current portion | 11,858.3 | 10,335.7 |
Finance lease obligation | 45.9 | 23.3 |
Carrying amount | ||
Fair value of financial instruments | ||
Preferred stock of subsidiary | 30.4 | 30.4 |
Long-term debt, including current portion | 11,858.3 | 10,335.7 |
Finance lease obligation | 45.9 | |
Capital lease obligation | 23.3 | |
Fair value | ||
Fair value of financial instruments | ||
Preferred stock of subsidiary | 29.5 | 28.3 |
Long-term debt, including current portion | $ 13,035.9 | $ 10,554.9 |
Derivative Instruments - Deriva
Derivative Instruments - Derivative Assets and Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Derivative assets | ||
Other current derivative assets | $ 6.7 | $ 15.3 |
Other long-term derivative assets | 0.2 | 0.6 |
Derivative assets | 6.9 | 15.9 |
Derivative liabilities | ||
Other current derivative liabilities | 24.8 | 5.8 |
Other long-term derivative Iiabilities | 4.1 | 2.1 |
Derivative liabilities | 28.9 | 7.9 |
Natural gas contracts | ||
Derivative assets | ||
Other current derivative assets | 3.4 | 7.7 |
Other long-term derivative assets | 0 | 0.4 |
Derivative liabilities | ||
Other current derivative liabilities | 21.8 | 5.3 |
Other long-term derivative Iiabilities | 0.9 | 0.2 |
FTRs | ||
Derivative assets | ||
Other current derivative assets | 3.1 | 7.4 |
Derivative liabilities | ||
Other current derivative liabilities | 0 | 0 |
Coal contracts | ||
Derivative assets | ||
Other current derivative assets | 0.2 | 0.2 |
Other long-term derivative assets | 0.2 | 0.2 |
Derivative liabilities | ||
Other current derivative liabilities | 0.2 | 0.1 |
Other long-term derivative Iiabilities | 0 | 0 |
Interest rate swaps | ||
Derivative assets | ||
Other current derivative assets | 0 | 0 |
Other long-term derivative assets | 0 | 0 |
Derivative liabilities | ||
Other current derivative liabilities | 2.8 | 0.4 |
Other long-term derivative Iiabilities | $ 3.2 | $ 1.9 |
Derivative Instruments - Gains
Derivative Instruments - Gains (Losses) and Notional Volumes (Details) gal in Millions, MWh in Millions, MMBTU in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2019USD ($)MWhMMBTUgal | Dec. 31, 2018USD ($)MWhMMBTUgal | Dec. 31, 2017USD ($)MWhMMBTUgal | |
Realized gains (losses) on derivatives | |||
Gains (losses) | $ (10.8) | $ 42.1 | $ 4.7 |
Natural gas contracts | |||
Realized gains (losses) on derivatives | |||
Gains (losses) | $ (27.1) | $ 24.6 | $ (8) |
Notional sales volumes | |||
Notional sales volumes | MMBTU | 183.9 | 173.2 | 123.1 |
Petroleum products contracts | |||
Realized gains (losses) on derivatives | |||
Gains (losses) | $ 0 | $ 1.6 | $ (1.3) |
Notional sales volumes | |||
Notional sales volumes (gallons) | gal | 0 | 6 | 18 |
FTRs | |||
Realized gains (losses) on derivatives | |||
Gains (losses) | $ 16.3 | $ 15.9 | $ 14 |
Notional sales volumes | |||
Notional sales volumes | MWh | 31.2 | 30.5 | 36.2 |
Derivative Instruments - Balanc
Derivative Instruments - Balance Sheet Offsetting (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Cash collateral | ||
Cash collateral posted in margin accounts | $ 34.4 | $ 2.7 |
Cash collateral received in margin accounts | 0.2 | |
Offsetting derivative assets | ||
Gross amount recognized on the balance sheet | 6.9 | 15.9 |
Gross amount not offset on the balance sheet | (1.4) | (4) |
Net amount | 5.5 | 11.9 |
Cash collateral received | 0.2 | |
Offsetting derivative liabilities | ||
Gross amount recognized on the balance sheet | 28.9 | 7.9 |
Gross amount not offset on the balance sheet | (21.4) | (4.9) |
Net amount | 7.5 | 3 |
Cash collateral posted | $ 20 | $ 1.1 |
Derivative Instruments - Cash F
Derivative Instruments - Cash Flow Hedges (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019USD ($)number_of_interest_rate_swaps | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | |
Derivative instruments | |||
Total interest expense line item on the income statements | $ 501.5 | $ 445.1 | $ 415.7 |
Reclassification to interest expense within next 12 months | 1 | ||
WEC Energy Group | |||
Derivative instruments | |||
Total interest expense line item on the income statements | 122.3 | 104.1 | 82 |
WEC Energy Group | WEC Energy Group 2007 Junior Notes due 2067 | |||
Derivative instruments | |||
Long-term debt outstanding | $ 500 | ||
Interest rate swaps | WEC Energy Group | |||
Derivative instruments | |||
Number of interest rate swaps executed | number_of_interest_rate_swaps | 2 | ||
Interest rate swap notional value | $ 250 | ||
Interest rate swap fixed interest rate | 4.9765% | ||
Derivative losses recognized in other comprehensive loss | $ (4.8) | (2.9) | 0 |
Net derivative gains reclassified from accumulated other comprehensive loss to interest expense | $ 1.1 | $ 1.6 | $ 2.2 |
Guarantees (Details)
Guarantees (Details) $ in Millions | Dec. 31, 2019USD ($) |
Guarantor Obligations | |
Total guarantees | $ 156 |
Guarantees expiring in less than one year | 22.2 |
Guarantees expiring within one to three years | 0.4 |
Guarantees with expiration over three years | 133.4 |
Guarantees supporting transactions of subsidiaries | |
Guarantor Obligations | |
Total guarantees | 31.4 |
Guarantees expiring in less than one year | 10.2 |
Guarantees expiring within one to three years | 0.2 |
Guarantees with expiration over three years | 21 |
Guarantees supporting transactions of subsidiaries | UMERC | |
Guarantor Obligations | |
Total guarantees | 4 |
Guarantees supporting transactions of subsidiaries | Bluewater | |
Guarantor Obligations | |
Total guarantees | 6.2 |
Guarantees supporting transactions of subsidiaries | WECI | |
Guarantor Obligations | |
Total guarantees | 21.2 |
Standby letters of credit | |
Guarantor Obligations | |
Total guarantees | 103 |
Guarantees expiring in less than one year | 1.2 |
Guarantees expiring within one to three years | 0.2 |
Guarantees with expiration over three years | 101.6 |
Surety bonds | |
Guarantor Obligations | |
Total guarantees | 9.9 |
Guarantees expiring in less than one year | 9.9 |
Guarantees expiring within one to three years | 0 |
Guarantees with expiration over three years | 0 |
Other guarantees | |
Guarantor Obligations | |
Total guarantees | 11.7 |
Guarantees expiring in less than one year | 0.9 |
Guarantees expiring within one to three years | 0 |
Guarantees with expiration over three years | 10.8 |
Other indemnification | |
Guarantor Obligations | |
Total guarantees | 11.7 |
Liability related to workers compensation coverage | $ 10.8 |
Employee Benefits - Change in B
Employee Benefits - Change in Benefit Obligations and Plan Assets (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Pension Benefits | |||
Change in benefit obligation | |||
Obligation at January 1 | $ 2,927.2 | $ 3,163.7 | |
Service cost | 47 | 47.1 | $ 44.6 |
Interest cost | 120.4 | 114.3 | 121.8 |
Participant contributions | 0 | 0 | |
Plan amendments | 0 | 0 | |
Actuarial loss (gain) | 269.3 | (171.8) | |
Benefit payments | (240.2) | (226.1) | |
Transfer | 0 | 0 | |
Obligation at December 31 | 3,123.7 | 2,927.2 | 3,163.7 |
Change in fair value of plan assets | |||
Beginning balance at January 1 | 2,690.8 | 2,966.8 | |
Actual return on plan assets | 494.1 | (122.2) | |
Employer contributions | 62.3 | 72.3 | |
Participant contributions | 0 | 0 | |
Benefit payments | (240.2) | (226.1) | |
Ending balance at December 31 | 3,007 | 2,690.8 | 2,966.8 |
Funded status at December 31 | (116.7) | (236.4) | |
OPEB Benefits | |||
Change in benefit obligation | |||
Obligation at January 1 | 608.2 | 818.5 | |
Service cost | 16.3 | 23.7 | 24.1 |
Interest cost | 25.7 | 29.9 | 32.9 |
Participant contributions | 12.3 | 15.5 | |
Plan amendments | (4) | (3.5) | |
Actuarial loss (gain) | (60.7) | (222.6) | |
Benefit payments | (42.3) | (55.4) | |
Federal subsidy on benefits paid | 1.3 | 1 | |
Transfer | 1.8 | 1.1 | |
Obligation at December 31 | 558.6 | 608.2 | 818.5 |
Change in fair value of plan assets | |||
Beginning balance at January 1 | 771.7 | 841.5 | |
Actual return on plan assets | 134.3 | (35.2) | |
Employer contributions | 3.6 | 5.3 | |
Participant contributions | 12.3 | 15.5 | |
Benefit payments | (42.3) | (55.4) | |
Ending balance at December 31 | 879.6 | 771.7 | $ 841.5 |
Funded status at December 31 | $ 321 | $ 163.5 |
Employee Benefits - Amounts Rec
Employee Benefits - Amounts Recognized on the Balance Sheets (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Defined Benefit Plan Disclosure [Line Items] | ||
Pension and OPEB obligations | $ 326.2 | $ 422.8 |
Pension Benefits | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Other long-term assets | 188.8 | 139.1 |
Pension and OPEB obligations | 305.5 | 375.5 |
Total net (liabilities) assets | (116.7) | (236.4) |
OPEB Benefits | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Other long-term assets | 341.7 | 210.8 |
Pension and OPEB obligations | 20.7 | 47.3 |
Total net (liabilities) assets | $ 321 | $ 163.5 |
Employee Benefits - Accumulated
Employee Benefits - Accumulated Benefit Obligations (Details) - Pension Plan - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Defined Benefit Plan Disclosure [Line Items] | ||
Accumulated benefit obligation | $ 2,992.9 | $ 2,804.9 |
Information for pension plans with an accumulated benefit obligation in excess of plan assets | ||
Projected benefit obligation | 1,810.1 | 1,930.8 |
Accumulated benefit obligation | 1,754.2 | 1,882.2 |
Fair value of plan assets | $ 1,504.6 | $ 1,572.7 |
Employee Benefits - Amounts Not
Employee Benefits - Amounts Not Yet Recognized in Net Periodic Benefit Cost (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Pension Benefits | ||
Accumulated other comprehensive loss (pre-tax) | ||
Net actuarial loss (gain) | $ 10.6 | $ 14.5 |
Prior service credits | 0 | 0 |
Total | 10.6 | 14.5 |
Net regulatory assets (liabilities) | ||
Net actuarial loss (gain) | 1,067.7 | 1,184.1 |
Prior service costs (credits) | 2.7 | 4.9 |
Total | 1,070.4 | 1,189 |
Estimated amounts that will be amortized into net periodic benefit cost next year | ||
Net actuarial loss (gain) | (97.1) | |
Prior service costs (credits) | 1.6 | |
Total 2020 – estimated amortization | 98.7 | |
OPEB Benefits | ||
Accumulated other comprehensive loss (pre-tax) | ||
Net actuarial loss (gain) | (1.6) | (1.6) |
Prior service credits | (0.1) | (0.1) |
Total | (1.7) | (1.7) |
Net regulatory assets (liabilities) | ||
Net actuarial loss (gain) | (266.6) | (133) |
Prior service costs (credits) | (88.6) | (100) |
Total | (355.2) | $ (233) |
Estimated amounts that will be amortized into net periodic benefit cost next year | ||
Net actuarial loss (gain) | 21.5 | |
Prior service costs (credits) | (15) | |
Total 2020 – estimated amortization | $ (36.5) |
Employee Benefits - Net Periodi
Employee Benefits - Net Periodic Benefit Cost (Credit) (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Pension Benefits | |||
Components of net periodic benefit cost (credit) (including amounts capitalized to the balance sheets) | |||
Service cost | $ 47 | $ 47.1 | $ 44.6 |
Interest cost | 120.4 | 114.3 | 121.8 |
Expected return on plan assets | (193.3) | (196.5) | (195.7) |
Plan settlement | 11.5 | 1 | 9 |
Amortization of prior service cost (credit) | 2.2 | 2.7 | 2.9 |
Amortization of net actuarial loss | 77.3 | 94 | 86.1 |
Net periodic benefit cost (credit) | 65.1 | 62.6 | 68.7 |
OPEB Benefits | |||
Components of net periodic benefit cost (credit) (including amounts capitalized to the balance sheets) | |||
Service cost | 16.3 | 23.7 | 24.1 |
Interest cost | 25.7 | 29.9 | 32.9 |
Expected return on plan assets | (54.7) | (59.5) | (55.5) |
Plan settlement | 0 | 0 | 0 |
Amortization of prior service cost (credit) | (15.4) | (15.4) | (12.3) |
Amortization of net actuarial loss | (6.6) | 1 | 3.1 |
Net periodic benefit cost (credit) | $ (34.7) | $ (20.3) | $ (7.7) |
Employee Benefits - Assumptions
Employee Benefits - Assumptions (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Pension Plan | Benefit obligation assumptions | ||||
Weighted average assumptions - benefit obligations | ||||
Discount rate | 3.41% | 4.30% | ||
Rate of compensation increase | 4.00% | 3.66% | ||
Pension Plan | Net periodic benefit cost assumptions | ||||
Weighted average assumptions - net periodic benefit cost | ||||
Discount rate | 4.21% | 3.71% | 4.11% | |
Expected return on plan assets | 7.12% | 7.12% | 7.11% | |
Rate of compensation increase | 3.66% | 3.66% | 3.60% | |
Pension Plan | Net periodic benefit cost assumptions | Subsequent event | ||||
Weighted average assumptions - net periodic benefit cost | ||||
Expected return on plan assets | 6.87% | |||
OPEB Plan | Benefit obligation assumptions | ||||
Weighted average assumptions - benefit obligations | ||||
Discount rate | 3.39% | 4.27% | ||
Effects of a one-percentage-point change in assumed health care cost trend rates | ||||
Effect of one-percentage-point increase on the health care component of the accumulated postretirement benefit obligation | $ 43.5 | |||
Effect of one-percentage-point decrease on the health care component of the accumulated postretirement benefit obligation | $ (36.5) | |||
OPEB Plan | Benefit obligation assumptions | Pre 65 | ||||
Medical cost trend rates | ||||
Assumed medical cost trend rate | 6.00% | 6.25% | ||
Ultimate trend rate | 5.00% | 5.00% | ||
Year ultimate trend rate is reached | 2028 | 2024 | ||
OPEB Plan | Benefit obligation assumptions | Post 65 | ||||
Medical cost trend rates | ||||
Assumed medical cost trend rate | 5.91% | 6.01% | ||
Ultimate trend rate | 5.00% | 5.00% | ||
Year ultimate trend rate is reached | 2028 | 2028 | ||
OPEB Plan | Net periodic benefit cost assumptions | ||||
Weighted average assumptions - net periodic benefit cost | ||||
Discount rate | 4.27% | 3.63% | 4.04% | |
Expected return on plan assets | 7.25% | 7.25% | 7.25% | |
Effects of a one-percentage-point change in assumed health care cost trend rates | ||||
Effect of one-percentage-point increase on total of service and interest cost components of net periodic postretirement health care benefit cost | $ 4.7 | |||
Effect of one-percentage-point decrease on total of service and interest cost components of net periodic postretirement health care benefit cost | $ (3.8) | |||
OPEB Plan | Net periodic benefit cost assumptions | Subsequent event | ||||
Weighted average assumptions - net periodic benefit cost | ||||
Expected return on plan assets | 7.00% | |||
OPEB Plan | Net periodic benefit cost assumptions | Pre 65 | ||||
Medical cost trend rates | ||||
Assumed medical cost trend rate | 6.25% | 6.50% | 7.00% | |
Ultimate trend rate | 5.00% | 5.00% | 5.00% | |
Year ultimate trend rate is reached | 2024 | 2024 | 2021 | |
OPEB Plan | Net periodic benefit cost assumptions | Post 65 | ||||
Medical cost trend rates | ||||
Assumed medical cost trend rate | 6.01% | 6.09% | 7.00% | |
Ultimate trend rate | 5.00% | 5.00% | 5.00% | |
Year ultimate trend rate is reached | 2028 | 2028 | 2021 |
Employee Benefits - Target Asse
Employee Benefits - Target Asset Allocations (Details) | Dec. 31, 2019 |
Pension Plan | Wisconsin Energy Corporation | Equity securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 35.00% |
Pension Plan | Wisconsin Energy Corporation | Fixed income securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 55.00% |
Pension Plan | Wisconsin Energy Corporation | Private Equity and Real Estate | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 10.00% |
Pension Plan | Integrys Holding Inc | Equity securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 45.00% |
Pension Plan | Integrys Holding Inc | Fixed income securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 45.00% |
Pension Plan | Integrys Holding Inc | Private Equity and Real Estate | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 10.00% |
OPEB Plan | Wisconsin Energy Corporation | Largest trust 1 | Equity securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 50.00% |
OPEB Plan | Wisconsin Energy Corporation | Largest trust 1 | Fixed income securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 50.00% |
OPEB Plan | Wisconsin Energy Corporation | Largest trust 2 | Equity securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 70.00% |
OPEB Plan | Wisconsin Energy Corporation | Largest trust 2 | Fixed income securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 30.00% |
OPEB Plan | Integrys Holding Inc | Largest trust 1 | Equity securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 45.00% |
OPEB Plan | Integrys Holding Inc | Largest trust 1 | Fixed income securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 55.00% |
OPEB Plan | Integrys Holding Inc | Largest trust 2 | Equity securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 45.00% |
OPEB Plan | Integrys Holding Inc | Largest trust 2 | Fixed income securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 55.00% |
Employee Benefits - Plan Assets
Employee Benefits - Plan Assets (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 |
Pension Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | $ 3,007 | $ 2,690.8 | $ 2,966.8 |
Pension Plan | Level 1, 2, and 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 1,778.1 | 1,626.2 | |
Pension Plan | Level 1, 2, and 3 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 335.6 | 281.7 | |
Pension Plan | Level 1, 2, and 3 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 322.3 | 280.4 | |
Pension Plan | Level 1, 2, and 3 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 981.7 | 962.5 | |
Pension Plan | Level 1, 2, and 3 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 138.5 | 101.6 | |
Pension Plan | Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 803 | 701.2 | |
Pension Plan | Level 1 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 335.6 | 281.7 | |
Pension Plan | Level 1 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 321.6 | 279.7 | |
Pension Plan | Level 1 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 94.3 | 123.7 | |
Pension Plan | Level 1 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 51.5 | 16.1 | |
Pension Plan | Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 975.1 | 925 | |
Pension Plan | Level 2 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Plan | Level 2 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0.7 | 0.7 | |
Pension Plan | Level 2 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 887.4 | 838.8 | |
Pension Plan | Level 2 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 87 | 85.5 | |
Pension Plan | Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Plan | Level 3 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Plan | Level 3 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | 0.8 |
Pension Plan | Level 3 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Plan | Level 3 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Plan | Investments measured at net asset value per share | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 1,228.9 | 1,064.6 | |
OPEB Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 879.6 | 771.7 | 841.5 |
OPEB Plan | Level 1, 2, and 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 528.6 | 467 | |
OPEB Plan | Level 1, 2, and 3 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 103 | 88.2 | |
OPEB Plan | Level 1, 2, and 3 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 107.5 | 92.4 | |
OPEB Plan | Level 1, 2, and 3 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 285 | 270.4 | |
OPEB Plan | Level 1, 2, and 3 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 33.1 | 16 | |
OPEB Plan | Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 354 | 307.1 | |
OPEB Plan | Level 1 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 103 | 88.2 | |
OPEB Plan | Level 1 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 107.3 | 92.2 | |
OPEB Plan | Level 1 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 119.1 | 119.6 | |
OPEB Plan | Level 1 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 24.6 | 7.1 | |
OPEB Plan | Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 174.6 | 159.9 | |
OPEB Plan | Level 2 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
OPEB Plan | Level 2 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0.2 | 0.2 | |
OPEB Plan | Level 2 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 165.9 | 150.8 | |
OPEB Plan | Level 2 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 8.5 | 8.9 | |
OPEB Plan | Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
OPEB Plan | Level 3 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
OPEB Plan | Level 3 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | $ 0.2 |
OPEB Plan | Level 3 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
OPEB Plan | Level 3 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
OPEB Plan | Investments measured at net asset value per share | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | $ 351 | $ 304.7 |
Employee Benefits - Changes in
Employee Benefits - Changes in the Fair Value of Plan Assets Categorized as Level 3 (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Pension Plan | ||
Reconciliation of changes in the fair value of pension plan assets | ||
Beginning balance at January 1 | $ 2,690.8 | $ 2,966.8 |
Realized and unrealized gains (losses) | 494.1 | (122.2) |
Ending balance at December 31 | 3,007 | 2,690.8 |
Pension Plan | Level 3 | ||
Reconciliation of changes in the fair value of pension plan assets | ||
Beginning balance at January 1 | 0 | |
Ending balance at December 31 | 0 | 0 |
Pension Plan | Level 3 | Private Equity and Real Estate | ||
Reconciliation of changes in the fair value of pension plan assets | ||
Beginning balance at January 1 | 0 | 100.1 |
Realized and unrealized gains (losses) | 8 | |
Purchases | 18.3 | |
Liquidations | (1.7) | |
Transfers out of level 3 | (124.7) | |
Ending balance at December 31 | 0 | |
Pension Plan | Level 3 | International equity | ||
Reconciliation of changes in the fair value of pension plan assets | ||
Beginning balance at January 1 | 0 | 0.8 |
Realized and unrealized gains (losses) | (0.1) | |
Purchases | 0 | |
Liquidations | 0 | |
Transfers out of level 3 | (0.7) | |
Ending balance at December 31 | 0 | 0 |
OPEB Plan | ||
Reconciliation of changes in the fair value of pension plan assets | ||
Beginning balance at January 1 | 771.7 | 841.5 |
Realized and unrealized gains (losses) | 134.3 | (35.2) |
Ending balance at December 31 | 879.6 | 771.7 |
OPEB Plan | Level 3 | ||
Reconciliation of changes in the fair value of pension plan assets | ||
Beginning balance at January 1 | 0 | |
Ending balance at December 31 | 0 | 0 |
OPEB Plan | Level 3 | Private Equity and Real Estate | ||
Reconciliation of changes in the fair value of pension plan assets | ||
Beginning balance at January 1 | 0 | 7.7 |
Realized and unrealized gains (losses) | 1.1 | |
Purchases | 1.5 | |
Liquidations | (0.2) | |
Transfers out of level 3 | (10.1) | |
Ending balance at December 31 | 0 | |
OPEB Plan | Level 3 | International equity | ||
Reconciliation of changes in the fair value of pension plan assets | ||
Beginning balance at January 1 | 0 | 0.2 |
Realized and unrealized gains (losses) | 0 | |
Purchases | 0 | |
Liquidations | 0 | |
Transfers out of level 3 | (0.2) | |
Ending balance at December 31 | $ 0 | $ 0 |
Employee Benefits - Cash Flows
Employee Benefits - Cash Flows (Details) $ in Millions | Dec. 31, 2019USD ($) |
Pension Benefits | |
Defined Benefit Plan Disclosure [Line Items] | |
Expected contributions to the plans during the next year | $ 11.6 |
2020 | 236.9 |
2021 | 236.7 |
2022 | 228.4 |
2023 | 226.8 |
2024 | 218.8 |
2025 through 2029 | 1,004.2 |
OPEB Benefits | |
Defined Benefit Plan Disclosure [Line Items] | |
Expected contributions to the plans during the next year | 0.9 |
2020 | 37.1 |
2021 | 34.7 |
2022 | 35.6 |
2023 | 36.1 |
2024 | 36.1 |
2025 through 2029 | $ 179.5 |
Employee Benefits - Defined Con
Employee Benefits - Defined Contribution Benefit Plans (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Defined Contribution Benefit Plans | |||
Total costs incurred for defined contribution benefit plans | $ 50.9 | $ 49.3 | $ 47.9 |
Investment in Transmission Af_3
Investment in Transmission Affiliates - Changes to Investment in ATC (Details) $ in Millions | 1 Months Ended | 12 Months Ended | |||
Nov. 30, 2019 | Dec. 31, 2019USD ($)membervote | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | |
Changes to investment in transmission affiliates | |||||
Equity in earnings of transmission affiliates | $ 127.6 | $ 136.7 | $ 154.3 | ||
Capital contributions | 52.6 | 53.5 | 109.6 | ||
Transmission Affiliates | |||||
Changes to investment in transmission affiliates | |||||
Investment in ATC, balance at beginning of period | 1,665.3 | 1,553.4 | 1,443.9 | ||
Equity in earnings of transmission affiliates | 127.6 | 136.7 | 154.3 | ||
Capital contributions | 52.6 | 53.5 | 109.6 | ||
Distributions | 124.7 | 78.2 | 154.2 | ||
Other | 0.1 | 0.2 | |||
Investment in ATC, balance at end of period | $ 1,720.8 | 1,665.3 | 1,553.4 | ||
ATC | |||||
Investment in Transmission Affiliates | |||||
Equity interest in ATC | 60.00% | ||||
Total number of members serving on the transmission affiliate's board of directors | member | 10 | ||||
Number of representatives on the transmission affiliate's board of directors | member | 1 | ||||
Number of votes that can be placed by each member on the transmission affiliate's board of directors | vote | 1 | ||||
Maximum voting control of any member on the transmission affiliate's board of directors | 10.00% | ||||
Liability for potential future refunds that ATC may be required to provide | $ 41.9 | ||||
Approved return on equity (as a percent) | 10.38% | ||||
Changes to investment in transmission affiliates | |||||
Investment in ATC, balance at beginning of period | 1,625.3 | 1,515.8 | 1,443.9 | ||
Equity in earnings of transmission affiliates | 132.8 | 139.6 | 166 | ||
Capital contributions | 51.3 | 48.2 | 60.3 | ||
Distributions | 124.7 | 78.2 | 154.2 | ||
Other | 0.1 | 0.2 | |||
Investment in ATC, balance at end of period | $ 1,684.7 | 1,625.3 | 1,515.8 | ||
Dividends not received | |||||
Dividends Receivable | 39.9 | $ 35.2 | |||
ATC HoldCo | |||||
Investment in Transmission Affiliates | |||||
Equity interest in ATC | 75.00% | ||||
Total number of members serving on the transmission affiliate's board of directors | member | 10 | ||||
Number of representatives on the transmission affiliate's board of directors | member | 1 | ||||
Number of votes that can be placed by each member on the transmission affiliate's board of directors | vote | 1 | ||||
Maximum voting control of any member on the transmission affiliate's board of directors | 10.00% | ||||
Changes to investment in transmission affiliates | |||||
Investment in ATC, balance at beginning of period | $ 40 | 37.6 | 0 | ||
Equity in earnings of transmission affiliates | (5.2) | (2.9) | (11.7) | ||
Capital contributions | 1.3 | 5.3 | 49.3 | ||
Distributions | 0 | 0 | 0 | ||
Other | 0 | 0 | |||
Investment in ATC, balance at end of period | $ 36.1 | $ 40 | $ 37.6 |
Investment in Transmission Af_4
Investment in Transmission Affiliates - Transactions with ATC (Details) - ATC - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Significant related party transactions | |||
Charges to ATC for services and construction | $ 25.9 | $ 21.8 | $ 17.1 |
Charges from ATC for network transmission services | 348.1 | 338.1 | 349.3 |
Refund from ATC related to a FERC audit | 0 | 22 | 0 |
Refund from ATC per FERC ROE order | 0 | 0 | $ 28.3 |
Balance Sheet | |||
Accounts receivable for services provided to ATC | 3.5 | 3.4 | |
Accounts payable for services received from ATC | 29 | 28.2 | |
Amounts due from ATC for transmission infrastructure upgrades | $ 2.8 | $ 29.4 |
Investment in Transmission Af_5
Investment in Transmission Affiliates - ATC Summarized Financial Data (Details) - ATC - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Income statement data | |||
Revenues | $ 744.4 | $ 690.5 | $ 721.7 |
Operating expenses | 373.5 | 358.7 | 345 |
Other expense | 110.5 | 108.3 | 104.1 |
Net income | 260.4 | 223.5 | $ 272.6 |
Balance sheet data | |||
Current assets | 84.7 | 87.2 | |
Noncurrent assets | 5,244.2 | 4,928.8 | |
Total assets | 5,328.9 | 5,016 | |
Current liabilities | 502.6 | 640 | |
Long-term debt | 2,312.8 | 2,014 | |
Other noncurrent liabilities | 298.9 | 295.3 | |
Shareholders' equity | 2,214.6 | 2,066.7 | |
Total liabilities and shareholders' equity | $ 5,328.9 | $ 5,016 |
Segment Information (Details)
Segment Information (Details) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2019USD ($) | Sep. 30, 2019USD ($) | Jun. 30, 2019USD ($) | Mar. 31, 2019USD ($) | Dec. 31, 2018USD ($) | Sep. 30, 2018USD ($) | Jun. 30, 2018USD ($) | Mar. 31, 2018USD ($) | Dec. 31, 2019USD ($)segment | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | |
Segment information | |||||||||||
Number of reportable segments | segment | 6 | ||||||||||
Revenues | $ 1,947.5 | $ 1,608 | $ 1,590.2 | $ 2,377.4 | $ 2,076.8 | $ 1,643.7 | $ 1,672.5 | $ 2,286.5 | $ 7,523.1 | $ 7,679.5 | $ 7,648.5 |
Other operation and maintenance | 2,184.8 | 2,270.5 | 2,056.1 | ||||||||
Depreciation and amortization | 926.3 | 845.8 | 798.6 | ||||||||
Operating income (loss) | 363.1 | $ 310.9 | $ 314.6 | $ 542.8 | 289.8 | $ 302.7 | $ 330.8 | $ 545.1 | 1,531.4 | 1,468.4 | 1,776.1 |
Equity in earnings of transmission affiliates | 127.6 | 136.7 | 154.3 | ||||||||
Interest expense | 501.5 | 445.1 | 415.7 | ||||||||
Capital expenditures and asset acquisitions | 2,529 | 2,417.1 | 1,959.5 | ||||||||
Total assets | 34,951.8 | 33,475.8 | 34,951.8 | 33,475.8 | 31,590.5 | ||||||
Wisconsin | |||||||||||
Segment information | |||||||||||
Revenues | 5,647.1 | 5,794.7 | |||||||||
Illinois | |||||||||||
Segment information | |||||||||||
Revenues | 1,357.1 | 1,400 | |||||||||
Other States | |||||||||||
Segment information | |||||||||||
Revenues | 426 | 438.2 | |||||||||
Electric transmission | |||||||||||
Segment information | |||||||||||
Other operation and maintenance | 0 | 0 | 0 | ||||||||
Depreciation and amortization | 0 | 0 | 0 | ||||||||
Operating income (loss) | 0 | 0 | 0 | ||||||||
Equity in earnings of transmission affiliates | 127.6 | 136.7 | 154.3 | ||||||||
Interest expense | 13.1 | 0.3 | 0 | ||||||||
Capital expenditures and asset acquisitions | 0 | 0 | 0 | ||||||||
Total assets | 1,723.1 | 1,665.3 | $ 1,723.1 | 1,665.3 | 1,593.4 | ||||||
Non-Utility Energy Infrastructure | |||||||||||
Segment information | |||||||||||
Natural gas storage needs provided to Wisconsin utilities | 33.00% | ||||||||||
Revenues | $ 495.9 | 468.4 | |||||||||
Other operation and maintenance | 19.7 | 12.6 | 7.3 | ||||||||
Depreciation and amortization | 92 | 75.7 | 71.4 | ||||||||
Operating income (loss) | 366.6 | 365.8 | 400.5 | ||||||||
Equity in earnings of transmission affiliates | 0 | 0 | 0 | ||||||||
Interest expense | 62.1 | 63.7 | 62.8 | ||||||||
Capital expenditures and asset acquisitions | 389.9 | 260.6 | 35.4 | ||||||||
Total assets | 3,654.1 | 3,227.2 | 3,654.1 | 3,227.2 | 2,992.8 | ||||||
Corporate and other | |||||||||||
Segment information | |||||||||||
Revenues | 4.4 | 8.7 | |||||||||
Other operation and maintenance | 14 | 1.8 | 1.4 | ||||||||
Depreciation and amortization | 24.3 | 29.1 | 25.9 | ||||||||
Operating income (loss) | (34.4) | (22.2) | (13.9) | ||||||||
Equity in earnings of transmission affiliates | 0 | 0 | 0 | ||||||||
Interest expense | 140.9 | 125.8 | 107.3 | ||||||||
Capital expenditures and asset acquisitions | 26.5 | 39.7 | 152.1 | ||||||||
Total assets | 814 | 959.6 | 814 | 959.6 | 953.6 | ||||||
Reconciling eliminations | |||||||||||
Segment information | |||||||||||
Other operation and maintenance | 0.2 | (393.3) | (441.1) | ||||||||
Depreciation and amortization | (15.8) | 0 | 0 | ||||||||
Operating income (loss) | (347.6) | 0 | 0 | ||||||||
Equity in earnings of transmission affiliates | 0 | 0 | 0 | ||||||||
Interest expense | (354.1) | (5.3) | (1.8) | ||||||||
Capital expenditures and asset acquisitions | 0 | 0 | 0 | ||||||||
Total assets | (3,344.5) | (3,414.5) | (3,344.5) | (3,414.5) | (3,398.9) | ||||||
Reconciling eliminations | WE | |||||||||||
Segment information | |||||||||||
Total assets | $ 1,896.7 | 1,968.5 | $ 1,896.7 | 1,968.5 | 2,038.1 | ||||||
ATC | |||||||||||
Segment information | |||||||||||
Equity method investment, ownership interest (as a percent) | 60.00% | 60.00% | |||||||||
Equity in earnings of transmission affiliates | $ 132.8 | 139.6 | 166 | ||||||||
ATC | Electric transmission | |||||||||||
Segment information | |||||||||||
Equity method investment, ownership interest (as a percent) | 60.00% | 60.00% | |||||||||
ATC HoldCo | |||||||||||
Segment information | |||||||||||
Equity method investment, ownership interest (as a percent) | 75.00% | 75.00% | |||||||||
Equity in earnings of transmission affiliates | $ (5.2) | (2.9) | (11.7) | ||||||||
ATC HoldCo | Electric transmission | |||||||||||
Segment information | |||||||||||
Equity method investment, ownership interest (as a percent) | 75.00% | 75.00% | |||||||||
Bishop Hill III Wind Energy Center | Non-Utility Energy Infrastructure | |||||||||||
Segment information | |||||||||||
WEC's ownership interest in Bishop Hill III Wind Energy Center | 90.00% | 90.00% | |||||||||
Coyote Ridge | Non-Utility Energy Infrastructure | |||||||||||
Segment information | |||||||||||
WEC's ownership interest in Coyote Ridge Wind, LLC | 80.00% | 80.00% | |||||||||
Upstream | Non-Utility Energy Infrastructure | |||||||||||
Segment information | |||||||||||
WEC's ownership interest in Upstream Wind Energy Center | 80.00% | 80.00% | |||||||||
Public Utilities | |||||||||||
Segment information | |||||||||||
Other operation and maintenance | $ 2,150.9 | 2,649.4 | 2,488.5 | ||||||||
Depreciation and amortization | 825.8 | 741 | 701.3 | ||||||||
Operating income (loss) | 1,546.8 | 1,124.8 | 1,389.5 | ||||||||
Equity in earnings of transmission affiliates | 0 | 0 | 0 | ||||||||
Interest expense | 639.5 | 260.6 | 247.4 | ||||||||
Capital expenditures and asset acquisitions | 2,112.6 | 2,116.8 | 1,772 | ||||||||
Total assets | $ 32,105.1 | 31,038.2 | 32,105.1 | 31,038.2 | 29,449.6 | ||||||
Public Utilities | Wisconsin | |||||||||||
Segment information | |||||||||||
Other operation and maintenance | 1,591.3 | 2,076.1 | 1,923.2 | ||||||||
Depreciation and amortization | 617 | 546.6 | 523.9 | ||||||||
Operating income (loss) | 1,189.6 | 800.2 | 1,055.2 | ||||||||
Equity in earnings of transmission affiliates | 0 | 0 | 0 | ||||||||
Interest expense | 572 | 200.7 | 193.7 | ||||||||
Capital expenditures and asset acquisitions | 1,378.6 | 1,466.1 | 1,152.3 | ||||||||
Total assets | 23,934.8 | 23,407 | 23,934.8 | 23,407 | 22,237.1 | ||||||
Public Utilities | Illinois | |||||||||||
Segment information | |||||||||||
Other operation and maintenance | 461.1 | 472.3 | 464.2 | ||||||||
Depreciation and amortization | 181.3 | 170.3 | 152.6 | ||||||||
Operating income (loss) | 291.9 | 255.8 | 279.9 | ||||||||
Equity in earnings of transmission affiliates | 0 | 0 | 0 | ||||||||
Interest expense | 59 | 51.2 | 45 | ||||||||
Capital expenditures and asset acquisitions | 624.9 | 547.1 | 545.2 | ||||||||
Total assets | 6,932.5 | 6,483.3 | 6,932.5 | 6,483.3 | 6,144.7 | ||||||
Public Utilities | Other States | |||||||||||
Segment information | |||||||||||
Other operation and maintenance | 98.5 | 101 | 101.1 | ||||||||
Depreciation and amortization | 27.5 | 24.1 | 24.8 | ||||||||
Operating income (loss) | 65.3 | 68.8 | 54.4 | ||||||||
Equity in earnings of transmission affiliates | 0 | 0 | 0 | ||||||||
Interest expense | 8.5 | 8.7 | 8.7 | ||||||||
Capital expenditures and asset acquisitions | 109.1 | 103.6 | 74.5 | ||||||||
Total assets | $ 1,237.8 | $ 1,147.9 | 1,237.8 | 1,147.9 | 1,067.8 | ||||||
External Revenues | Electric transmission | |||||||||||
Segment information | |||||||||||
Revenues | 0 | 0 | 0 | ||||||||
External Revenues | Non-Utility Energy Infrastructure | |||||||||||
Segment information | |||||||||||
Revenues | 88.5 | 37.9 | 38.9 | ||||||||
External Revenues | Corporate and other | |||||||||||
Segment information | |||||||||||
Revenues | 4.4 | 8.7 | 13.7 | ||||||||
External Revenues | Reconciling eliminations | |||||||||||
Segment information | |||||||||||
Revenues | 0 | 0 | 0 | ||||||||
External Revenues | Public Utilities | |||||||||||
Segment information | |||||||||||
Revenues | 7,430.2 | 7,632.9 | 7,595.9 | ||||||||
External Revenues | Public Utilities | Wisconsin | |||||||||||
Segment information | |||||||||||
Revenues | 5,647.1 | 5,794.7 | 5,829.2 | ||||||||
External Revenues | Public Utilities | Illinois | |||||||||||
Segment information | |||||||||||
Revenues | 1,357.1 | 1,400 | 1,355.5 | ||||||||
External Revenues | Public Utilities | Other States | |||||||||||
Segment information | |||||||||||
Revenues | 426 | 438.2 | 411.2 | ||||||||
Intersegment Transactions | |||||||||||
Segment information | |||||||||||
Revenues | 0 | 0 | 0 | ||||||||
Intersegment Transactions | Electric transmission | |||||||||||
Segment information | |||||||||||
Revenues | 0 | 0 | 0 | ||||||||
Intersegment Transactions | Non-Utility Energy Infrastructure | |||||||||||
Segment information | |||||||||||
Revenues | 407.4 | 430.5 | 446.3 | ||||||||
Intersegment Transactions | Corporate and other | |||||||||||
Segment information | |||||||||||
Revenues | 0 | 0 | 0 | ||||||||
Intersegment Transactions | Reconciling eliminations | |||||||||||
Segment information | |||||||||||
Revenues | (407.4) | (430.5) | (446.3) | ||||||||
Intersegment Transactions | Public Utilities | |||||||||||
Segment information | |||||||||||
Revenues | 0 | 0 | 0 | ||||||||
Intersegment Transactions | Public Utilities | Wisconsin | |||||||||||
Segment information | |||||||||||
Revenues | 0 | 0 | 0 | ||||||||
Intersegment Transactions | Public Utilities | Illinois | |||||||||||
Segment information | |||||||||||
Revenues | 0 | 0 | 0 | ||||||||
Intersegment Transactions | Public Utilities | Other States | |||||||||||
Segment information | |||||||||||
Revenues | $ 0 | $ 0 | $ 0 |
Variable Interest Entities (Det
Variable Interest Entities (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2019USD ($)MW | Dec. 31, 2018USD ($) | |
ATC | ||
Variable interest entities | ||
Equity method investment, ownership interest (as a percent) | 60.00% | |
Equity investment | $ 1,684.7 | $ 1,625.3 |
ATC HoldCo | ||
Variable interest entities | ||
Equity method investment, ownership interest (as a percent) | 75.00% | |
Equity investment | $ 36.1 | $ 40 |
Power purchase agreement | ||
Variable interest entities | ||
Firm capacity from purchased power agreement (in megawatts) | MW | 236 | |
Minimum energy requirements over remaining term of purchased power agreement (in megawatts) | MW | 0 | |
Remaining term of purchased power agreement (in years) | 2 years | |
Residual guarantee associated with purchased power agreement | $ 0 | |
Required payments over remaining term of purchased power agreement | $ 22.4 |
Commitments and Contingencies -
Commitments and Contingencies - Unconditional Purchase Obligations (Details) $ in Millions | Dec. 31, 2019USD ($) |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | $ 11,570 |
2020 | 1,231.1 |
2021 | 1,112.3 |
2022 | 1,040.6 |
2023 | 946.8 |
2024 | 720.7 |
Later Years | 6,518.5 |
Nuclear | Electric | |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | 8,319 |
2020 | 475.1 |
2021 | 501.1 |
2022 | 531.2 |
2023 | 563 |
2024 | 596.8 |
Later Years | 5,651.8 |
Coal supply and transportation | Electric | |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | 983.2 |
2020 | 306.9 |
2021 | 255.7 |
2022 | 223.4 |
2023 | 196.5 |
2024 | 0.7 |
Later Years | 0 |
Purchased power | Electric | |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | 428.3 |
2020 | 88.9 |
2021 | 58.5 |
2022 | 51.5 |
2023 | 46.5 |
2024 | 43.4 |
Later Years | 139.5 |
Supply and transportation | Natural gas | |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | 1,652.3 |
2020 | 344.8 |
2021 | 285.5 |
2022 | 224.6 |
2023 | 131.2 |
2024 | 70.8 |
Later Years | 595.4 |
Non-Utility Energy Infrastructure | Purchased power | Electric | |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | 173.6 |
2020 | 7.7 |
2021 | 8.8 |
2022 | 8.6 |
2023 | 8.8 |
2024 | 8.9 |
Later Years | 130.8 |
Non-Utility Energy Infrastructure | Natural gas storage and transportation | Natural gas | |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | 13.6 |
2020 | 7.7 |
2021 | 2.7 |
2022 | 1.3 |
2023 | 0.8 |
2024 | 0.1 |
Later Years | $ 1 |
Commitments and Contingencies_2
Commitments and Contingencies - Environmental Matters (Details) T in Millions, $ in Millions | 1 Months Ended | 12 Months Ended | |||
Sep. 30, 2019Years | Apr. 30, 2019degreecelsius | Dec. 31, 2018USD ($)change | Dec. 31, 2019USD ($)generating_unitsTMW | Dec. 31, 2018USD ($)T | |
Mercury and Air Toxics | Electric | |||||
Air Quality | |||||
Revisions to mercury and air toxics standards | change | 0 | ||||
Climate Change | Electric | |||||
Air Quality | |||||
Number of states challenging the ACE rule | Years | 22 | ||||
Company goal for percentage of carbon dioxide emissions reductions by 2030 | 40.00% | ||||
Capacity of coal generation retired since the beginning of 2018 | MW | 1,800 | ||||
Per mile rate of methane emission reduction | 30.00% | ||||
Carbon dioxide emissions | T | 21.8 | 26.4 | |||
Climate Change | Electric | Maximum | |||||
Air Quality | |||||
Global temperature increases limit | degreecelsius | 2 | ||||
Climate Change | Natural gas | |||||
Air Quality | |||||
Carbon dioxide emissions | T | 29.4 | 29.4 | |||
Steam Electric Effluent Guidelines | Electric | |||||
Water Quality | |||||
Total units of OCPP and ERGS | generating_units | 6 | ||||
Expected cost to achieve required discharge limits | $ 60 | ||||
Manufactured Gas Plant Remediation | Natural gas | |||||
Manufactured Gas Plant Remediation | |||||
Regulatory assets recorded for remediation of manufactured gas plant sites | $ 687.1 | 685.5 | $ 687.1 | ||
Reserves for future environmental remediation of manufactured gas plant sites | $ 616.4 | $ 589.2 | $ 616.4 | ||
Renewables, Efficiency, and Conservation | Electric | Wisconsin | |||||
Renewables, Efficiency, and Conservation | |||||
Annual state renewable portfolio requirement, as a percent | 10.00% | ||||
Percent of annual operating revenues used to fund renewable program | 1.20% | ||||
Renewables, Efficiency, and Conservation | Electric | Wisconsin | WE | |||||
Renewables, Efficiency, and Conservation | |||||
Required renewable energy percent achieved | 8.27% | ||||
Renewables, Efficiency, and Conservation | Electric | Wisconsin | WPS | |||||
Renewables, Efficiency, and Conservation | |||||
Required renewable energy percent achieved | 9.74% | ||||
Renewables, Efficiency, and Conservation | Electric | Michigan | |||||
Renewables, Efficiency, and Conservation | |||||
State renewable portfolio requirement for years 2019 through 2020, as a percent | 12.50% | ||||
Energy optimization target, as a percent | 1.00% | ||||
State renewable portfolio requirement for 2021, as a percent | 15.00% |
Supplemental Cash Flow Inform_3
Supplemental Cash Flow Information - Supplemental Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Supplemental cash flow information | |||
Cash paid for interest, net of amount capitalized | $ 485.9 | $ 441.5 | $ 413.7 |
Cash paid (received) for income taxes, net | (24.9) | 16.3 | (5.2) |
Accounts payable related to construction costs | 159.9 | 65.9 | 169.2 |
Capital contributions from noncontrolling interest | 21 | 0 | 0 |
Receivable related to corporate-owned life insurance proceeds | 0 | 7.7 | 0 |
Bostco | |||
Supplemental cash flow information | |||
Portion of Bostco real estate holdings sale financed with note receivable | $ 0 | $ 0 | $ 7 |
Supplemental Cash Flow Inform_4
Supplemental Cash Flow Information - Reconciliation of Cash and Cash Equivalents and Restricted Cash (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Supplemental Cash Flow Information [Abstract] | ||||
Cash and cash equivalents | $ 37.5 | $ 84.5 | $ 38.9 | |
Restricted cash included in other current assets | 0 | 2.5 | 0 | |
Restricted cash included in other long term assets | 44.8 | 59.1 | 19.7 | |
Cash, cash equivalents, and restricted cash | $ 82.3 | $ 146.1 | $ 58.6 | $ 72.7 |
Regulatory Environment - Tax Cu
Regulatory Environment - Tax Cuts and Jobs Act of 2017 (Details) $ in Millions | 1 Months Ended | |||
May 31, 2018 | Feb. 28, 2018Filings | Dec. 31, 2017USD ($) | Dec. 31, 2019customer | |
Public Utilities, General Disclosures [Line Items] | ||||
Estimated tax benefit related to the remeasurement of deferred income taxes from tax legislation | $ 2,657 | |||
MPSC | WE | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Number of Electric Customers Served in Michigan | customer | 1 | |||
MPSC | MGU | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Number of filings required related to the Tax Cuts and Jobs Act of 2018 | Filings | 3 | |||
Tax Cuts and Jobs Act of 2017 | Utility operations | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Estimated tax benefit related to the remeasurement of deferred income taxes from tax legislation | $ 2,529 | |||
2018 and 2019 rates | Electric rates | Public Service Commission of Wisconsin (PSCW) | WE | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Percentage of current tax benefit from Tax Cuts and Jobs Act of 2017 to be used to reduce regulatory assets | 80.00% | |||
Percent of current tax benefit from Tax Cuts and Jobs Act of 2017 to be returned to customers via bill credits | 20.00% | |||
2018 and 2019 rates | Electric rates | Public Service Commission of Wisconsin (PSCW) | WPS | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Percentage of current tax benefit from Tax Cuts and Jobs Act of 2017 to be used to reduce regulatory assets | 40.00% | |||
Percent of current tax benefit from Tax Cuts and Jobs Act of 2017 to be returned to customers via bill credits | 60.00% | |||
2018 and 2019 rates | Natural gas rates | Public Service Commission of Wisconsin (PSCW) | WE, WG, and WPS | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Percent of current tax benefit from Tax Cuts and Jobs Act of 2017 to be returned to customers via bill credits | 100.00% |
Regulatory Environment - WI 202
Regulatory Environment - WI 2020 and 2021 Rates (Details) - Public Service Commission of Wisconsin (PSCW) - USD ($) | 1 Months Ended | |
Dec. 31, 2019 | Sep. 30, 2017 | |
2020 and 2021 rates | ||
Public Utilities, General Disclosures [Line Items] | ||
Number of utilities with earnings sharing mechanism | (3) | |
Percentage of first 25 basis points of additional earnings retained by the utility | 100.00% | |
Percentage of additional earnings between 25 and 75 basis points refunded to customers | 50.00% | |
Percentage of earnings in excess of 75 basis points refunded to customers | 100.00% | |
Return on equity in excess of authorized amount (as a percent) | 0.25% | |
Return on equity in excess of first 25 basis points above authorized amount (as a percent) | 0.50% | |
Electric rates | 2020 and 2021 rates | Tax Cuts and Jobs Act of 2017 | ||
Public Utilities, General Disclosures [Line Items] | ||
Amortization period | 2 years | |
Natural gas rates | 2020 and 2021 rates | Tax Cuts and Jobs Act of 2017 | ||
Public Utilities, General Disclosures [Line Items] | ||
Amortization period | 4 years | |
Number of gas utilities amortizing unprotected deferred tax expense over 4 years | 3 | |
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 | 2018 and 2019 rates | ||
Public Utilities, General Disclosures [Line Items] | ||
Approved return on equity (as a percent) | 10.20% | |
WE | Electric rates | 2020 rates | ||
Public Utilities, General Disclosures [Line Items] | ||
Approved rate increase | $ 15,300,000 | |
Approved rate increase (as a percent) | 0.50% | |
WE | Electric rates | 2020 rates | Tax Cuts and Jobs Act of 2017 | ||
Public Utilities, General Disclosures [Line Items] | ||
Amortization of regulatory liabilities | $ 65,000,000 | |
WE | Electric rates | 2020 and 2021 rates | ||
Public Utilities, General Disclosures [Line Items] | ||
Pleasant Prairie power plant's book value to be securitized | 100,000,000 | |
WE | Natural gas rates | 2020 rates | ||
Public Utilities, General Disclosures [Line Items] | ||
Approved rate increase | $ 10,400,000 | |
Approved rate increase (as a percent) | 2.80% | |
WE | Natural gas rates | 2020 rates | Tax Cuts and Jobs Act of 2017 | ||
Public Utilities, General Disclosures [Line Items] | ||
Amortization of regulatory liabilities | $ 5,000,000 | |
WE | Steam rates | 2020 rates | ||
Public Utilities, General Disclosures [Line Items] | ||
Approved rate increase | $ 1,900,000 | |
Approved rate increase (as a percent) | 8.60% | |
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 | 2018 and 2019 rates | ||
Public Utilities, General Disclosures [Line Items] | ||
Approved return on equity (as a percent) | 10.30% | |
Authorized Revenue Requirement For ReACT | $ 275,000,000 | |
WPS | Electric rates | 2020 rates | ||
Public Utilities, General Disclosures [Line Items] | ||
Approved rate increase | $ 15,800,000 | |
Approved rate increase (as a percent) | 1.60% | |
WPS | Electric rates | 2020 rates | Tax Cuts and Jobs Act of 2017 | ||
Public Utilities, General Disclosures [Line Items] | ||
Amortization of regulatory liabilities | $ 11,000,000 | |
WPS | Electric rates | 2021 rates | Tax Cuts and Jobs Act of 2017 | ||
Public Utilities, General Disclosures [Line Items] | ||
Amortization of regulatory liabilities | 39,000,000 | |
WPS | Electric rates | 2020 and 2021 rates | ||
Public Utilities, General Disclosures [Line Items] | ||
Cost of the ReACT project, excluding AFUDC | $ 342,000,000 | |
Collection of ReACT Regulatory Asset in Years | 8 years | |
WPS | Electric rates | 2020 and 2021 rates | Earnings sharing mechanisms | ||
Public Utilities, General Disclosures [Line Items] | ||
Amortization of regulatory liabilities | $ 21,000,000 | |
Amortization period | 2 years | |
WPS | Natural gas rates | 2020 rates | ||
Public Utilities, General Disclosures [Line Items] | ||
Approved rate increase | $ 4,300,000 | |
Approved rate increase (as a percent) | 1.40% | |
WPS | Natural gas rates | 2020 rates | Tax Cuts and Jobs Act of 2017 | ||
Public Utilities, General Disclosures [Line Items] | ||
Amortization of regulatory liabilities | $ 5,000,000 | |
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 | 2018 and 2019 rates | ||
Public Utilities, General Disclosures [Line Items] | ||
Approved return on equity (as a percent) | 10.00% | |
WG | Natural gas rates | 2020 rates | ||
Public Utilities, General Disclosures [Line Items] | ||
Approved rate increase | $ (1,500,000) | |
Approved rate increase (as a percent) | (0.20%) | |
WG | Natural gas rates | 2020 rates | Tax Cuts and Jobs Act of 2017 | ||
Public Utilities, General Disclosures [Line Items] | ||
Amortization of regulatory liabilities | $ 3,000,000 |
Regulatory Environment - WI 201
Regulatory Environment - WI 2018 and 2019 Rates (Details) - 2018 and 2019 rates - Public Service Commission of Wisconsin (PSCW) $ in Millions | 1 Months Ended | 12 Months Ended |
Sep. 30, 2017USD ($)utility | Dec. 31, 2019USD ($) | |
WE | ||
Public Utilities, General Disclosures [Line Items] | ||
Approved return on equity (as a percent) | 10.20% | |
Income statement impact of flow through of repair-related deferred tax liabilities | $ 0 | |
WG | ||
Public Utilities, General Disclosures [Line Items] | ||
Approved return on equity (as a percent) | 10.00% | |
WPS | ||
Public Utilities, General Disclosures [Line Items] | ||
Approved return on equity (as a percent) | 10.30% | |
Authorized Revenue Requirement For ReACT | $ 275 | |
WE, WG, and WPS | ||
Public Utilities, General Disclosures [Line Items] | ||
Number of utilities with earnings sharing mechanism | utility | 3 | |
Percentage of first 50 basis points of additional utility earnings shared with customers | 50.00% | |
Return on equity in excess of authorized amount (as a percent) | 0.50% |
Regulatory Environment - WI Liq
Regulatory Environment - WI Liquefied Natural Gas Facilities (Details) - Public Service Commission of Wisconsin (PSCW) - Liquefied Natural Gas Facilities $ in Millions | Nov. 01, 2019USD ($)Bcf |
WE | |
Public Utilities, General Disclosures [Line Items] | |
Natural gas supply | 1 |
WG | |
Public Utilities, General Disclosures [Line Items] | |
Natural gas supply | 1 |
WE and WE | |
Public Utilities, General Disclosures [Line Items] | |
Entity's estimated project costs | $ | $ 370 |
Regulatory Environment - WI Sol
Regulatory Environment - WI Solar Generation Projects (Details) - Public Service Commission of Wisconsin (PSCW) $ in Millions | Aug. 01, 2019USD ($)MW | May 31, 2018USD ($)solar_projectsMW |
WE | Badger Hollow Solar Farm II | ||
Public Utilities, General Disclosures [Line Items] | ||
Solar project output that approval was requested for from the PSCW (in megawatts) | 100 | |
Estimated share of cost for solar project(s) | $ | $ 130 | |
WE | Two Creeks Solar Farm [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Solar project output that approval was requested for from the PSCW (in megawatts) | 100 | |
WPS | Badger Hollow Solar Farm I | ||
Public Utilities, General Disclosures [Line Items] | ||
Solar project output that approval was requested for from the PSCW (in megawatts) | 100 | |
WPS | Badger Hollow Solar Farm I and Two Creeks Solar Project | ||
Public Utilities, General Disclosures [Line Items] | ||
Number of solar projects for which approval was requested | solar_projects | 2 | |
Solar project output that approval was requested for from the PSCW (in megawatts) | 200 | |
Estimated share of cost for solar project(s) | $ | $ 256 |
Regulatory Environment - Natura
Regulatory Environment - Natural Gas Storage Facility (Details) | 12 Months Ended |
Dec. 31, 2017 | |
Michigan Natural Gas Storage Facility [Member] | Public Service Commission of Wisconsin (PSCW) | WE, WG, and WPS | |
Public Utilities, General Disclosures [Line Items] | |
Natural gas storage needs provided to Wisconsin utilities | 33.33% |
Regulatory Environment - Acquis
Regulatory Environment - Acquisition of a Wind Energy Generation Facility in Wisconsin (Details) - Forward Wind Energy Center Acquisition - WPS | 1 Months Ended |
Oct. 31, 2017wind_turbinesutilityMW | |
Public Utilities, General Disclosures [Line Items] | |
Number Of Additional Utilities Purchased Forward Wind Energy Center | utility | 2 |
Wind Turbines Forward Energy Center | wind_turbines | 86 |
Capacity Forward Wind Energy Center | MW | 138 |
Regulatory Environment - PGL (D
Regulatory Environment - PGL (Details) - Illinois Commerce Commission (ICC) - PGL $ in Millions | Dec. 31, 2019Assurance | Jul. 31, 2019USD ($) |
Public Utilities, General Disclosures [Line Items] | ||
Rate base reduction from settlement of 2015 reconciliation | $ 7 | |
Total refunds required to ratepayers from settlement of 2015 reconciliation | $ 7.3 | |
Amount of assurance that PGL's QIP rider costs will be recoverable | Assurance | 0 |
Regulatory Environment - MERC (
Regulatory Environment - MERC (Details) - 2018 rates - Minnesota Public Utilities Commission (MPUC) - MERC - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended |
Dec. 31, 2018 | Dec. 31, 2019 | |
Public Utilities, General Disclosures [Line Items] | ||
Approved rate increase | $ 3.1 | |
Approved rate increase (as a percent) | 1.26% | |
Approved return on equity (as a percent) | 9.70% | |
Approved common equity component average (as a percent) | 50.90% | |
Interim rates refunded to customers | $ 8.2 |
Regulatory Environment - MGU a
Regulatory Environment - MGU and UMERC (Details) - UMERC $ in Millions | 1 Months Ended | 12 Months Ended |
Aug. 31, 2016MW | Dec. 31, 2019USD ($) | |
Public Utilities, General Disclosures [Line Items] | ||
Electric Power Purchase Agreement Term with Tilden | 20 years | |
Capacity of UMERC Generation | MW | 180 | |
Cost to Construct UMERC Generation | $ 242 | |
Cost to Construct UMERC Generation with AFUDC | $ 255 | |
Cost of Rice Units to be recovered from Utility Customers | 50.00% | |
Cost of Rice Units to be recovered from Tilden | 50.00% |
Other Income, Net (Details)
Other Income, Net (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Other Income and Expenses [Abstract] | |||
AFUDC – Equity | $ 14.4 | $ 15.2 | $ 11.4 |
Non-service components of net periodic benefit costs | 36.2 | 26 | 9.1 |
Gains (losses) from investments held in rabbi trust | 21.2 | (1.8) | 21.5 |
Other, net | 30.4 | 30.9 | 31.7 |
Other income, net | $ 102.2 | $ 70.3 | $ 73.7 |
Quarterly Financial Informati_3
Quarterly Financial Information (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Operating revenues | $ 1,947.5 | $ 1,608 | $ 1,590.2 | $ 2,377.4 | $ 2,076.8 | $ 1,643.7 | $ 1,672.5 | $ 2,286.5 | $ 7,523.1 | $ 7,679.5 | $ 7,648.5 |
Operating income | 363.1 | 310.9 | 314.6 | 542.8 | 289.8 | 302.7 | 330.8 | 545.1 | 1,531.4 | 1,468.4 | 1,776.1 |
Net income attributed to common shareholders | $ 243.9 | $ 234.3 | $ 235.7 | $ 420.1 | $ 205 | $ 233.2 | $ 231 | $ 390.1 | $ 1,134 | $ 1,059.3 | $ 1,203.7 |
Earnings Per Share, Basic | |||||||||||
Earnings per common share (basic) (in dollars per share) | $ 0.77 | $ 0.74 | $ 0.75 | $ 1.33 | $ 0.65 | $ 0.74 | $ 0.73 | $ 1.24 | $ 3.60 | $ 3.36 | $ 3.81 |
Earnings Per Share (Diluted) | |||||||||||
Earnings per common share (diluted) (in dollars per share) | $ 0.77 | $ 0.74 | $ 0.74 | $ 1.33 | $ 0.65 | $ 0.74 | $ 0.73 | $ 1.23 | $ 3.58 | $ 3.34 | $ 3.79 |
Schedule I - Income Statements
Schedule I - Income Statements (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Income statements | |||||||||||
Equity (loss) from equity method investment | $ 127.6 | $ 136.7 | $ 154.3 | ||||||||
Other income, net | 102.2 | 70.3 | 73.7 | ||||||||
Interest expense | 501.5 | 445.1 | 415.7 | ||||||||
Income before income taxes | 1,259.7 | 1,230.3 | 1,588.4 | ||||||||
Income tax benefit | (125) | (169.8) | (383.5) | ||||||||
Net income attributed to common shareholders | $ 243.9 | $ 234.3 | $ 235.7 | $ 420.1 | $ 205 | $ 233.2 | $ 231 | $ 390.1 | 1,134 | 1,059.3 | 1,203.7 |
WEC Energy Group | |||||||||||
Income statements | |||||||||||
Operating expenses | 4.7 | 5 | 6 | ||||||||
Equity (loss) from equity method investment | 1,210.5 | 1,108.3 | 1,234.7 | ||||||||
Other income, net | 6.3 | 6.8 | 2.1 | ||||||||
Interest expense | 122.3 | 104.1 | 82 | ||||||||
Income before income taxes | 1,089.8 | 1,006 | 1,148.8 | ||||||||
Income tax benefit | 44.2 | 53.3 | 54.9 | ||||||||
Net income attributed to common shareholders | $ 1,134 | $ 1,059.3 | $ 1,203.7 |
Schedule I - Statements of Comp
Schedule I - Statements of Comprehensive Income (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Statements of comprehensive income | |||||||||||
Net income attributed to common shareholders | $ 243.9 | $ 234.3 | $ 235.7 | $ 420.1 | $ 205 | $ 233.2 | $ 231 | $ 390.1 | $ 1,134 | $ 1,059.3 | $ 1,203.7 |
Other comprehensive loss, net of tax | (1.5) | (5.5) | 0 | ||||||||
Comprehensive income attributed to common shareholders | 1,132.5 | 1,053.8 | 1,203.7 | ||||||||
Derivatives accounted for as cash flow hedges | |||||||||||
Other comprehensive income (loss), net of tax | |||||||||||
Cumulative effect adjustment from adoption of ASU 2018-02 | 0 | 1.6 | 0 | 1.6 | 0 | ||||||
Derivatives accounted for as cash flow hedges | |||||||||||
Net derivative losses, net of tax benefits of $1.3, $0.8, and $0.0, respectively | (3.5) | (2.1) | 0 | ||||||||
Reclassification of net gains to net income, net of tax | (0.8) | (1.2) | (1.3) | ||||||||
Cash flow hedges, net | (4.3) | (1.7) | (1.3) | ||||||||
Defined benefit plans | |||||||||||
Other comprehensive income (loss), net of tax | |||||||||||
Cumulative effect adjustment from adoption of ASU 2018-02 | 0 | (1) | 0 | (1) | 0 | ||||||
Defined benefit plans | |||||||||||
Pension and OPEB adjustments arising during the period, net of tax | 2.6 | (3.1) | 0.9 | ||||||||
Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax | 0.2 | 0.3 | 0.4 | ||||||||
Defined benefit plans, net | (2.8) | 3.8 | (1.3) | ||||||||
WEC Energy Group | |||||||||||
Statements of comprehensive income | |||||||||||
Net income attributed to common shareholders | 1,134 | 1,059.3 | 1,203.7 | ||||||||
Other comprehensive income (loss) from subsidiaries, net of tax | 2.2 | (2.8) | 1.2 | ||||||||
Other comprehensive loss, net of tax | (1.5) | (5.5) | 0 | ||||||||
Comprehensive income attributed to common shareholders | 1,132.5 | 1,053.8 | 1,203.7 | ||||||||
WEC Energy Group | Derivatives accounted for as cash flow hedges | |||||||||||
Other comprehensive income (loss), net of tax | |||||||||||
Cumulative effect adjustment from adoption of ASU 2018-02 | 0 | 1.6 | 0 | 1.6 | 0 | ||||||
Derivatives accounted for as cash flow hedges | |||||||||||
Net derivative losses, net of tax benefits of $1.3, $0.8, and $0.0, respectively | (3.5) | (2.1) | 0 | ||||||||
Reclassification of net gains to net income, net of tax | (0.8) | (1.2) | (1.3) | ||||||||
Cash flow hedges, net | (4.3) | (1.7) | (1.3) | ||||||||
WEC Energy Group | Defined benefit plans | |||||||||||
Other comprehensive income (loss), net of tax | |||||||||||
Cumulative effect adjustment from adoption of ASU 2018-02 | $ 0 | $ (0.3) | 0 | (0.3) | 0 | ||||||
Defined benefit plans | |||||||||||
Pension and OPEB adjustments arising during the period, net of tax | 0.4 | (0.9) | (0.1) | ||||||||
Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax | 0.2 | 0.2 | 0.2 | ||||||||
Defined benefit plans, net | $ 0.6 | $ (1) | $ 0.1 |
Schedule I - Statements of Co_2
Schedule I - Statements of Comprehensive Income (Parentheticals) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Statements of comprehensive income | |||
Net derivative losses, tax benefits | $ 1.3 | $ 0.8 | $ 0 |
Schedule I - Balance Sheets (De
Schedule I - Balance Sheets (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Current assets | ||||
Cash and cash equivalents | $ 37.5 | $ 84.5 | $ 38.9 | |
Other | 68 | 77.2 | ||
Current assets | 2,093.6 | 2,247.6 | ||
Long-term assets | ||||
Other | 957.8 | 704.1 | ||
Long-term assets | 32,858.2 | 31,228.2 | ||
Total assets | 34,951.8 | 33,475.8 | 31,590.5 | |
Current liabilities | ||||
Short-term debt | 830.8 | 1,440.1 | ||
Current portion of long-term debt | 686.9 | 360.1 | ||
Other | 550.8 | 464.8 | ||
Current liabilities | 3,182.7 | 3,331.7 | ||
Long-term liabilities | ||||
Long-term debt | 11,171.4 | 9,975.6 | ||
Other | 1,128.9 | 1,108.1 | ||
Long-term liabilities | 21,514.5 | 20,301.4 | ||
Equity | ||||
Total liabilities and equity | 34,951.8 | 33,475.8 | ||
WEC Energy Group | ||||
Current assets | ||||
Cash and cash equivalents | 0.5 | 32.8 | $ 4 | $ 1.2 |
Accounts receivable from related parties | 0.7 | 4 | ||
Notes receivable from related parties | 22.5 | 71 | ||
Prepaid taxes | 46.5 | 0 | ||
Other | 0 | 0.6 | ||
Current assets | 70.2 | 108.4 | ||
Long-term assets | ||||
Investments in subsidiaries | 13,433.1 | 12,682.5 | ||
Notes receivable from UMERC | 0 | 150 | ||
Other | 23 | 31.8 | ||
Long-term assets | 13,456.1 | 12,864.3 | ||
Total assets | 13,526.3 | 12,972.7 | ||
Current liabilities | ||||
Short-term debt | 334.7 | 548.4 | ||
Current portion of long-term debt | 400 | 0 | ||
Accounts payable to related parties | 2.5 | 7.7 | ||
Notes payable to related parties | 489.3 | 398.9 | ||
Other | 17.9 | 14 | ||
Current liabilities | 1,244.4 | 969 | ||
Long-term liabilities | ||||
Long-term debt | 2,141.6 | 2,190.8 | ||
Other | 26.9 | 24 | ||
Long-term liabilities | 2,168.5 | 2,214.8 | ||
Equity | ||||
Common shareholders' equity | 10,113.4 | 9,788.9 | ||
Total liabilities and equity | $ 13,526.3 | $ 12,972.7 |
Schedule I - Statements of Cash
Schedule I - Statements of Cash Flows (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Operating activities | |||||||||||
Net income attributed to common shareholders | $ 243.9 | $ 234.3 | $ 235.7 | $ 420.1 | $ 205 | $ 233.2 | $ 231 | $ 390.1 | $ 1,134 | $ 1,059.3 | $ 1,203.7 |
Reconciliation to cash provided by operating activities | |||||||||||
Equity income in subsidiaries, net of distributions | (2.9) | (18.6) | (4.8) | ||||||||
Deferred income taxes | 167.7 | 300.1 | 274.4 | ||||||||
Change in - | |||||||||||
Other current liabilities | 78.7 | (67.6) | 161.8 | ||||||||
Other, net | 20.6 | 290.4 | (197.4) | ||||||||
Net cash provided by operating activities | 2,345.5 | 2,445.5 | 2,078.6 | ||||||||
Investing activities | |||||||||||
Acquisition of Bluewater | 0 | 0 | (226) | ||||||||
Capital contributions to subsidiaries | (52.6) | (53.5) | (109.6) | ||||||||
Other, net | 16.5 | 20.5 | 12 | ||||||||
Net cash used in investing activities | (2,494.9) | (2,384.4) | (2,254.1) | ||||||||
Financing activities | |||||||||||
Exercise of stock options | 67 | 29.1 | 30.8 | ||||||||
Purchase of common stock | (140.1) | (72.4) | (71.3) | ||||||||
Dividends paid on common stock | (744.5) | (697.3) | (656.5) | ||||||||
Issuance of long-term debt | 1,895 | 1,740 | 435 | ||||||||
Retirement of long-term debt | (360.1) | (953.3) | (154.5) | ||||||||
Other, net | (22.4) | (15.2) | (6.5) | ||||||||
Net cash provided by financing activities | 85.6 | 26.4 | 161.4 | ||||||||
Cash and cash equivalents at beginning of year | 84.5 | 38.9 | 84.5 | 38.9 | |||||||
Cash and cash equivalents at end of year | 37.5 | 84.5 | 37.5 | 84.5 | 38.9 | ||||||
WEC Energy Group | |||||||||||
Operating activities | |||||||||||
Net income attributed to common shareholders | 1,134 | 1,059.3 | 1,203.7 | ||||||||
Reconciliation to cash provided by operating activities | |||||||||||
Equity income in subsidiaries, net of distributions | (475.2) | (419.4) | (686.1) | ||||||||
Deferred income taxes | 9.1 | 14.4 | 89.5 | ||||||||
Change in - | |||||||||||
Accounts receivable from related parties | 3.3 | (2.1) | (0.1) | ||||||||
Prepaid taxes | (46.5) | 17.5 | 28.4 | ||||||||
Accounts payable to related parties | (5.2) | 4.6 | (0.5) | ||||||||
Other current liabilities | 1.5 | 4.7 | (1.4) | ||||||||
Other, net | 7 | 5.6 | 0.9 | ||||||||
Net cash provided by operating activities | 628 | 684.6 | 634.4 | ||||||||
Investing activities | |||||||||||
Acquisition of Bluewater | 0 | 0 | (226) | ||||||||
Capital contributions to subsidiaries | (602.3) | (448.7) | (173.4) | ||||||||
Return of capital from subsidiaries | 337.3 | 290.2 | 0 | ||||||||
Short-term notes receivable from related parties, net | 48.5 | (6.9) | 167.8 | ||||||||
Issuance of long-term notes receivable to UMERC | 0 | (100) | (50) | ||||||||
Redemption of long-term notes receivable from UMERC | 150 | 0 | 0 | ||||||||
Other, net | (0.6) | 6.4 | 4.5 | ||||||||
Net cash used in investing activities | (67.1) | (259) | (277.1) | ||||||||
Financing activities | |||||||||||
Exercise of stock options | 67 | 29.1 | 30.8 | ||||||||
Purchase of common stock | (140.1) | (72.4) | (71.3) | ||||||||
Dividends paid on common stock | (744.5) | (697.3) | (656.5) | ||||||||
Issuance of long-term debt | 350 | 600 | 0 | ||||||||
Retirement of long-term debt | 0 | (300) | 0 | ||||||||
Change in short-term debt | (213.7) | 53.6 | 173 | ||||||||
Short-term notes payable to related parties, net | 90.4 | (6.2) | 169.5 | ||||||||
Other, net | (2.3) | (3.6) | 0 | ||||||||
Net cash provided by financing activities | (593.2) | (396.8) | (354.5) | ||||||||
Net change in cash and cash equivalents | (32.3) | 28.8 | 2.8 | ||||||||
Cash and cash equivalents at beginning of year | $ 32.8 | $ 4 | 32.8 | 4 | 1.2 | ||||||
Cash and cash equivalents at end of year | $ 0.5 | $ 32.8 | $ 0.5 | $ 32.8 | $ 4 |
Schedule I - Cash Dividends Rec
Schedule I - Cash Dividends Received from Subsidiaries (Details) - WEC Energy Group - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Notes to parent company financial statements | |||
Cash dividends received from subsidiaries | $ 735.3 | $ 688.9 | $ 548.6 |
WE | |||
Notes to parent company financial statements | |||
Cash dividends received from subsidiaries | 360 | 310 | 240 |
We Power | |||
Notes to parent company financial statements | |||
Cash dividends received from subsidiaries | 192.5 | 223 | 181 |
ATC Holding LLC | |||
Notes to parent company financial statements | |||
Cash dividends received from subsidiaries | 87.4 | 105.8 | 82.6 |
WG | |||
Notes to parent company financial statements | |||
Cash dividends received from subsidiaries | 60 | 50 | 45 |
WECI | |||
Notes to parent company financial statements | |||
Cash dividends received from subsidiaries | 25.4 | 0 | 0 |
UMERC | |||
Notes to parent company financial statements | |||
Cash dividends received from subsidiaries | 10 | 0 | 0 |
Wisvest | |||
Notes to parent company financial statements | |||
Cash dividends received from subsidiaries | $ 0 | $ 0.1 | $ 0 |
Schedule I - Long-Term Debt (De
Schedule I - Long-Term Debt (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Future maturities of long-term debt outstanding | ||
2020 | $ 686.9 | |
2021 | 1,338.8 | |
2022 | 390.8 | |
2023 | 42.8 | |
2024 | 570 | |
Thereafter | 8,893.2 | |
Long-term debt | 11,171.4 | $ 9,975.6 |
WEC Energy Group | ||
Future maturities of long-term debt outstanding | ||
2020 | 400 | |
2021 | 600 | |
2022 | 350 | |
2023 | 0 | |
2024 | 0 | |
Thereafter | 1,200 | |
Total | 2,550 | |
Long-term debt | 2,141.6 | $ 2,190.8 |
WEC Energy Group | WECC | Support agreement related to WECC debt | ||
Future maturities of long-term debt outstanding | ||
Long-term debt | $ 50 |
Schedule I - Fair Value Measure
Schedule I - Fair Value Measurements (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Notes to parent company financial statements | ||
Long-term debt, including current portion | $ 11,858.3 | $ 10,335.7 |
Carrying amount | ||
Notes to parent company financial statements | ||
Long-term debt, including current portion | 11,858.3 | 10,335.7 |
Fair value | ||
Notes to parent company financial statements | ||
Long-term debt, including current portion | 13,035.9 | 10,554.9 |
WEC Energy Group | ||
Notes to parent company financial statements | ||
Long-term notes receivable from UMERC | 0 | 150 |
WEC Energy Group | Carrying amount | ||
Notes to parent company financial statements | ||
Long-term notes receivable from UMERC | 0 | 150 |
Long-term debt, including current portion | 2,541.6 | 2,190.8 |
WEC Energy Group | Fair value | ||
Notes to parent company financial statements | ||
Long-term notes receivable from UMERC | 0 | 145.5 |
Long-term debt, including current portion | $ 2,619.4 | $ 2,132.8 |
Schedule I - Supplemental Cash
Schedule I - Supplemental Cash Flow Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Notes to parent company financial statements | |||
Cash received for income taxes, net | $ 24.9 | $ (16.3) | $ 5.2 |
WEC Energy Group | |||
Notes to parent company financial statements | |||
Cash paid for interest | 117.7 | 102.9 | 82.5 |
Cash received for income taxes, net | (4.9) | (85.9) | (169.9) |
WEC Energy Group | Bluewater | |||
Notes to parent company financial statements | |||
Issuance of short-term note receivable | 0 | 0 | 115 |
WEC Energy Group | UMERC | |||
Notes to parent company financial statements | |||
Issuance of short-term note receivable | 0 | 0 | 40.5 |
WEC Energy Group | Wisvest | |||
Notes to parent company financial statements | |||
Settlement of short-term note payable | 0 | 0.9 | 0 |
WEC Energy Group | Bostco | |||
Notes to parent company financial statements | |||
Settlement of short-term note payable | $ 0 | $ 0 | $ 4.8 |
Schedule I - Short-Term Notes R
Schedule I - Short-Term Notes Receivable from Related Parties (Details) - WEC Energy Group - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Notes to parent company financial statements | ||
Short-term notes receivable from related parties | $ 22.5 | $ 71 |
Wispark | ||
Notes to parent company financial statements | ||
Short-term notes receivable from related parties | 13.5 | 28.5 |
UMERC | ||
Notes to parent company financial statements | ||
Short-term notes receivable from related parties | $ 9 | $ 42.5 |
Schedule I - Short-Term Notes P
Schedule I - Short-Term Notes Payable to Related Parties (Details) - WEC Energy Group - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Notes to parent company financial statements | ||
Short-term notes payable to related parties | $ 489.3 | $ 398.9 |
WBS | ||
Notes to parent company financial statements | ||
Short-term notes payable to related parties | 168.9 | 123.5 |
Integrys | ||
Notes to parent company financial statements | ||
Short-term notes payable to related parties | 166.9 | 139.5 |
WECC | ||
Notes to parent company financial statements | ||
Short-term notes payable to related parties | 111.7 | 110.3 |
Bluewater Gas Storage | ||
Notes to parent company financial statements | ||
Short-term notes payable to related parties | $ 41.8 | $ 25.6 |
Schedule II - Valuation and Q_2
Schedule II - Valuation and Qualifying Accounts (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Valuation and qualifying accounts | |||
Balance at beginning of period | $ 149.2 | $ 143.2 | $ 108 |
Expense | 85.8 | 94.7 | 96.7 |
Deferral | 11.4 | (5.5) | 16.4 |
Net write-offs | (106.4) | (83.2) | (77.9) |
Balance at end of period | $ 140 | $ 149.2 | $ 143.2 |