Item 1. FINANCIAL STATEMENTS

WEC ENERGY GROUP, INC.

CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited)						Three Months Ended												Nine Months Ended
			September 30												September 30
(in millions, except per share amounts)						2021						2020						2021						2020
Operating revenues						$	1,746.5					$	1,651.0					$	6,114.1					$	5,308.3
Operating expenses
Cost of sales						560.7						482.8						2,352.2						1,662.0
Other operation and maintenance						473.7						498.7						1,417.4						1,427.5
Depreciation and amortization						271.6						245.0						799.2						726.6
Property and revenue taxes						50.5						54.3						157.2						156.6
Total operating expenses						1,356.5						1,280.8						4,726.0						3,972.7
Operating income						390.0						370.2						1,388.1						1,335.6
Equity in earnings of transmission affiliates						42.3						40.1						126.2						132.8
Other income, net						25.2						25.7						97.7						59.9
Interest expense						118.0						122.0						357.5						375.8
Other expense						(50.5)						(56.2)						(133.6)						(183.1)
Income before income taxes						339.5						314.0						1,254.5						1,152.5
Income tax expense						50.8						46.9						179.8						190.7
Net income						288.7						267.1						1,074.7						961.8
Preferred stock dividends of subsidiary						0.3						0.3						0.9						0.9
Net loss attributed to noncontrolling interests						1.6						—						2.3						—
Net income attributed to common shareholders						$	290.0					$	266.8					$	1,076.1					$	960.9
Earnings per share
Basic						$	0.92					$	0.85					$	3.41					$	3.05
Diluted						$	0.92					$	0.84					$	3.40					$	3.04
Weighted average common shares outstanding
Basic						315.4						315.4						315.4						315.4
Diluted						316.3						316.5						316.3						316.6

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these financial statements.

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WEC ENERGY GROUP, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)						Three Months Ended												Nine Months Ended
			September 30												September 30
(in millions)						2021						2020						2021						2020
Net income						$	288.7					$	267.1					$	1,074.7					$	961.8
Other comprehensive income (loss), net of tax
Derivatives accounted for as cash flow hedges
Net derivative loss, net of tax benefit of $— , $—, $—, and $(1.6), respectively						—						—						—						(4.2)
Reclassification of realized net derivative loss to net income, net of tax expense of $0.5 , $0.4, $1.2, and $0.6, respectively						0.9						0.9						2.9						1.4
Cash flow hedges, net						0.9						0.9						2.9						(2.8)
Defined benefit plans
Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax						0.1						—						0.3						0.5
Other comprehensive income (loss), net of tax						1.0						0.9						3.2						(2.3)
Comprehensive income						289.7						268.0						1,077.9						959.5
Preferred stock dividends of subsidiary						0.3						0.3						0.9						0.9
Comprehensive loss attributed to noncontrolling interests						1.6						—						2.3						—
Comprehensive income attributed to common shareholders						$	291.0					$	267.7					$	1,079.3					$	958.6

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these financial statements.

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WEC ENERGY GROUP, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (in millions, except share and per share amounts)						September 30, 2021						December 31, 2020
Assets
Current assets
Cash and cash equivalents						$	26.0					$	24.8
Accounts receivable and unbilled revenues, net of reserves of $199.7 and $220.1, respectively						1,103.8						1,202.8
Materials, supplies, and inventories						645.7						528.6
Prepayments						195.7						263.4
Amounts recoverable from customers						139.4						20.0
Derivative assets						247.1						17.0
Other						51.2						26.4
Current assets						2,408.9						2,083.0
Long-term assets
Property, plant, and equipment, net of accumulated depreciation and amortization of $9,799.3 and $9,364.7, respectively						26,622.7						25,707.4
Regulatory assets (September 30, 2021 includes $102.9 related to WEPCo Environmental Trust)						3,488.7						3,524.1
Equity investment in transmission affiliates						1,791.3						1,764.3
Goodwill						3,052.8						3,052.8
Other						1,036.5						896.5
Long-term assets						35,992.0						34,945.1
Total assets						$	38,400.9					$	37,028.1
Liabilities and Equity
Current liabilities
Short-term debt						$	1,508.9					$	1,776.9
Current portion of long-term debt (September 30, 2021 includes $8.5 related to WEPCo Environmental Trust)						496.7						785.8
Accounts payable						872.8						880.7
Other						814.2						704.7
Current liabilities						3,692.6						4,148.1
Long-term liabilities
Long-term debt (September 30, 2021 includes $107.0 related to WEPCo Environmental Trust)						12,678.1						11,728.1
Deferred income taxes						4,295.8						4,059.8
Deferred revenue, net						394.9						412.2
Regulatory liabilities						4,131.2						3,928.1
Environmental remediation liabilities						510.3						532.9
Pension and OPEB obligations						307.8						327.0
Other						1,283.6						1,229.4
Long-term liabilities						23,601.7						22,217.5
Commitments and contingencies (Note 20)
Common shareholders' equity
Common stock – $0.01 par value; 325,000,000 shares authorized; 315,434,531 shares outstanding						3.2						3.2
Additional paid in capital						4,144.4						4,143.7
Retained earnings						6,764.5						6,329.6
Accumulated other comprehensive loss						(3.6)						(6.8)
Common shareholders' equity						10,908.5						10,469.7
Preferred stock of subsidiary						30.4						30.4
Noncontrolling interests						167.7						162.4
Total liabilities and equity						$	38,400.9					$	37,028.1

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these financial statements.

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WEC ENERGY GROUP, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)						Nine Months Ended
						September 30
(in millions)						2021						2020
Operating activities
Net income						$	1,074.7					$	961.8
Reconciliation to cash provided by operating activities
Depreciation and amortization						799.2						726.6
Deferred income taxes and ITCs, net						158.0						152.5
Contributions and payments related to pension and OPEB plans						(11.3)						(10.1)
Equity income in transmission affiliates, net of distributions						(27.0)						(20.3)
Change in –
Accounts receivable and unbilled revenues, net						162.4						262.3
Materials, supplies, and inventories						(117.1)						(23.6)
Prepayments						67.7						92.3
Amounts recoverable from customers						(119.4)						(1.3)
Other current assets						13.8						38.5
Accounts payable						(15.1)						(178.9)
Other current liabilities						107.5						(23.3)
Other, net						(86.7)						(26.8)
Net cash provided by operating activities						2,006.7						1,949.7
Investing activities
Capital expenditures						(1,627.9)						(1,618.7)
Acquisition of Jayhawk						(119.8)						—
Capital contributions to transmission affiliates						—						(15.2)
Proceeds from the sale of assets						21.6						9.8
Proceeds from the sale of investments held in rabbi trust						12.7						17.1
Insurance proceeds received for property damage						—						22.2
Other, net						24.7						21.7
Net cash used in investing activities						(1,688.7)						(1,563.1)
Financing activities
Exercise of stock options						6.5						23.3
Purchase of common stock						(15.7)						(56.7)
Dividends paid on common stock						(641.2)						(598.5)
Issuance of long-term debt						1,018.8						810.0
Retirement of long-term debt						(356.2)						(482.6)
Issuance of short-term loan						0.5						340.0
Repayment of short-term loan						(340.0)						—
Change in other short-term debt						71.5						(399.8)
Purchase of additional ownership interest in Upstream from noncontrolling interest						—						(31.0)
Other, net						(25.6)						(12.4)
Net cash used in financing activities						(281.4)						(407.7)
Net change in cash, cash equivalents, and restricted cash						36.6						(21.1)
Cash, cash equivalents, and restricted cash at beginning of period						72.6						82.3
Cash, cash equivalents, and restricted cash at end of period						$	109.2					$	61.2

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these financial statements.

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WEC ENERGY GROUP, INC.

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (Unaudited)
						WEC Energy Group Common Shareholders' Equity
(in millions, except per share amounts)						Common Stock						Additional Paid In Capital						Retained Earnings						Accumulated Other Comprehensive Loss						Total Common Shareholders' Equity						Preferred Stock of Subsidiary						Non-controlling Interests						Total Equity
Balance at December 31, 2020						$	3.2					$	4,143.7					$	6,329.6					$	(6.8)					$	10,469.7					$	30.4					$	162.4					$	10,662.5
Net income attributed to common shareholders						—						—						510.1						—						510.1						—						—						510.1
Net loss attributed to noncontrolling interests						—						—						—						—						—						—						(0.1)						(0.1)
Other comprehensive income						—						—						—						1.1						1.1						—						—						1.1
Common stock dividends of $0.6775 per share						—						—						(213.7)						—						(213.7)						—						—						(213.7)
Exercise of stock options						—						1.2						—						—						1.2						—						—						1.2
Purchase of common stock						—						(6.6)						—						—						(6.6)						—						—						(6.6)
Acquisition of a noncontrolling interest						—						—						—						—						—						—						6.2						6.2
Capital contributions from noncontrolling interest						—						—						—						—						—						—						2.0						2.0
Distributions to noncontrolling interests						—						—						—						—						—						—						(0.4)						(0.4)
Stock-based compensation and other						—						5.3						—						—						5.3						—						—						5.3
Balance at March 31, 2021						$	3.2					$	4,143.6					$	6,626.0					$	(5.7)					$	10,767.1					$	30.4					$	170.1					$	10,967.6
Net income attributed to common shareholders						—						—						276.0						—						276.0						—						—						276.0
Net loss attributed to noncontrolling interests						—						—						—						—						—						—						(0.6)						(0.6)
Other comprehensive income						—						—						—						1.1						1.1						—						—						1.1
Common stock dividends of $0.6775 per share						—						—						(213.8)						—						(213.8)						—						—						(213.8)
Exercise of stock options						—						2.8						—						—						2.8						—						—						2.8
Purchase of common stock						—						(4.7)						—						—						(4.7)						—						—						(4.7)
Capital contributions from noncontrolling interest						—						—						—						—						—						—						0.5						0.5
Distributions to noncontrolling interests						—						—						—						—						—						—						(0.9)						(0.9)
Stock-based compensation and other						—						2.4						—						—						2.4						—						—						2.4
Balance at June 30, 2021						$	3.2					$	4,144.1					$	6,688.2					$	(4.6)					$	10,830.9					$	30.4					$	169.1					$	11,030.4
Net income attributed to common shareholders						—						—						290.0						—						290.0						—						—						290.0
Net loss attributed to noncontrolling interests						—						—						—						—						—						—						(1.6)						(1.6)
Other comprehensive income						—						—						—						1.0						1.0						—						—						1.0
Common stock dividends of $0.6775 per share						—						—						(213.7)						—						(213.7)						—						—						(213.7)
Exercise of stock options						—						2.5						—						—						2.5						—						—						2.5
Purchase of common stock						—						(4.4)						—						—						(4.4)						—						—						(4.4)
Capital contributions from noncontrolling interest						—						—						—						—						—						—						2.2						2.2
Distributions to noncontrolling interests						—						—						—						—						—						—						(2.0)						(2.0)
Stock-based compensation and other						—						2.2						—						—						2.2						—						—						2.2
Balance at September 30, 2021						$	3.2					$	4,144.4					$	6,764.5					$	(3.6)					$	10,908.5					$	30.4					$	167.7					$	11,106.6

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CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (Unaudited) (continued)
						WEC Energy Group Common Shareholders' Equity
(in millions, except per share amounts)						Common Stock						Additional Paid In Capital						Retained Earnings						Accumulated Other Comprehensive Loss						Total Common Shareholders' Equity						Preferred Stock of Subsidiary						Non-controlling Interests						Total Equity
Balance at December 31, 2019						$	3.2					$	4,186.6					$	5,927.7					$	(4.1)					$	10,113.4					$	30.4					$	110.8					$	10,254.6
Net income attributed to common shareholders						—						—						452.5						—						452.5						—						—						452.5
Net loss attributed to noncontrolling interests						—						—						—						—						—						—						(0.2)						(0.2)
Other comprehensive loss						—						—						—						(3.0)						(3.0)						—						—						(3.0)
Common stock dividends of $0.6325 per share						—						—						(199.5)						—						(199.5)						—						—						(199.5)
Exercise of stock options						—						16.0						—						—						16.0						—						—						16.0
Purchase of common stock						—						(40.4)						—						—						(40.4)						—						—						(40.4)
Distributions to noncontrolling interests						—						—						—						—						—						—						(0.5)						(0.5)
Stock-based compensation and other						—						5.1						—						—						5.1						—						—						5.1
Balance at March 31, 2020						$	3.2					$	4,167.3					$	6,180.7					$	(7.1)					$	10,344.1					$	30.4					$	110.1					$	10,484.6
Net income attributed to common shareholders						—						—						241.6						—						241.6						—						—						241.6
Net income attributed to noncontrolling interests						—						—						—						—						—						—						0.2						0.2
Other comprehensive loss						—						—						—						(0.2)						(0.2)						—						—						(0.2)
Common stock dividends of $0.6325 per share						—						—						(199.5)						—						(199.5)						—						—						(199.5)
Exercise of stock options						—						4.3						—						—						4.3						—						—						4.3
Purchase of common stock						—						(9.9)						—						—						(9.9)						—						—						(9.9)
Purchase of additional ownership interest in Upstream from noncontrolling interest						—						—						—						—						—						—						(31.0)						(31.0)
Distributions to noncontrolling interests						—						—						—						—						—						—						(0.7)						(0.7)
Stock-based compensation and other						—						3.3						—						—						3.3						—						—						3.3
Balance at June 30, 2020						$	3.2					$	4,165.0					$	6,222.8					$	(7.3)					$	10,383.7					$	30.4					$	78.6					$	10,492.7
Net income attributed to common shareholders						—						—						266.8						—						266.8						—						—						266.8
Other comprehensive income						—						—						—						0.9						0.9						—						—						0.9
Common stock dividends of $0.6325 per share						—						—						(199.5)						—						(199.5)						—						—						(199.5)
Exercise of stock options						—						3.0						—						—						3.0						—						—						3.0
Purchase of common stock						—						(6.4)						—						—						(6.4)						—						—						(6.4)
Distributions to noncontrolling interests						—						—						—						—						—						—						(0.6)						(0.6)
Stock-based compensation and other						—						2.2						—						—						2.2						—						—						2.2
Balance at September 30, 2020						$	3.2					$	4,163.8					$	6,290.1					$	(6.4)					$	10,450.7					$	30.4					$	78.0					$	10,559.1

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these financial statements.

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WEC ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

September 30, 2021

NOTE 1—GENERAL INFORMATION

WEC Energy Group serves approximately 1.6 million electric customers and 3.0 million natural gas customers, owns approximately 60% of ATC, and owns majority interests in multiple wind generating facilities as part of its non-utility energy infrastructure business.

As used in these notes, the term "financial statements" refers to the condensed consolidated financial statements. This includes the income statements, statements of comprehensive income, balance sheets, statements of cash flows, and statements of equity, unless otherwise noted. In this report, when we refer to "the Company," "us," "we," "our," or "ours," we are referring to WEC Energy Group and all of its subsidiaries.

On our financial statements, we consolidate our majority-owned subsidiaries, which we control, and VIEs, of which we are the primary beneficiary. We reflect noncontrolling interests for the portion of entities that we do not own as a component of consolidated equity separate from the equity attributable to our shareholders. The noncontrolling interests that we reported as equity on our balance sheets related to the minority interests at Bishop Hill III, Blooming Grove, Coyote Ridge, Jayhawk, Tatanka Ridge, and Upstream held by third parties.

We use the equity method to account for investments in companies we do not control but over which we exercise significant influence regarding their operating and financial policies. As a result of our limited voting rights, we account for ATC and ATC Holdco as equity method investments. See Note 17, Investment in Transmission Affiliates, for more information.

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2020. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three and nine months ended September 30, 2021, are not necessarily indicative of expected results for 2021 due to seasonal variations and other factors, including any continuing financial impacts from the COVID-19 pandemic.

In management's opinion, we have included all adjustments, normal and recurring in nature, necessary for a fair presentation of our financial results.

NOTE 2—ACQUISITIONS

The purchase price of certain acquisitions below includes intangibles recorded as long-term liabilities related to PPAs and interconnection agreements. See Note 16, Goodwill and Intangibles, for more information.

Acquisition of a Wind Energy Generation Facility in Illinois

In June 2021, WECI signed an agreement to acquire a 90% ownership interest in Sapphire Sky, a 250 MW wind generating facility under construction in McLean County, Illinois, for approximately $412 million. The project has an offtake agreement with an unaffiliated third party for all of the energy to be produced by the facility for a period of 12 years. WECI's investment in Sapphire Sky is expected to qualify for PTCs. The transaction is subject to FERC approval and commercial operation is expected to begin by the end of 2022, at which time the transaction is expected to close. Sapphire Sky will be included in the non-utility energy infrastructure segment.

Acquisition of a Wind Energy Generation Facility in Kansas

In February 2021, WECI completed the acquisition of a 90% ownership interest in Jayhawk, a 190 MW wind generating facility under construction in Bourbon and Crawford counties, Kansas, for $119.8 million, which included transaction costs, and was allocated primarily to property, plant, and equipment. As of September 30, 2021, WECI incurred an additional $88.3 million of capital expenditures for the project for a total investment of $208.1 million. Upon completion, we expect WECI's total investment to be

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approximately $302 million. The project has an offtake agreement with an unaffiliated third party for all of the energy to be produced by the facility for a period of 10 years. WECI's investment in Jayhawk is expected to qualify for PTCs. WECI is entitled to 99% of the tax benefits related to this facility for the first 10 years of commercial operation, after which we will be entitled to tax benefits equal to our ownership interest. Commercial operation is expected to begin no later than the first quarter of 2022. Jayhawk is included in the non-utility energy infrastructure segment.

Acquisition of a Wind Energy Generation Facility in South Dakota

In December 2020, WECI completed the acquisition of an 85% ownership interest in Tatanka Ridge, a 155 MW wind generating facility in Deuel County, South Dakota that became commercially operational in January 2021. WECI's total investment was $240.1 million, which included transaction costs. Tatanka Ridge has offtake agreements for all the energy produced with an affiliate of an investment grade multinational company for 12 years and a well-established electric cooperative that serves utilities in multiple states for 10 years. WECI's investment in Tatanka Ridge qualifies for PTCs. WECI is entitled to 99% of the tax benefits related to this facility for the first 11 years of commercial operation, after which we will be entitled to tax benefits equal to our ownership interest. Tatanka Ridge is included in the non-utility energy infrastructure segment.

Acquisition of Wind Generation Facilities in Nebraska

In August 2019, WECI signed an agreement to acquire an 80% ownership interest in Thunderhead, a 300 MW wind generating facility under construction in Antelope and Wheeler counties in Nebraska, for a total investment of approximately $338 million. In February 2020, WECI agreed to acquire an additional 10% ownership interest in Thunderhead for $43 million. The project has an offtake agreement for all of the energy to be produced by the facility for 12 years. WECI's investment in Thunderhead is expected to qualify for PTCs. The transaction was approved by FERC in April 2020, and commercial operation was initially expected to begin by the end of 2020. However, due to a delay in construction of the required substation, Thunderhead is now expected to begin commercial operation during the first half of 2022. The transaction is expected to close upon commercial operation. Thunderhead will be included in the non-utility energy infrastructure segment.

In April 2020, WECI acquired an additional 10% ownership interest in Upstream for $31.0 million, bringing its total ownership interest to 90%. Upstream is located in Antelope County, Nebraska and supplies energy to the Southwest Power Pool. Upstream's revenue is substantially fixed over the first 10 years through an agreement with an unaffiliated third party. WECI's investment in Upstream qualifies for PTCs. Upstream is included in the non-utility energy infrastructure segment.

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NOTE 3—OPERATING REVENUES

For more information about our operating revenues, see Note 1(d), Operating Revenues, in our 2020 Annual Report on Form 10-K.

Disaggregation of Operating Revenues

The following tables present our operating revenues disaggregated by revenue source. We do not have any revenues associated with our electric transmission segment, which includes investments accounted for using the equity method. We disaggregate revenues into categories that depict how the nature, amount, timing, and uncertainty of revenues and cash flows are affected by economic factors. For our segments, revenues are further disaggregated by electric and natural gas operations and then by customer class. Each customer class within our electric and natural gas operations have different expectations of service, energy and demand requirements, and can be impacted differently by regulatory activities within their jurisdictions.

(in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Non-Utility Energy Infrastructure						Corporate and Other						Reconciling Eliminations						WEC Energy Group Consolidated
Three Months Ended September 30, 2021
Electric						$	1,284.6					$	—					$	—					$	1,284.6					$	—					$	—					$	—					$	1,284.6
Natural gas						169.0						208.3						48.1						425.4						9.7						—						(9.1)						426.0
Total regulated revenues						1,453.6						208.3						48.1						1,710.0						9.7						—						(9.1)						1,710.6
Other non-utility revenues						—						—						4.3						4.3						19.7						—						(1.6)						22.4
Total revenues from contracts with customers						1,453.6						208.3						52.4						1,714.3						29.4						—						(10.7)						1,733.0
Other operating revenues						5.0						7.9						0.4						13.3						100.1						0.2						(100.1)			(1)			13.5
Total operating revenues						$	1,458.6					$	216.2					$	52.8					$	1,727.6					$	129.5					$	0.2					$	(110.8)					$	1,746.5

(in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Non-Utility Energy Infrastructure						Corporate and Other						Reconciling Eliminations						WEC Energy Group Consolidated
Three Months Ended September 30, 2020
Electric						$	1,212.9					$	—					$	—					$	1,212.9					$	—					$	—					$	—					$	1,212.9
Natural gas						150.5						213.4						43.1						407.0						9.1						—						(8.3)						407.8
Total regulated revenues						1,363.4						213.4						43.1						1,619.9						9.1						—						(8.3)						1,620.7
Other non-utility revenues						—						0.1						4.2						4.3						14.7						0.5						(1.6)						17.9
Total revenues from contracts with customers						1,363.4						213.5						47.3						1,624.2						23.8						0.5						(9.9)						1,638.6
Other operating revenues						2.9						8.4						1.0						12.3						99.7						0.1						(99.7)			(1)			12.4
Total operating revenues						$	1,366.3					$	221.9					$	48.3					$	1,636.5					$	123.5					$	0.6					$	(109.6)					$	1,651.0

(in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Non-Utility Energy Infrastructure						Corporate and Other						Reconciling Eliminations						WEC Energy Group Consolidated
Nine Months Ended September 30, 2021
Electric						$	3,462.8					$	—					$	—					$	3,462.8					$	—					$	—					$	—					$	3,462.8
Natural gas						1,009.0						1,167.9						340.6						2,517.5						33.7						—						(31.1)						2,520.1
Total regulated revenues						4,471.8						1,167.9						340.6						5,980.3						33.7						—						(31.1)						5,982.9
Other non-utility revenues						—						—						13.4						13.4						67.1						—						(7.1)						73.4
Total revenues from contracts with customers						4,471.8						1,167.9						354.0						5,993.7						100.8						—						(38.2)						6,056.3
Other operating revenues						26.0						27.2						4.2						57.4						299.8						0.4						(299.8)			(1)			57.8
Total operating revenues						$	4,497.8					$	1,195.1					$	358.2					$	6,051.1					$	400.6					$	0.4					$	(338.0)					$	6,114.1

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(in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Non-Utility Energy Infrastructure						Corporate and Other						Reconciling Eliminations						WEC Energy Group Consolidated
Nine Months Ended September 30, 2020
Electric						$	3,247.1					$	—					$	—					$	3,247.1					$	—					$	—					$	—					$	3,247.1
Natural gas						817.2						901.5						245.3						1,964.0						32.3						—						(30.6)						1,965.7
Total regulated revenues						4,064.3						901.5						245.3						5,211.1						32.3						—						(30.6)						5,212.8
Other non-utility revenues						—						0.1						12.8						12.9						48.2						1.7						(7.1)						55.7
Total revenues from contracts with customers						4,064.3						901.6						258.1						5,224.0						80.5						1.7						(37.7)						5,268.5
Other operating revenues						7.1						29.1						3.3						39.5						297.9						0.3						(297.9)			(1)			39.8
Total operating revenues						$	4,071.4					$	930.7					$	261.4					$	5,263.5					$	378.4					$	2.0					$	(335.6)					$	5,308.3

(1)Amounts eliminated represent lease revenues related to certain plants that We Power leases to WE to supply electricity to its customers. Lease payments are billed from We Power to WE and then recovered in WE's rates as authorized by the PSCW and the FERC. WE operates the plants and is authorized by the PSCW and Wisconsin state law to fully recover prudently incurred operating and maintenance costs in electric rates.

Revenues from Contracts with Customers

Electric Utility Operating Revenues

The following table disaggregates electric utility operating revenues into customer class:

						Three Months Ended September 30												Nine Months Ended September 30
(in millions)						2021						2020						2021						2020
Residential						$	512.2					$	500.8					$	1,354.9					$	1,324.4
Small commercial and industrial						396.9						373.6						1,074.9						1,004.3
Large commercial and industrial						271.9						244.0						705.9						626.4
Other						7.0						6.9						21.7						21.1
Total retail revenues						1,188.0						1,125.3						3,157.4						2,976.2
Wholesale						41.1						46.5						119.4						129.9
Resale						45.0						33.7						145.1						107.3
Steam						2.7						2.5						21.7						15.0
Other utility revenues						7.8						4.9						19.2						18.7
Total electric utility operating revenues						$	1,284.6					$	1,212.9					$	3,462.8					$	3,247.1

Natural Gas Utility Operating Revenues

The following tables disaggregate natural gas utility operating revenues into customer class:

(in millions)						Wisconsin						Illinois						Other States						Total Natural Gas Utility Operating Revenues
Three Months Ended September 30, 2021
Residential						$	89.4					$	146.5					$	23.7					$	259.6
Commercial and industrial						45.4						40.7						14.6						100.7
Total retail revenues						134.8						187.2						38.3						360.3
Transportation						16.1						43.4						6.0						65.5
Other utility revenues (1)						18.1						(22.3)						3.8						(0.4)
Total natural gas utility operating revenues						$	169.0					$	208.3					$	48.1					$	425.4

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(in millions)						Wisconsin						Illinois						Other States						Total Natural Gas Utility Operating Revenues
Three Months Ended September 30, 2020
Residential						$	74.6					$	128.6					$	18.8					$	222.0
Commercial and industrial						28.3						28.6						10.2						67.1
Total retail revenues						102.9						157.2						29.0						289.1
Transportation						15.7						40.0						5.3						61.0
Other utility revenues (1)						31.9						16.2						8.8						56.9
Total natural gas utility operating revenues						$	150.5					$	213.4					$	43.1					$	407.0

(in millions)						Wisconsin						Illinois						Other States						Total Natural Gas Utility Operating Revenues
Nine Months Ended September 30, 2021
Residential						$	625.6					$	679.5					$	149.5					$	1,454.6
Commercial and industrial						312.0						194.9						75.8						582.7
Total retail revenues						937.6						874.4						225.3						2,037.3
Transportation						58.3						166.4						23.6						248.3
Other utility revenues (1)						13.1						127.1						91.7						231.9
Total natural gas utility operating revenues						$	1,009.0					$	1,167.9					$	340.6					$	2,517.5

(in millions)						Wisconsin						Illinois						Other States						Total Natural Gas Utility Operating Revenues
Nine Months Ended September 30, 2020
Residential						$	513.5					$	568.9					$	154.1					$	1,236.5
Commercial and industrial						226.6						156.5						78.5						461.6
Total retail revenues						740.1						725.4						232.6						1,698.1
Transportation						56.8						159.0						22.8						238.6
Other utility revenues (1)						20.3						17.1						(10.1)						27.3
Total natural gas utility operating revenues						$	817.2					$	901.5					$	245.3					$	1,964.0

(1)Includes the revenues subject to the purchased gas recovery mechanisms of our utilities. The amounts for the nine months ended September 30, 2021 reflect the higher natural gas costs that were incurred as a result of the extreme winter weather conditions in February 2021. As these amounts are billed to customers, they are reflected in retail revenues with an offsetting decrease in other utility revenues. See Note 22, Regulatory Environment, for more information. In addition to costs related to the extreme weather event, we incurred higher natural gas costs throughout the nine months ended September 30, 2021, compared with the same period in 2020, as a result of an increase in the price of natural gas.

Other Natural Gas Operating Revenues

We have other natural gas operating revenues from Bluewater, which is in our non-utility energy infrastructure segment. Bluewater has entered into long-term service agreements for natural gas storage services with WE, WPS, and WG, and also provides limited service to unaffiliated customers. All amounts associated with the service agreements with WE, WPS, and WG have been eliminated at the consolidated level.

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Other Non-Utility Operating Revenues

Other non-utility operating revenues consist primarily of the following:

						Three Months Ended September 30												Nine Months Ended September 30
(in millions)						2021						2020						2021						2020
Wind generation revenues						$	12.2					$	7.4					$	42.5					$	24.0
We Power revenues (1)						5.9						5.8						17.5						17.1
Appliance service revenues						4.3						4.2						13.4						12.8
Other						—						0.5						—						1.8
Total other non-utility operating revenues						$	22.4					$	17.9					$	73.4					$	55.7

(1)As part of the construction of the We Power electric generating units, we capitalized interest during construction, which is included in property, plant, and equipment. As allowed by the PSCW, we collected these carrying costs from WE's utility customers during construction. The equity portion of these carrying costs was recorded as a contract liability, which is presented as deferred revenue, net on our balance sheets. We continually amortize the deferred carrying costs to revenues over the related lease term that We Power has with WE.

Other Operating Revenues

Other operating revenues consist primarily of the following:

						Three Months Ended September 30												Nine Months Ended September 30
(in millions)						2021						2020						2021						2020
Late payment charges (1)						$	11.9					$	6.0					$	44.2					$	18.1
Alternative revenues						0.9						5.4						10.0						18.2
Other						0.7						1.0						3.6						3.5
Total other operating revenues						$	13.5					$	12.4					$	57.8					$	39.8

(1)The increase in late payment charges during the three and nine months ended September 30, 2021, compared with the same periods in 2020, was a result of the expiration of various regulatory orders from our utility commissions in response to the COVID-19 pandemic, which included the suspension of late payment charges during a designated time period. See Note 22, Regulatory Environment, for more information.

NOTE 4—CREDIT LOSSES

Our exposure to credit losses is related to our accounts receivable and unbilled revenue balances, which are primarily generated from the sale of electricity and natural gas by our regulated utility operations. Credit losses associated with our utility operations are analyzed at the reportable segment level as we believe contract terms, political and economic risks, and the regulatory environment are similar at this level as our reportable segments are generally based on the geographic location of the underlying utility operations.

We have an accounts receivable and unbilled revenue balance associated with our non-utility energy infrastructure segment, related to the sale of electricity from our majority-owned wind generating facilities through agreements with several large high credit quality counterparties.

We evaluate the collectability of our accounts receivable and unbilled revenue balances considering a combination of factors. For some of our larger customers and also in circumstances where we become aware of a specific customer's inability to meet its financial obligations to us, we record a specific allowance for credit losses against amounts due in order to reduce the net recognized receivable to the amount we reasonably believe will be collected. For all other customers, we use the accounts receivable aging method to calculate an allowance for credit losses. Using this method, we classify accounts receivable into different aging buckets and calculate a reserve percentage for each aging bucket based upon historical loss rates. The calculated reserve percentages are updated on at least an annual basis, in order to ensure recent macroeconomic, political, and regulatory trends are captured in the calculation, to the extent possible. Risks identified that we do not believe are reflected in the calculated reserve percentages, are assessed on a quarterly basis to determine whether further adjustments are required.

We monitor our ongoing credit exposure through active review of counterparty accounts receivable balances against contract terms and due dates. Our activities include timely account reconciliation, dispute resolution and payment confirmation. To the extent possible, we work with customers with past due balances to negotiate payment plans, but will disconnect customers for non-payment as allowed by our regulators, if necessary, and employ collection agencies and legal counsel to pursue recovery of

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defaulted receivables. For our larger customers, detailed credit review procedures may be performed in advance of any sales being made. We sometimes require letters of credit, parental guarantees, prepayments or other forms of credit assurance from our larger customers to mitigate credit risk. See Note 22, Regulatory Environment, for information on certain regulatory actions that were and/or are being taken for the purpose of ensuring that essential utility services are available to our customers during the COVID-19 pandemic.

We have included tables below that show our gross third-party receivable balances and the related allowance for credit losses at September 30, 2021 and December 31, 2020, by reportable segment.

(in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Non-Utility Energy Infrastructure						Corporate and Other						WEC Energy Group Consolidated
September 30, 2021
Accounts receivable and unbilled revenues						$	927.9					$	316.6					$	45.2					$	1,289.7					$	9.4					$	4.4					$	1,303.5
Allowance for credit losses						76.4						114.7						8.6						199.7						—						—						199.7
Accounts receivable and unbilled revenues, net (1)						$	851.5					$	201.9					$	36.6					$	1,090.0					$	9.4					$	4.4					$	1,103.8
Total accounts receivable, net – past due greater than 90 days (1)						$	51.9					$	26.4					$	8.9					$	87.2					$	—					$	—					$	87.2
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)						96.5		%				100.0		%				—		%				87.7		%				—		%				—		%				87.7		%

(in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Non-Utility Energy Infrastructure						Corporate and Other						WEC Energy Group Consolidated
December 31, 2020
Accounts receivable and unbilled revenues						$	899.8					$	393.9					$	79.8					$	1,373.5					$	45.0					$	4.4					$	1,422.9
Allowance for credit losses						102.1						111.6						6.4						220.1						—						—						220.1
Accounts receivable and unbilled revenues, net (1)						$	797.7					$	282.3					$	73.4					$	1,153.4					$	45.0					$	4.4					$	1,202.8
Total accounts receivable, net – past due greater than 90 days (1)						$	84.8					$	34.5					$	3.5					$	122.8					$	—					$	—					$	122.8
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)						97.6		%				100.0		%				—		%				95.5		%				—		%				—		%				95.5		%

(1)Our exposure to credit losses for certain regulated utility customers is mitigated by regulatory mechanisms we have in place. Specifically, rates related to all of the customers in our Illinois segment, as well as the residential rates of WE, WPS, and WG in our Wisconsin segment, include riders or other mechanisms for cost recovery or refund of uncollectible expense based on the difference between the actual provision for credit losses and the amounts recovered in rates. As a result, at September 30, 2021, $527.5 million, or 47.8%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses. In addition, we have received specific orders related to the deferral of certain costs (including credit losses) incurred as a result of the COVID-19 pandemic. The additional protections related to our accounts receivable and unbilled revenue balances provided by these orders are subject to prudency reviews and are still being assessed. They are not reflected in the percentages in the above table or this note. See Note 22, Regulatory Environment, for more information on these orders.

A rollforward of the allowance for credit losses by reportable segment for the three and nine months ended September 30, 2021 and 2020 is included below:

Three Months Ended September 30, 2021 (in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Corporate and Other						WEC Energy Group Consolidated
Balance at June 30, 2021						$	114.4					$	109.0					$	8.3					$	231.7					$	—					$	231.7
Provision for credit losses						10.7						4.4						0.8						15.9						—						15.9
Provision for credit losses deferred for future recovery or refund						(38.2)						26.5						—						(11.7)						—						(11.7)
Write-offs charged against the allowance						(16.2)						(29.9)						(0.7)						(46.8)						—						(46.8)
Recoveries of amounts previously written off						5.7						4.7						0.2						10.6						—						10.6
Balance at September 30, 2021						$	76.4					$	114.7					$	8.6					$	199.7					$	—					$	199.7

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Nine Months Ended September 30, 2021 (in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Corporate and Other						WEC Energy Group Consolidated
Balance at December 31, 2020						$	102.1					$	111.6					$	6.4					$	220.1					$	—					$	220.1
Provision for credit losses						33.8						16.7						3.1						53.6						—						53.6
Provision for credit losses deferred for future recovery or refund						(28.1)						10.7						—						(17.4)						—						(17.4)
Write-offs charged against the allowance						(51.2)						(36.7)						(1.8)						(89.7)						—						(89.7)
Recoveries of amounts previously written off						19.8						12.4						0.9						33.1						—						33.1
Balance at September 30, 2021						$	76.4					$	114.7					$	8.6					$	199.7					$	—					$	199.7

In total, the allowance for credit losses decreased over both the three and nine month periods ended September 30, 2021. The allowance for credit losses related to our Wisconsin segment decreased, as normal collection practices began in April 2021 for our Wisconsin Utilities, earlier than in our other service territories. Normal collection practices in our Illinois and Other States segments didn't begin until June 30, 2021 and August 2, 2021, respectively. As a result, we continued to see an increase in the allowance for credit losses in these service territories through September 30, 2021, but expect that the allowance for credit losses will decrease as we continue to ramp up our collection efforts. See Note 22, Regulatory Environment, for more information on the impact that the COVID-19 pandemic has had on our allowed collection practices.

Three Months Ended September 30, 2020 (in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Corporate and Other						WEC Energy Group Consolidated
Balance at June 30, 2020						$	77.9					$	82.7					$	4.0					$	164.6					$	0.1					$	164.7
Provision for credit losses						14.8						6.3						1.0						22.1						0.1						22.2
Provision for credit losses deferred for future recovery or refund						2.5						(3.2)						—						(0.7)						—						(0.7)
Write-offs charged against the allowance						(14.5)						(10.0)						(0.9)						(25.4)						—						(25.4)
Recoveries of amounts previously written off						7.8						4.4						0.3						12.5						—						12.5
Balance at September 30, 2020						$	88.5					$	80.2					$	4.4					$	173.1					$	0.2					$	173.3

Nine Months Ended September 30, 2020 (in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Corporate and Other						WEC Energy Group Consolidated
Balance at December 31, 2019						$	59.9					$	75.9					$	4.1					$	139.9					$	0.1					$	140.0
Provision for credit losses						40.8						28.3						2.1						71.2						0.1						71.3
Provision for credit losses deferred for future recovery or refund						11.6						22.4						—						34.0						—						34.0
Write-offs charged against the allowance						(52.2)						(59.5)						(2.9)						(114.6)						—						(114.6)
Recoveries of amounts previously written off						28.4						13.1						1.1						42.6						—						42.6
Balance at September 30, 2020						$	88.5					$	80.2					$	4.4					$	173.1					$	0.2					$	173.3

The increase in the allowance for credit losses at our Wisconsin and Illinois reportable segments was driven by an increase in past due accounts receivable balances from December 31, 2019 to September 30, 2020. This is a trend we generally see over the winter moratorium months, when we are not allowed to disconnect customer service as a result of non-payment. In Wisconsin, the winter moratorium begins on November 1 and ends on April 15, and in Illinois the winter moratorium begins on December 1 and ends on March 31. However, as a result of the COVID-19 pandemic and related regulatory orders we received, we were also unable to disconnect any of our Wisconsin and Illinois customers during the second and third quarters of 2020.

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NOTE 5—REGULATORY ASSETS AND LIABILITIES

The following regulatory assets and liabilities were reflected on our balance sheets at September 30, 2021 and December 31, 2020. For more information on our regulatory assets and liabilities, see Note 6, Regulatory Assets and Liabilities, in our 2020 Annual Report on Form 10-K.

(in millions)						September 30, 2021						December 31, 2020
Regulatory assets
Pension and OPEB costs						$	1,019.1					$	1,101.6
Plant retirements						726.5						740.8
Environmental remediation costs						601.9						638.2
Income tax related items						459.3						454.6
Asset retirement obligations						208.9						181.3
SSR						131.6						135.6
Energy costs recoverable through rate adjustments (1)						125.9						1.1
Securitization (2)						102.9						105.2
MERC extraordinary natural gas costs (3)						64.7						—
Uncollectible expense						55.7						82.0
Derivatives						25.9						26.5
Other, net						105.7						77.2
Total regulatory assets						$	3,628.1					$	3,544.1
Balance sheet presentation
Amounts recoverable from customers (1)						$	139.4					$	20.0
Regulatory assets						3,488.7						3,524.1
Total regulatory assets						$	3,628.1					$	3,544.1

(1)The increase in these regulatory assets primarily relates to the high natural gas costs that were incurred as a result of the extreme winter weather conditions in February 2021. See Note 22, Regulatory Environment, for more information.

(2)See Note 19, Variable Interest Entities, for more information.

(3)This regulatory asset relates to the extraordinary natural gas costs MERC incurred during February 2021 that are being recovered over 27 months, beginning in September 2021. See Note 22, Regulatory Environment, for more information.

(in millions)						September 30, 2021						December 31, 2020
Regulatory liabilities
Income tax related items						$	2,030.1					$	2,137.7
Removal costs						1,244.5						1,221.1
Pension and OPEB benefits						366.3						378.1
Derivatives (1)						298.7						16.4
Electric transmission costs						83.5						78.5
Uncollectible expense						47.2						25.5
Earnings sharing mechanisms						25.2						36.9
Energy costs refundable through rate adjustments						5.5						59.9
Other, net						36.9						25.0
Total regulatory liabilities						$	4,137.9					$	3,979.1
Balance sheet presentation
Other current liabilities						$	6.7					$	51.0
Regulatory liabilities						4,131.2						3,928.1
Total regulatory liabilities						$	4,137.9					$	3,979.1

(1) For most energy-related physical and financial contracts that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities. See Note 13, Derivative Instruments, for more information.

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NOTE 6—PROPERTY, PLANT, AND EQUIPMENT

Wisconsin Segment Plant to be Retired

Columbia Units 1 and 2

As a result of a MISO ruling received in June 2021, retirement of the jointly-owned Columbia generating units 1 and 2 became probable. Columbia generating units 1 and 2 are expected to be retired by the end of 2023 and 2024, respectively. The net book value of WPS's ownership share of these generating units was $279.3 million at September 30, 2021. This amount was classified as plant to be retired within property, plant, and equipment on our balance sheet. These units are included in rate base, and WPS continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW.

Public Service Building

During a significant rain event in May 2020, an underground steam tunnel in downtown Milwaukee flooded and steam vented into WE’s PSB. The damage to the building from the flooding and steam was extensive and requires significant repairs and restorations. As of September 30, 2021, WE had incurred $93.5 million of costs related to these repairs and restorations. WE received $20.0 million of insurance proceeds in 2020 to cover a portion of these costs and $61.0 million was recorded in accounts receivable on our balance sheet as of September 30, 2021 for future insurance recoveries. The remaining $12.5 million of costs were included in other operation and maintenance expense in 2020 as we do not intend to seek recovery of these costs.

In June 2021, we received approval from the PSCW to restore the PSB and to defer the project costs, net of insurance proceeds, as a component of rate base. As such, we do not currently expect a significant impact to our future results of operations, and although we may experience differences between periods in the timing of cash flows, we also do not currently expect a significant impact to our long-term cash flows from this event.

NOTE 7—COMMON EQUITY

Stock-Based Compensation

During the nine months ended September 30, 2021, the Compensation Committee of our Board of Directors awarded the following stock-based compensation awards to our directors, officers, and certain other key employees:

Award Type						Number of Awards
Stock options (1)						530,612
Restricted shares (2)						69,681
Performance units						152,382

(1)Stock options awarded had a weighted-average exercise price of $91.06 and a weighted-average grant date fair value of $13.20 per option.

(2)Restricted shares awarded had a weighted-average grant date fair value of $91.06 per share.

Restrictions

Our ability as a holding company to pay common stock dividends primarily depends on the availability of funds received from our utility subsidiaries; We Power; Bluewater Gas Storage, LLC; ATC Holding LLC, which holds our ownership interest in ATC; and WECI. Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans, or advances. All of our utility subsidiaries, with the exception of UMERC and MGU, are prohibited from loaning funds to us, either directly or indirectly. See Note 11, Common Equity, in our 2020 Annual Report on Form 10-K for additional information on these and other restrictions.

We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future.

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Common Stock Dividends

On October 21, 2021, our Board of Directors declared a quarterly cash dividend of $0.6775 per share, payable on December 1, 2021, to shareholders of record on November 12, 2021.

NOTE 8—SHORT-TERM DEBT AND LINES OF CREDIT

The following table shows our short-term borrowings and their corresponding weighted-average interest rates:

(in millions, except percentages)						September 30, 2021						December 31, 2020
Commercial paper
Amount outstanding						$	1,508.4					$	1,436.9
Weighted-average interest rate on amounts outstanding						0.16		%				0.21		%
Term loan
Amount outstanding						$	—					$	340.0
Weighted-average interest rate on amounts outstanding						N/A						0.99		%
Operating expense loans
Amount outstanding (1)						$	0.5					$	—

(1)Coyote Ridge and Tatanka Ridge entered into operating expense loans and borrowed funds from their noncontrolling interests. In accordance with their limited liability company operating agreements, Coyote Ridge and Tatanka Ridge received loans from their owners in proportion to their ownership interests.

Our average amount of commercial paper borrowings based on daily outstanding balances during the nine months ended September 30, 2021 was $1,415.4 million with a weighted-average interest rate during the period of 0.17%.

In order to enhance our liquidity position in response to the COVID-19 pandemic, in March 2020, WEC Energy Group entered into a $340.0 million 364-day term loan. In March 2021, we repaid the term loan using the net proceeds from the issuance of our 0.80% Senior Notes. See Note 9, Long-Term Debt, for more information.

The information in the table below relates to our revolving credit facilities used to support our commercial paper borrowing programs, including remaining available capacity under these facilities:

(in millions)						Maturity						September 30, 2021
WEC Energy Group (1)						September 2026						$	1,500.0
WE (1)						September 2026						500.0
WPS (2)						October 2022						400.0
WG (1)						September 2026						350.0
PGL (1)						September 2026						350.0
Total short-term credit capacity												$	3,100.0
Less:
Letters of credit issued inside credit facilities												$	2.3
Commercial paper outstanding												1,508.4
Available capacity under existing agreements												$	1,589.3

(1) In September 2021, WEC Energy Group increased its credit facility to $1,500.0 million, and each of WEC Energy Group, WE, WG, and PGL extended the maturities of their credit facilities to September 2026.

(2) WPS intends to request approval from the PSCW to extend the maturity of its facility to September 2026.

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NOTE 9—LONG-TERM DEBT

WEC Energy Group, Inc.

In March 2021, we issued $600.0 million of 0.80% Senior Notes due March 15, 2024, and used the net proceeds to repay the $340.0 million 364-day term loan entered into in March 2020 and for general corporate purposes.

Wisconsin Electric Power Company

In June 2021, WE issued $300.0 million of 1.70% Debentures due June 15, 2028, and used the net proceeds to redeem all $300.0 million outstanding of its 2.95% Debentures due September 15, 2021 at par.

Integrys Holding, Inc.

On October 28, 2021, pursuant to a tender offer, Integrys purchased $178.6 million aggregate principal amount of the $400.0 million outstanding of its 2013 Junior Notes for $196.4 million (which includes payment of accrued interest) with proceeds received from WEC Energy Group issuing commercial paper. Integrys exercised its right to early settlement of the 2013 Junior Notes tendered and not validly withdrawn as of October 26, 2021. Integrys' estimated loss is $13.6 million. Integrys does not anticipate purchasing any additional 2013 Junior Notes in the tender offer, which expires on November 9, 2021.

WEPCo Environmental Trust Finance I, LLC

In May 2021, WEPCo Environmental Trust, a special purpose entity formed by WE, issued $118.8 million of 1.578% ETBs due December 15, 2035, and used the net proceeds to purchase environmental control property from WE. Principal and interest will be paid semiannually, beginning December 15, 2021, and the ETBs are expected to be fully repaid by December 15, 2033. For additional information, see Note 19, Variable Interest Entities – WEPCo Environmental Trust Finance I, LLC.

NOTE 10—MATERIALS, SUPPLIES, AND INVENTORIES

Our inventory consisted of:

(in millions)						September 30, 2021						December 31, 2020
Natural gas in storage						$	365.3					$	224.9
Materials and supplies						229.0						218.1
Fossil fuel						51.4						85.6
Total						$	645.7					$	528.6

PGL and NSG price natural gas storage injections at the calendar year average of the costs of natural gas supply purchased. Withdrawals from storage are priced on the LIFO cost method. For interim periods, the difference between current projected replacement cost and the LIFO cost for quantities of natural gas temporarily withdrawn from storage is recorded as a temporary LIFO liquidation debit or credit. At September 30, 2021, all LIFO layers were replenished, and the LIFO liquidation balance was zero.

Substantially all other natural gas in storage, materials and supplies, and fossil fuel inventories are recorded using the weighted-average cost method of accounting.

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NOTE 11—INCOME TAXES

The provision for income taxes differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes as a result of the following:

						Three Months Ended September 30, 2021												Three Months Ended September 30, 2020
(in millions)						Amount						Effective Tax Rate						Amount						Effective Tax Rate
Statutory federal income tax						$	71.8					21.0		%				$	65.9					21.0		%
State income taxes net of federal tax benefit						21.5						6.3		%				19.7						6.3		%
PTCs						(17.0)						(5.0)		%				(11.2)						(3.6)		%
Federal excess deferred tax amortization – Wisconsin unprotected						(16.3)						(4.8)		%				(12.5)						(4.0)		%
Federal excess deferred tax amortization						(7.8)						(2.3)		%				(8.3)						(2.6)		%
Other						(1.4)						(0.2)		%				(6.7)						(2.2)		%
Total income tax expense						$	50.8					15.0		%				$	46.9					14.9		%

						Nine Months Ended September 30, 2021												Nine Months Ended September 30, 2020
(in millions)						Amount						Effective Tax Rate						Amount						Effective Tax Rate
Statutory federal income tax						$	263.7					21.0		%				$	242.0					21.0		%
State income taxes net of federal tax benefit						79.2						6.3		%				72.1						6.3		%
PTCs						(64.5)						(5.1)		%				(39.0)						(3.4)		%
Federal excess deferred tax amortization – Wisconsin unprotected						(62.9)						(5.0)		%				(45.7)						(4.0)		%
Federal excess deferred tax amortization						(30.3)						(2.4)		%				(30.2)						(2.6)		%
Other						(5.4)						(0.5)		%				(8.5)						(0.8)		%
Total income tax expense						$	179.8					14.3		%				$	190.7					16.5		%

The effective tax rates of 15.0% and 14.3% for the three and nine months ended September 30, 2021, respectively, differ from the United States statutory federal income tax rate of 21%, primarily due to PTCs generated from ownership interests in wind generation facilities in our non-utility energy infrastructure segment and the recognition of certain unprotected deferred tax benefits created as a result of the Tax Legislation. In accordance with the rate order received from the PSCW in December 2019, our Wisconsin utilities are amortizing the unprotected deferred tax benefits over periods ranging from two years to four years, to reduce near-term rate impacts to their customers. In addition, the impact of the protected benefits associated with the Tax Legislation, as discussed in more detail below, drove a decrease in the effective tax rate. These items were partially offset by state income taxes.

The effective tax rates of 14.9% and 16.5% for the three and nine months ended September 30, 2020, respectively, differ from the United States statutory federal income tax rate of 21%, primarily due to the recognition of certain unprotected deferred tax benefits created as a result of the Tax Legislation. In addition, PTCs generated from ownership interests in wind generation facilities in our non-utility energy infrastructure segment and the impact of the protected benefits associated with the Tax Legislation, as discussed in more detail below, drove a decrease in the effective tax rate. These items were partially offset by state income taxes.

The Tax Legislation required our regulated utilities to remeasure their deferred income taxes and we began to amortize the resulting excess protected deferred income taxes beginning in 2018 in accordance with normalization requirements (see federal excess deferred tax amortization line above).

See Note 22, Regulatory Environment, for more information on unprotected tax benefits.

NOTE 12—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).

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Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods.

Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

When possible, we base the valuations of our derivative assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally-developed inputs.

The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy:

						September 30, 2021
(in millions)						Level 1						Level 2						Level 3						Total
Derivative assets
Natural gas contracts						$	209.6					$	12.6					$	—					$	222.2
FTRs						—						—						3.7						3.7
Coal contracts						—						44.2						—						44.2
Total derivative assets						$	209.6					$	56.8					$	3.7					$	270.1
Investments held in rabbi trust						$	77.8					$	—					$	—					$	77.8
Derivative liabilities
Natural gas contracts						$	0.1					$	20.5					$	—					$	20.6
Interest rate swaps						—						1.7						—						1.7
Total derivative liabilities						$	0.1					$	22.2					$	—					$	22.3

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						December 31, 2020
(in millions)						Level 1						Level 2						Level 3						Total
Derivative assets
Natural gas contracts						$	11.7					$	2.0					$	—					$	13.7
FTRs						—						—						2.4						2.4
Coal contracts						—						1.8						—						1.8
Total derivative assets						$	11.7					$	3.8					$	2.4					$	17.9
Investments held in rabbi trust						$	79.6					$	—					$	—					$	79.6
Derivative liabilities
Natural gas contracts						$	7.7					$	6.4					$	—					$	14.1
Coal contracts						—						1.2						—						1.2
Interest rate swaps						—						6.8						—						6.8
Total derivative liabilities						$	7.7					$	14.4					$	—					$	22.1

The derivative assets and liabilities listed in the tables above include options, swaps, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices and interest rates. They also include FTRs, which are used to manage electric transmission congestion costs in the MISO Energy and Operating Reserves Markets.

We hold investments in the Integrys rabbi trust. These investments are restricted as they can only be withdrawn from the trust to fund participants' benefits under the Integrys deferred compensation plan and certain Integrys non-qualified pension plans. These investments are included in other long-term assets on our balance sheets. During the three months ended September 30, 2021, we recorded $0.1 million of net unrealized losses in earnings related to the investments held at the end of the period, compared with $5.7 million of net unrealized gains recorded during the same period in 2020. For the nine months ended September 30, 2021 and 2020, the net unrealized gains included in earnings related to the investments held at the end of the period were $9.7 million and $2.9 million, respectively.

The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy:

						Three Months Ended September 30												Nine Months Ended September 30
(in millions)						2021						2020						2021						2020
Balance at the beginning of the period						$	5.4					$	6.5					$	2.4					$	3.1
Purchases						—						—						6.1						7.5
Settlements						(1.7)						(2.5)						(4.8)						(6.6)
Balance at the end of the period						$	3.7					$	4.0					$	3.7					$	4.0

Fair Value of Financial Instruments

The following table shows the financial instruments included on our balance sheets that were not recorded at fair value:

						September 30, 2021												December 31, 2020
(in millions)						Carrying Amount						Fair Value						Carrying Amount						Fair Value
Preferred stock of subsidiary						$	30.4					$	30.5					$	30.4					$	32.3
Long-term debt, including current portion (1)						13,114.9						14,573.8						12,450.5						14,343.2

(1)The carrying amount of long-term debt excludes finance lease obligations of $59.9 million and $63.4 million at September 30, 2021 and December 31, 2020, respectively.

The fair values of our long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy.

NOTE 13—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.

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We record derivative instruments on our balance sheets as an asset or liability measured at fair value unless they qualify for the normal purchases and sales exception and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities.

None of our derivatives are designated as hedging instruments, with the exception of our interest rate swaps, which have been designated as cash flow hedges. On our balance sheets, we classify derivative assets and liabilities as current or long-term based on the maturities of the underlying contracts. Derivative assets and liabilities not shown separately on our balance sheets are included in the other current and other long-term line items. The following table shows our derivative assets and derivative liabilities.

						September 30, 2021												December 31, 2020
(in millions)						Derivative Assets						Derivative Liabilities						Derivative Assets						Derivative Liabilities
Current
Natural gas contracts						$	204.7					$	20.6					$	13.0					$	12.9
FTRs						3.7						—						2.4						—
Coal contracts						38.7						—						1.6						0.8
Interest rate swaps						—						1.7						—						6.8
Total current						247.1						22.3						17.0						20.5
Long-term
Natural gas contracts						17.5						—						0.7						1.2
Coal contracts						5.5						—						0.2						0.4
Total long-term						23.0						—						0.9						1.6
Total						$	270.1					$	22.3					$	17.9					$	22.1

Realized gains (losses) on derivatives not designated as hedging instruments are primarily recorded in cost of sales on the income statements. Our estimated notional sales volumes and realized gains (losses) were as follows:

						Three Months Ended September 30, 2021												Three Months Ended September 30, 2020
(in millions)						Volumes						Gains						Volumes						Gains (Losses)
Natural gas contracts						39.4 Dth						$	41.2					36.2 Dth						$	(12.0)
FTRs						6.3 MWh						3.0						8.3 MWh						1.1
Total												$	44.2											$	(10.9)
						Nine Months Ended September 30, 2021												Nine Months Ended September 30, 2020
(in millions)						Volumes						Gains						Volumes						Gains (Losses)
Natural gas contracts						147.1 Dth						$	38.5					139.3 Dth						$	(53.9)
FTRs						22.1 MWh						15.3						22.7 MWh						3.1
Total												$	53.8											$	(50.8)

On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At September 30, 2021 and December 31, 2020, we had posted cash collateral of $10.5 million and $18.9 million, respectively. These amounts were recorded on our balance sheets in other current assets. At September 30, 2021, we had also received cash collateral of $134.1 million. This amount was recorded on our balance sheet in other current liabilities.

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The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets:

						September 30, 2021												December 31, 2020
(in millions)						Derivative Assets						Derivative Liabilities						Derivative Assets						Derivative Liabilities
Gross amount recognized on the balance sheet						$	270.1					$	22.3					$	17.9					$	22.1
Gross amount not offset on the balance sheet						(134.9)			(1)			(1.3)						(6.9)						(7.7)			(2)
Net amount						$	135.2					$	21.0					$	11.0					$	14.4

(1)Includes cash collateral received of $133.6 million.

(2)Includes cash collateral posted of $0.8 million.

Cash Flow Hedges

As of September 30, 2021, we had two interest rate swaps with a combined notional value of $250.0 million to hedge the variable interest rate risk associated with our 2007 Junior Notes. The swaps provide a fixed interest rate of 4.9765% on $250.0 million of the $500.0 million of outstanding 2007 Junior Notes through November 15, 2021. As these swaps qualify for cash flow hedge accounting treatment, the related gains and losses are being deferred in accumulated other comprehensive loss and are being amortized to interest expense as interest is accrued on the 2007 Junior Notes.

We previously entered into forward interest rate swap agreements to mitigate the interest rate exposure associated with the issuance of long-term debt related to the acquisition of Integrys. These swap agreements were settled in 2015, and we continue to amortize amounts out of accumulated other comprehensive loss into interest expense over the periods in which the interest costs are recognized in earnings.

The table below shows the amounts related to these cash flow hedges recorded in other comprehensive income (loss) and in earnings, along with our total interest expense on the income statements:

						Three Months Ended September 30												Nine Months Ended September 30
(in millions)						2021						2020						2021						2020
Derivative loss recognized in other comprehensive loss						$	—					$	—					$	—					$	(5.8)
Net derivative loss reclassified from accumulated other comprehensive loss to interest expense						(1.4)						(1.3)						(4.1)						(2.0)
Total interest expense line item on the income statements						118.0						122.0						357.5						375.8

We estimate that during the next twelve months $0.4 million will be reclassified from accumulated other comprehensive loss as an increase to interest expense.

NOTE 14—GUARANTEES

The following table shows our outstanding guarantees:

												Expiration
(in millions)						Total Amounts Committed at September 30, 2021						Less Than 1 Year						1 to 3 Years						Over 3 Years
Guarantees supporting transactions of subsidiaries (1)						$	125.5					$	51.5					$	1.5					$	72.5
Standby letters of credit (2)						127.2						54.3						—						72.9
Surety bonds (3)						12.8						12.8						—						—
Other guarantees (4)						10.7						—						—						10.7
Total guarantees						$	276.2					$	118.6					$	1.5					$	156.1

(1)Consists of $4.2 million, $8.1 million, and $113.2 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.

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(3)Primarily for workers compensation self-insurance programs and obtaining various licenses, permits, and rights-of-way. These amounts are not reflected on our balance sheets.

(4)Consists of $10.7 million related to workers compensation coverage for which a liability was recorded on our balance sheets.

NOTE 15—EMPLOYEE BENEFITS

The following tables show the components of net periodic benefit cost (credit) for our benefit plans.

						Pension Benefits
						Three Months Ended September 30												Nine Months Ended September 30
(in millions)						2021						2020						2021						2020
Service cost						$	13.3					$	12.5					$	40.8					$	37.3
Interest cost						22.2						25.6						65.8						77.8
Expected return on plan assets						(50.1)						(47.4)						(150.8)						(143.0)
Loss on plan settlement						0.9						5.2						2.9						15.5
Amortization of prior service cost						0.4						0.4						1.2						1.2
Amortization of net actuarial loss						26.4						26.1						82.0						75.8
Net periodic benefit cost						$	13.1					$	22.4					$	41.9					$	64.6

						OPEB Benefits
						Three Months Ended September 30												Nine Months Ended September 30
(in millions)						2021						2020						2021						2020
Service cost						$	4.0					$	3.8					$	11.8					$	11.4
Interest cost						3.7						4.7						10.9						14.0
Expected return on plan assets						(16.5)						(15.0)						(49.5)						(45.2)
Amortization of prior service credit						(4.1)						(3.8)						(12.0)						(11.3)
Amortization of net actuarial gain						(5.9)						(5.6)						(18.1)						(16.8)
Net periodic benefit credit						$	(18.8)					$	(15.9)					$	(56.9)					$	(47.9)

During the nine months ended September 30, 2021, we made contributions and payments of $9.8 million related to our pension plans and $1.5 million related to our OPEB plans. We expect to make contributions and payments of $1.9 million related to our pension plans and $0.7 million related to our OPEB plans during the remainder of 2021, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.

NOTE 16—GOODWILL AND INTANGIBLES

Goodwill

Goodwill represents the excess of the cost of an acquisition over the fair value of the identifiable net assets acquired. The table below shows our goodwill balances by segment at September 30, 2021. We had no changes to the carrying amount of goodwill during the nine months ended September 30, 2021.

(in millions)						Wisconsin						Illinois						Other States						Non-Utility Energy Infrastructure						Total
Goodwill balance (1)						$	2,104.3					$	758.7					$	183.2					$	6.6					$	3,052.8

(1)We had no accumulated impairment losses related to our goodwill as of September 30, 2021.

During the third quarter of 2021, annual impairment tests were completed at all of our reporting units that carried a goodwill balance as of July 1, 2021. No impairments resulted from these tests.

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Intangible Assets

At September 30, 2021, we had $5.7 million of indefinite-lived intangible assets primarily related to an MGU trade name obtained through an acquisition, which is included in other long-term assets on our balance sheets. We had no changes to the carrying amount of these intangible assets during the nine months ended September 30, 2021.

Intangible Liabilities

The intangible liabilities below were all obtained through acquisitions by WECI and are classified as other long-term liabilities on our balance sheets. See Note 2, Acquisitions, for more information.

						September 30, 2021																		December 31, 2020
(in millions)						Gross Carrying Amount						Accumulated Amortization						Net Carrying Amount						Gross Carrying Amount						Accumulated Amortization						Net Carrying Amount
PPAs (1)						$	84.3					$	(4.9)					$	79.4					$	76.1					$	—					$	76.1
Proxy revenue swap (2)						7.2						(1.9)						5.3						7.2						(1.3)						5.9
Interconnection agreements (3)						5.1						(0.4)						4.7						5.1						(0.3)						4.8
Total intangible liabilities						$	96.6					$	(7.2)					$	89.4					$	88.4					$	(1.6)					$	86.8

(1) Represents PPAs related to the acquisition of Blooming Grove, Tatanka Ridge, and Jayhawk expiring between 2030 and 2032. The weighted-average remaining life of the PPAs is approximately 11 years.

(2) Represents an agreement with a counterparty to swap the market revenue of Upstream's wind generation for fixed quarterly payments over 10 years, which expires in 2029. The remaining life of the proxy revenue swap is approximately seven years.

(3) Represents interconnection agreements related to the acquisitions of Tatanka Ridge and Bishop Hill III, expiring in 2040 and 2041, respectively. These agreements relate to payments for connecting our facilities to the infrastructure of another utility to facilitate the movement of power onto the electric grid. The weighted-average remaining life of the interconnection agreements is approximately 19 years.

Amortization related to these intangibles for the three and nine months ended September 30, 2021 was $1.9 million and $5.6 million, respectively. Amortization for the three and nine months ended September 30, 2020 was not significant. Amortization for the next five years is estimated to be:

						For the Years Ending December 31
(in millions)						2022						2023						2024						2025						2026
Amortization to be recorded in operating revenues						$	8.1					$	8.1					$	8.1					$	8.1					$	8.1
Amortization to be recorded in other operation and maintenance						0.2						0.2						0.2						0.2						0.2

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NOTE 17—INVESTMENT IN TRANSMISSION AFFILIATES

We own approximately 60% of ATC, a for-profit, transmission-only company regulated by the FERC for cost of service and certain state regulatory commissions for routing and siting of transmission projects. We also own approximately 75% of ATC Holdco, a separate entity formed in December 2016 to invest in transmission-related projects outside of ATC's traditional footprint. The following tables provide a reconciliation of the changes in our investments in ATC and ATC Holdco:

						Three Months Ended September 30, 2021
(in millions)						ATC						ATC Holdco						Total
Balance at beginning of period						$	1,749.7					$	32.3					$	1,782.0
Add: Earnings from equity method investment						41.7						0.6						42.3
Less: Distributions						33.0						—						33.0
Balance at end of period						$	1,758.4					$	32.9					$	1,791.3
						Three Months Ended September 30, 2020
(in millions)						ATC						ATC Holdco						Total
Balance at beginning of period						$	1,713.3					$	31.4					$	1,744.7
Add: Earnings from equity method investment						39.6						0.5						40.1
Add: Capital contributions						6.2						—						6.2
Less: Distributions						39.9						—						39.9
Less: Return of capital						—						0.6						0.6
Less: Other						0.1						—						0.1
Balance at end of period						$	1,719.1					$	31.3					$	1,750.4
						Nine Months Ended September 30, 2021
(in millions)						ATC						ATC Holdco						Total
Balance at beginning of period						$	1,733.5					$	30.8					$	1,764.3
Add: Earnings from equity method investment						124.1						2.1						126.2
Less: Distributions						99.2						—						99.2
Balance at end of period						$	1,758.4					$	32.9					$	1,791.3
						Nine Months Ended September 30, 2020
(in millions)						ATC						ATC Holdco						Total
Balance at beginning of period						$	1,684.7					$	36.1					$	1,720.8
Add: Earnings from equity method investment						131.7						1.1						132.8
Add: Capital contributions						15.2						—						15.2
Less: Distributions						112.5						—						112.5
Less: Return of capital						—						5.9						5.9
Balance at end of period						$	1,719.1					$	31.3					$	1,750.4

We pay ATC for network transmission and other related services it provides. In addition, we provide a variety of operational, maintenance, and project management work for ATC, which is reimbursed by ATC. We are also required to initially fund the construction of transmission infrastructure upgrades needed for new generation projects. ATC owns these transmission assets and reimburses us for these costs when the new generation is placed in service.

The following table summarizes our significant related party transactions with ATC:

						Three Months Ended September 30												Nine Months Ended September 30
(in millions)						2021						2020						2021						2020
Charges to ATC for services and construction						$	5.5					$	5.7					$	17.2					$	18.7
Charges from ATC for network transmission services						90.3						87.8						270.7						262.7
Net refund from ATC related to FERC ROE orders						8.7						2.3						7.4						10.7

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Our balance sheets included the following receivables and payables for services provided to or received from ATC:

(in millions)						September 30, 2021						December 31, 2020
Accounts receivable for services provided to ATC						$	2.1					$	3.7
Accounts payable for services received from ATC						26.9						29.3
Amounts due from ATC for transmission infrastructure upgrades (1)						8.9						4.6

(1)The transmission infrastructure upgrades were primarily related to WE's and WPS's construction of their new solar projects, Badger Hollow II and Badger Hollow I, respectively.

Summarized financial data for ATC is included in the tables below:

						Three Months Ended September 30												Nine Months Ended September 30
(in millions)						2021						2020						2021						2020
Income statement data
Operating revenues						$	186.8					$	187.8					$	561.4					$	577.7
Operating expenses						91.3						93.0						278.8						285.7
Other expense, net						28.6						28.1						85.2						82.0
Net income						$	66.9					$	66.7					$	197.4					$	210.0

(in millions)						September 30, 2021						December 31, 2020
Balance sheet data
Current assets						$	87.0					$	92.7
Noncurrent assets						5,539.8						5,400.6
Total assets						$	5,626.8					$	5,493.3
Current liabilities						$	483.0					$	310.8
Long-term debt						2,412.8						2,512.2
Other noncurrent liabilities						398.9						378.2
Members' equity						2,332.1						2,292.1
Total liabilities and members' equity						$	5,626.8					$	5,493.3

NOTE 18—SEGMENT INFORMATION

We use net income attributed to common shareholders to measure segment profitability and to allocate resources to our businesses. At September 30, 2021, we reported six segments, which are described below.

• The Wisconsin segment includes the electric and natural gas utility operations of WE, WPS, WG, and UMERC.

• The Illinois segment includes the natural gas utility operations of PGL and NSG.

• The other states segment includes the natural gas utility and non-utility operations of MERC and MGU.

• The electric transmission segment includes our approximate 60% ownership interest in ATC, a for-profit, transmission-only company regulated by the FERC for cost of service and certain state regulatory commissions for routing and siting of transmission projects, and our approximate 75% ownership interest in ATC Holdco, which was formed to invest in transmission-related projects outside of ATC's traditional footprint.

• The non-utility energy infrastructure segment includes:

◦We Power, which owns and leases generating facilities to WE,

◦Bluewater, which owns underground natural gas storage facilities in Michigan that provide approximately one-third of the current storage needs for our Wisconsin natural gas utilities, and

◦WECI, which holds our ownership interests in the following wind generating facilities:

▪90% ownership interest in Bishop Hill III, located in Henry County, Illinois,

▪80% ownership interest in Coyote Ridge, located in Brookings County, South Dakota,

▪90% ownership interest in Upstream, located in Antelope County, Nebraska,

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▪90% ownership interest in Blooming Grove, located in McLean County, Illinois,

▪85% ownership interest in Tatanka Ridge, located in Deuel County, South Dakota, and

▪90% ownership interest in Jayhawk, under construction in Bourbon and Crawford counties, Kansas.

See Note 2, Acquisitions, for more information on Tatanka Ridge and Jayhawk.

• The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, the Peoples Energy, LLC holding company, Wispark, Wisvest LLC, Wisconsin Energy Capital Corporation, WEC Business Services LLC, and also included the operations of WPS Power Development, LLC in 2020 prior to the sale of its remaining solar facilities in the fourth quarter of 2020.

All of our operations are located within the United States. The following tables show summarized financial information related to our reportable segments for the three and nine months ended September 30, 2021 and 2020:

						Utility Operations
(in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Electric Transmission						Non-Utility Energy Infrastructure						Corporate and Other						Reconciling Eliminations						WEC Energy Group Consolidated
Three Months Ended September 30, 2021
External revenues						$	1,458.6					$	216.2					$	52.8					$	1,727.6					$	—					$	18.7					$	0.2					$	—					$	1,746.5
Intersegment revenues						—						—						—						—						—						110.8						—						(110.8)						—
Other operation and maintenance						359.1						91.2						19.6						469.9						—						9.9						(4.5)						(1.6)						473.7
Depreciation and amortization						184.4						55.4						9.6						249.4						—						31.2						6.3						(15.3)						271.6
Equity in earnings of transmission affiliates						—						—						—						—						42.3						—						—						—						42.3
Interest expense						137.9						16.5						1.6						156.0						4.8						17.6						24.7						(85.1)						118.0
Income tax expense (benefit)						33.6						7.0						(1.0)						39.6						9.7						5.0						(3.5)						—						50.8
Net income (loss)						197.8						19.1						(2.7)						214.2						27.8						62.8						(16.1)						—						288.7
Net income (loss) attributed to common shareholders						197.5						19.1						(2.7)						213.9						27.8						64.4						(16.1)						—						290.0

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						Utility Operations
(in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Electric Transmission						Non-Utility Energy Infrastructure						Corporate and Other						Reconciling Eliminations						WEC Energy Group Consolidated
Three Months Ended September 30, 2020
External revenues						$	1,366.3					$	221.9					$	48.3					$	1,636.5					$	—					$	13.9					$	0.6					$	—					$	1,651.0
Intersegment revenues						—						—						—						—						—						109.6						—						(109.6)						—
Other operation and maintenance						363.8						109.2						20.4						493.4						—						5.9						1.0						(1.6)						498.7
Depreciation and amortization						169.7						49.9						8.5						228.1						—						24.5						6.5						(14.1)						245.0
Equity in earnings of transmission affiliates						—						—						—						—						40.1						—						—						—						40.1
Interest expense						139.1						15.6						2.7						157.4						4.9						15.0						30.4						(85.7)						122.0
Income tax expense (benefit)						37.5						(4.0)						(1.2)						32.3						9.0						13.4						(7.8)						—						46.9
Net income (loss)						187.9						13.0						(3.3)						197.6						26.3						62.9						(19.7)						—						267.1
Net income (loss) attributed to common shareholders						187.6						13.0						(3.3)						197.3						26.3						62.9						(19.7)						—						266.8

						Utility Operations
(in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Electric Transmission						Non-Utility Energy Infrastructure						Corporate and Other						Reconciling Eliminations						WEC Energy Group Consolidated
Nine Months Ended September 30, 2021
External revenues						$	4,497.8					$	1,195.1					$	358.2					$	6,051.1					$	—					$	62.6					$	0.4					$	—					$	6,114.1
Intersegment revenues						—						—						—						—						—						338.0						—						(338.0)						—
Other operation and maintenance						1,047.1						291.3						64.0						1,402.4						—						31.2						(9.1)						(7.1)						1,417.4
Depreciation and amortization						540.4						162.1						28.2						730.7						—						93.5						19.3						(44.3)						799.2
Equity in earnings of transmission affiliates						—						—						—						—						126.2						—						—						—						126.2
Interest expense						417.8						49.6						4.6						472.0						14.5						53.5						73.5						(256.0)						357.5
Income tax expense (benefit)						104.8						64.4						8.2						177.4						28.9						5.8						(32.3)						—						179.8
Net income (loss)						601.2						174.8						24.5						800.5						82.8						202.3						(10.9)						—						1,074.7
Net income (loss) attributed to common shareholders						600.3						174.8						24.5						799.6						82.8						204.6						(10.9)						—						1,076.1

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						Utility Operations
(in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Electric Transmission						Non-Utility Energy Infrastructure						Corporate and Other						Reconciling Eliminations						WEC Energy Group Consolidated
Nine Months Ended September 30, 2020
External revenues						$	4,071.4					$	930.7					$	261.4					$	5,263.5					$	—					$	42.8					$	2.0					$	—					$	5,308.3
Intersegment revenues						—						—						—						—						—						335.6						—						(335.6)						—
Other operation and maintenance						1,044.0						306.5						62.5						1,413.0						—						18.7						2.9						(7.1)						1,427.5
Depreciation and amortization						502.7						146.0						24.6						673.3						—						73.4						19.0						(39.1)						726.6
Equity in earnings of transmission affiliates						—						—						—						—						132.8						—						—						—						132.8
Interest expense						422.2						47.7						7.4						477.3						14.6						45.4						98.1						(259.6)						375.8
Income tax expense (benefit)						110.5						47.7						8.7						166.9						33.4						35.8						(45.4)						—						190.7
Net income (loss)						565.0						152.4						25.8						743.2						84.8						193.2						(59.4)						—						961.8
Net income (loss) attributed to common shareholders						564.1						152.4						25.8						742.3						84.8						193.2						(59.4)						—						960.9

NOTE 19—VARIABLE INTEREST ENTITIES

The primary beneficiary of a VIE must consolidate the entity's assets and liabilities. In addition, certain disclosures are required for significant interest holders in VIEs.

We assess our relationships with potential VIEs, such as our coal suppliers, natural gas suppliers, coal transporters, natural gas transporters, and other counterparties related to PPAs, investments, and joint ventures. In making this assessment, we consider, along with other factors, the potential that our contracts or other arrangements provide subordinated financial support, the obligation to absorb the entity's losses, the right to receive residual returns of the entity, and the power to direct the activities that most significantly impact the entity's economic performance.

WEPCo Environmental Trust Finance I, LLC

In November 2020, the PSCW issued a financing order approving the securitization of $100 million of undepreciated environmental control costs related to WE's retired Pleasant Prairie power plant, the carrying costs accrued on the $100 million during the securitization process, and the related financing fees. The financing order also authorized WE to form WEPCo Environmental Trust, a bankruptcy-remote special purpose entity, for the sole purpose of issuing ETBs to recover the costs approved in the financing order. WEPCo Environmental Trust is a wholly-owned subsidiary of WE.

In May 2021, WEPCo Environmental Trust issued ETBs and used the proceeds to acquire environmental control property from WE. The environmental control property is recorded as a regulatory asset on our balance sheets and includes the right to impose, collect, and receive a non-bypassable environmental control charge from WE's retail electric distribution customers until the ETBs are paid in full and all financing costs have been recovered. The ETBs are secured by the environmental control property. Cash collections from the environmental control charge, and funds on deposit in trust accounts, are the sole source of funds to satisfy the debt obligation. The bondholders have no recourse to WE or any of WE's affiliates. See Note 9, Long-Term Debt, for more information on the ETBs.

WE acts as the servicer of the environmental control property on behalf of WEPCo Environmental Trust and is responsible for metering, calculating, billing, and collecting the environmental control charge. As necessary, WE is authorized to implement periodic adjustments of the environmental control charge. The adjustments are designed to ensure the timely payment of principal, interest, and other ongoing financing costs. WE remits all collections of the environmental control charge to an indenture trustee of WEPCo Environmental Trust.

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WEPCo Environmental Trust is a VIE primarily because its equity capitalization is insufficient to support its operations. As described above, WE has the power to direct the activities that most significantly impact WEPCo Environmental Trust's economic performance. Therefore, WE is considered the primary beneficiary of WEPCo Environmental Trust, and consolidation is required.

The following table summarizes the impact of WEPCo Environmental Trust on our balance sheet.

(in millions)						September 30, 2021
Assets
Other current assets (restricted cash)						$	4.6
Regulatory assets						102.9
Other long-term assets (restricted cash)						0.6
Liabilities
Current portion of long-term debt						8.5
Other current liabilities (accrued interest)						0.7
Long-term debt						107.0

Investment in Transmission Affiliates

We own approximately 60% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. We have determined that ATC is a VIE but consolidation is not required since we are not ATC's primary beneficiary. As a result of our limited voting rights, we do not have the power to direct the activities that most significantly impact ATC's economic performance. Therefore, we account for ATC as an equity method investment. At September 30, 2021 and December 31, 2020, our equity investment in ATC was $1,758.4 million and $1,733.5 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC.

We also own approximately 75% of ATC Holdco, a separate entity formed in December 2016 to invest in transmission-related projects outside of ATC's traditional footprint. We have determined that ATC Holdco is a VIE but consolidation is not required since we are not ATC Holdco's primary beneficiary. As a result of our limited voting rights, we do not have the power to direct the activities that most significantly impact ATC Holdco's economic performance. Therefore, we account for ATC Holdco as an equity method investment. At September 30, 2021 and December 31, 2020, our equity investment in ATC Holdco was $32.9 million and $30.8 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC Holdco.

See Note 17, Investment in Transmission Affiliates, for more information, including any significant assets and liabilities related to ATC and ATC Holdco recorded on our balance sheets.

Power Purchase Agreement

We have a PPA that represents a variable interest. This agreement is for 236 MWs of firm capacity from a natural gas-fired cogeneration facility, and we account for it as a finance lease. The agreement includes no minimum energy requirements over the remaining term of approximately one year. We have examined the risks of the entity, including operations, maintenance, dispatch, financing, fuel costs, and other factors, and have determined that we are not the primary beneficiary of the entity. We do not hold an equity or debt interest in the entity, and there is no residual guarantee associated with the PPA.

We have $6.5 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.

NOTE 20—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.

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Unconditional Purchase Obligations

Our electric utilities have obligations to distribute and sell electricity to their customers, and our natural gas utilities have obligations to distribute and sell natural gas to their customers. The utilities expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time.

The wind generation facilities that are part of our non-utility energy infrastructure segment have obligations to distribute and sell electricity through long-term offtake agreements with their customers for all of the energy produced. In order to support these sales obligations, these companies enter into easements and other service agreements associated with the wind generating facilities.

Our minimum future commitments related to these purchase obligations as of September 30, 2021, including those of our subsidiaries, were approximately $10.8 billion.

Environmental Matters

Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as sulfur dioxide, NOx, fine particulates, mercury, and GHGs; water intake and discharges; management of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites.

Air Quality

National Ambient Air Quality Standards

Ozone

After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, creating a more stringent standard than the 2008 NAAQS. The 2015 ozone standard lowered the 8-hour limit for ground-level ozone. In December 2020, the EPA completed its 5-year review of the ozone standard and issued a final decision to retain, without any changes, the existing 2015 standard. Under Executive Order 13990, the Biden Administration ordered that all agencies review existing regulations, orders, guidance documents, policies, and similar actions promulgated, issued, or adopted between January 20, 2017 and January 20, 2021. Consequently, the December 2020 decision to retain the 2015 ozone standards with no changes is currently under review by the EPA.

The EPA issued final nonattainment area designations for the 2015 ozone standard in April 2018. The following counties within our Wisconsin service territories were designated as partial nonattainment: Door, Kenosha, Sheboygan, Manitowoc, and Northern Milwaukee/Ozaukee. This re-designation was challenged in the D.C. Circuit Court of Appeals in Clean Wisconsin et al. v. U.S. Environmental Protection Agency. A decision was issued in July 2020 remanding the rule to the EPA for further evaluation. As a result of the July 2020 remand, in June 2021, the EPA published its final action to revise the boundaries for 13 counties associated with six nonattainment areas, including several in Illinois and Wisconsin. Under the new designations, all of Milwaukee and Ozaukee counties are now listed as nonattainment and portions of Racine, Waukesha, and Washington counties have been added to the nonattainment area. Additionally, the Chicago, Illinois, Indiana, and Wisconsin nonattainment area now includes an expanded portion of Kenosha county, and the partial nonattainment areas of Sheboygan, Door, and Manitowoc counties have also been expanded. Preliminary 2019-2021 monitoring data indicates that the Milwaukee, Sheboygan, and Chicago nonattainment areas will likely be adjusted to "moderate" nonattainment for the 2015 standard.

In February 2021, the WDNR proposed draft revisions to the Wisconsin Administrative Code to adopt the 2015 ozone standard and incorporate by reference the federal air pollution monitoring requirements related to the NAAQS. The Natural Resources Board adopted the rule as proposed during their June 2021 meeting and the rule is now in legislative review. We believe that we are well positioned to meet the requirements associated with the 2015 ozone standard and do not expect to incur significant costs to comply with associated state or federal rules.

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Particulate Matter

In addition to the 2015 ozone standard, in December 2020, the EPA completed its 5-year review of the 2012 standard for particulate matter, including fine particulate matter. The EPA determined that no revisions were necessary to the current standard. This determination was also subject to review under Executive Order 13990 and in June 2021, the EPA announced it would reconsider the December 2020 decision. Under the Biden Administration's policy review, the EPA concluded that the scientific evidence and information from the December 2020 determination supports revising the level of the annual standard for the particulate matter NAAQS to below the current level of 12 micrograms per cubic meter, while retaining the 24-hour standard. A proposed rule-making is expected in summer 2022, and a final rule is expected in spring 2023. All counties within our service territories are in attainment with the current 2012 standards.

Climate Change

The ACE rule, effective since September 2019, was vacated by the D.C. Circuit Court of Appeals in January 2021. The ACE rule replaced the Clean Power Plan and provided existing coal-fired generating units with standards for achieving GHG emission reductions. In a memorandum issued to the EPA regional administrators in February 2021, the EPA stated that the D.C. Circuit Court decision meant that no existing rule regulates GHG emissions from electric generating units. The EPA is currently reviewing its options for such regulations and has signaled that a draft rule will not be ready until 2022 at the earliest. In October 2021, the Supreme Court agreed to review the D.C. Circuit Court's ruling vacating the EPA's ACE rule. The Supreme Court will review a number of issues regarding the scope of the EPA's regulatory authority to utilize Section 111(d) of the CAA to address CO2 emissions. Arguments are expected to take place in early 2022 with a decision expected by the summer of 2022.

In January 2021, the EPA finalized a rule to revise the New Source Performance Standards for GHG emissions from new, modified, and reconstructed fossil-fueled power plants. The rule became effective in March 2021; however, the EPA asked the D.C. Circuit Court of Appeals to vacate and remand the final rule, which was granted by the D.C. Circuit Court of Appeals in April 2021. Despite this uncertainty, we continue to move forward on the ESG Progress Plan, which is heavily focused on reducing GHG emissions.

Our ESG Progress Plan includes the retirement of older, fossil-fueled generation, to be replaced with zero-carbon-emitting renewables and clean natural gas-fueled generation by 2025. By the end of 2020, we were able to reduce CO2 emissions from our electric generation fleet by more than 50% below 2005 levels. As a result, we announced new goals in May 2021. We committed to a 60% reduction in carbon emissions from our electric generation fleet by 2025 and an 80% reduction by the end of 2030, both from a 2005 baseline. We expect to achieve these goals by making operating refinements, retiring less efficient generating units, and executing our capital plan. Over the longer term, the target for our generation fleet is net-zero carbon emissions by 2050. We have already retired more than 1,800 MW of coal-fired generation since the beginning of 2018. As part of the ESG Progress Plan, we expect to retire approximately 1,600 MW of additional fossil-fueled generation by 2025, which includes the planned retirements in 2023-2024 of OCPP Units 5-8 and the jointly-owned Columbia Units 1-2.

We continue to reduce methane emissions by improving our natural gas distribution system. Our initial 2030 goal called for a 30% reduction in methane emissions from a 2011 baseline. Given advancements with renewable natural gas, we set a new target across our natural gas distribution operations to achieve net-zero methane emissions by the end of 2030.

Cross-State Air Pollution Rule Update Rule Revision

In 2015, the EPA determined that several upwind states had failed to submit state implementation plans that addressed their "Good Neighbor" obligations (i.e., the states projected NOx emissions significantly contribute to a continuing downwind nonattainment and/or maintenance problem); therefore, by statute, the EPA was required to issue a federal implementation plan. In March 2021, the EPA finalized a CSAPR update rule revision that keeps nine of the 21 CSAPR affected states (including Wisconsin) in a Group 2 NOx ozone season trading program and found that the prior CSAPR update is sufficient to meet Wisconsin's "Good Neighbor" obligations. No further NOx reductions will be needed within these nine states. This rule became effective June 29, 2021 and did not have a material impact on our financial condition or results of operations.

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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 federal rule became effective in October 2014 and applies to all of our existing generating facilities with cooling water intake structures, except for the ERGS units, which were permitted under the rules governing new facilities. In 2016, the WDNR initiated a state rulemaking process to incorporate the federal Section 316(b) requirements into the Wisconsin Administrative Code. This new state rule became effective in June 2020, and the WDNR will apply this rule when establishing BTA requirements for cooling water intake structures at existing facilities. These BTA requirements are incorporated into Wisconsin Pollutant Discharge Elimination System permits for WE and WPS facilities.

We have received BTA determinations for OC 5 through OC 8 and Valley power plant. Although we currently believe that existing technology at the Port Washington Generating Station satisfies the BTA requirements, a final determination will not be made until the discharge permit is renewed for this facility, which is expected to be in the second quarter of 2022. We have received interim BTA determinations for Weston Units 2, 3, and 4. A final BTA decision for the Weston facility is expected during its next permit renewal in late 2023.

As a result of past capital investments completed to address Section 316(b) compliance at WE and WPS, we believe our fleet overall is well positioned to continue to meet this regulation and do not expect to incur significant additional compliance costs.

Steam Electric Effluent Limitation Guidelines

The EPA's final 2015 ELG rule took effect in January 2016 and was modified in 2020 to revise the treatment technology requirements related to BATW and wet FGD wastewaters at existing facilities. This rule created new requirements for several types of power plant wastewaters. The two new requirements that affect WE and WPS relate to discharge limits for BATW and wet FGD wastewater. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. There will, however, need to be facility modifications to meet water permit requirements for the BATW systems at Weston Unit 3 and OC 7 and OC 8. Wastewater treatment system modifications also will be required for wet FGD discharges and site wastewater from the OCPP and ERGS units. Based on engineering cost estimates, we expect that compliance with the ELG rule will require approximately $110 million in capital investment. In February 2021, we applied for PSCW approval of this project.

In July 2021, the EPA announced that it intends to initiate rulemaking to revise the ELG Rule as modified in 2020. The EPA has stated that the ELG Rule will continue to be implemented and enforced while the agency pursues this rulemaking process. The EPA plans to propose a revised rule in the fall of 2022.

Waters of the United States

In September 2021, the EPA and the United States Army Corps of Engineers together announced they have halted implementation of the April 2020 Navigable Waters Protection Rule and are interpreting "Waters of the United States" consistent with the pre-2015 regulatory regime until further notice. The pre-2015 approach involves applying factors established through case law and agency precedents to determine whether a wetland or surface drainage feature is subject to federal jurisdiction. We continue to move forward on company projects subject to federal permits and will monitor these actions to better understand potential future impacts.

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.

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In addition, we are coordinating the investigation and cleanup of some of these sites subject to the jurisdiction of the EPA under what is called a "multisite" program. This program involves prioritizing the work to be done at the sites, preparation and approval of documents common to all of the sites, and use of a consistent approach in selecting remedies. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below.

The future costs for detailed site investigation, future remediation, and monitoring are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation. Historically, our regulators have allowed us to recover incurred costs, net of insurance recoveries and recoveries from potentially responsible parties, associated with the remediation of manufactured gas plant sites. Accordingly, we have established regulatory assets for costs associated with these sites.

We have established the following regulatory assets and reserves for manufactured gas plant sites:

(in millions)						September 30, 2021						December 31, 2020
Regulatory assets						$	601.9					$	638.2
Reserves for future environmental remediation						510.3						532.9

Enforcement and Litigation Matters

We and our subsidiaries are involved in legal and administrative proceedings before various courts and agencies with respect to matters arising in the ordinary course of business. Although we are unable to predict the outcome of these matters, management believes that appropriate reserves have been established and that final settlement of these actions will not have a material impact on our financial condition or results of operations.

Consent Decrees

Wisconsin Public Service Corporation – Weston and Pulliam Power Plants

In November 2009, the EPA issued an NOV to WPS, which alleged violations of the CAA's New Source Review requirements relating to certain projects completed at the Weston and Pulliam power plants from 1994 to 2009. WPS entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Eastern District of Wisconsin in March 2013. With the retirement of Pulliam Units 7 and 8 in October 2018, WPS completed the mitigation projects required by the Consent Decree and received a completeness letter from the EPA in October 2018. We are working with the EPA on a closeout process for the Consent Decree.

Joint Ownership Power Plants – Columbia and Edgewater

In December 2009, the EPA issued an NOV to Wisconsin Power and Light Company, the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including Madison Gas and Electric, WE (former co-owner of an Edgewater unit), and WPS. The NOV alleged violations of the CAA's New Source Review requirements related to certain projects completed at those plants. WPS, along with Wisconsin Power and Light Company, Madison Gas and Electric, and WE, entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Western District of Wisconsin in June 2013. As a result of the continued implementation of the Consent Decree related to the jointly owned Columbia and Edgewater plants, the Edgewater 4 generating unit was retired in September 2018. Wisconsin Power and Light Company has started the process to close out this Consent Decree.

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NOTE 21—SUPPLEMENTAL CASH FLOW INFORMATION

						Nine Months Ended September 30
(in millions)						2021						2020
Cash paid for interest, net of amount capitalized						$	310.9					$	332.4
Cash paid for income taxes, net						33.8						27.6
Significant non-cash investing and financing transactions:
Accounts payable related to construction costs						144.0						177.8
Increase in receivable related to insurance proceeds for property damage (1)						58.3						—

(1)See Note 6, Property, Plant, and Equipment, for information about a steam incident at WE's PSB.

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 consists of cash on deposit in financial institutions that is restricted to satisfy the requirements of certain debt agreements at WECI Wind Holding I and WEPCo Environmental Trust. The restricted cash we received when WECI acquired ownership interests in certain wind generation projects is included in our restricted cash as well. This cash is restricted as it can only be used to pay for any remaining costs associated with the construction of the wind generation facilities.

The following table reconciles the cash, cash equivalents, and restricted cash amounts reported within the balance sheets to the total of these amounts shown on the statements of cash flows:

(in millions)						September 30, 2021						December 31, 2020
Cash and cash equivalents						$	26.0					$	24.8
Restricted cash included in other current assets						36.4						—
Restricted cash included in other long term assets						46.8						47.8
Cash, cash equivalents, and restricted cash						$	109.2					$	72.6

NOTE 22—REGULATORY ENVIRONMENT

Recovery of Natural Gas Costs

Due to the cold temperatures, wind, snow, and ice throughout the central part of the country during February 2021, the cost of gas purchased for our natural gas utility customers was temporarily driven significantly higher than our normal winter weather expectations. All of our utilities have regulatory mechanisms in place for recovering all prudently incurred gas costs.

On March 23, 2021, WE and WG requested approval from the PSCW to recover approximately $54 million and $24 million, respectively, of natural gas costs in excess of the benchmark set in their GCRMs. On March 30, 2021, the PSCW approved the requests and both WE and WG recovered these excess costs over a period of three months, beginning in April 2021. In March 2021, WPS also filed its revised natural gas rate sheets with the PSCW reflecting approximately $28 million of natural gas costs in excess of the benchmark set in its GCRM. WPS recovered these excess costs over a period of three months, beginning in April 2021.

PGL and NSG incurred approximately $131 million and $10 million, respectively, of natural gas costs in February 2021 in excess of the amounts included in their rates. These costs are being recovered over a period of 12 months, which started on April 1, 2021. PGL's and NSG's natural gas costs will be reviewed for prudency by the ICC as part of their annual natural gas cost reconciliation, which we expect to file with the ICC in April 2022.

In February 2021, MERC incurred approximately $75 million of natural gas costs in excess of the benchmark set in its GCRM. In July 2021, MERC and four other Minnesota utilities filed a joint proposal with the MPUC to recover their respective excess natural gas costs. Under the proposal, MERC will recover $10 million of these costs through its annual natural gas true-up process over a period of 12 months, and the remaining $65 million over 27 months, both beginning in September 2021. On August 30, 2021, the MPUC issued a written order approving this proposal; however, recovery of these costs and the issue of prudence has been referred to a contested-case proceeding. As a result of the proceeding, the MPUC could disallow recovery or order the refund of any costs determined to be imprudent. A decision regarding this review is expected in August 2022.

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Natural gas costs incurred at MGU and UMERC in excess of the amount included in their respective rates were not significant.

Coronavirus Disease – 2019

The global outbreak of COVID-19 was declared a pandemic by the WHO and the CDC. COVID-19 has spread globally, including throughout the United States and, in turn, our service territories. Each of the states in which our regulated utilities operate declared a public health emergency and issued shelter-in-place orders in response to the COVID-19 pandemic. All of the shelter-in-place orders have since expired or been lifted. The PSCW, the ICC, the MPUC, and the MPSC all issued written orders requiring certain actions to ensure that essential utility services were available to customers in their respective jurisdictions. A summary of these orders is included below.

Wisconsin

In March 2020, the PSCW issued two orders in response to the COVID-19 pandemic. The first order required all public utilities in the state of Wisconsin, including WE, WPS, and WG, to temporarily suspend disconnections, the assessment of late fees, and deposit requirements for all customer classes. In addition, it required utilities to reconnect customers that were previously disconnected, offer deferred payment arrangements to all customers, and streamline the application process for customers applying for utility service.

In the second order issued in March 2020, the PSCW authorized Wisconsin utilities to defer expenditures and certain foregone revenues resulting from compliance with the first order, and expenditures as otherwise incurred to ensure safe, reliable, and affordable access to utility services during the declared public health emergency. The PSCW affirmed that this authorization for deferral includes the incremental increase in uncollectible expense above what is currently being recovered in rates. As WE, WPS, and WG already have a cost recovery mechanism in place to recover uncollectible expense for residential customers, this new deferral only impacts the recovery of uncollectible expense for their commercial and industrial customers. See Note 4, Credit Losses, for information regarding changes to our allowance for credit losses. As of September 30, 2021, the total amount deferred at our Wisconsin utilities related to the COVID-19 pandemic was not significant. The PSCW will review the recoverability and examine the prudency of any deferred amounts in future rate proceedings.

In June 2020, the PSCW issued a written order providing a timeline for the lifting of the temporary provisions required in the first March 2020 order. Utilities were allowed to disconnect commercial and industrial customers and require deposits for new service as of July 25, 2020 and July 31, 2020, respectively. After August 15, 2020, utilities were no longer required to offer deferred payment arrangements to all customers. Additionally, utilities were authorized to reinstate late fees except for the period between the first order and this supplemental order. Our Wisconsin utilities resumed charging late payment fees in late August 2020. Late payment fees were not charged on outstanding balances that were billed between the first order and late August 2020.

Subsequent to the June 2020 order, the PSCW extended the moratorium on disconnections of residential customers until November 1, 2020. In accordance with Wisconsin regulations, utilities are generally not allowed to disconnect residential customers for non-payment during the winter moratorium, which began on November 1, 2020 and ended on April 15, 2021. Utilities were allowed to continue assessing late payment fees during the winter moratorium. On April 5, 2021, the PSCW issued a written order indicating that it would not extend the moratorium on disconnections further; therefore, utilities could begin disconnecting residential customers for non-payment after April 15, 2021. Utilities are required to offer a deferred payment arrangement to low-income residential customers prior to disconnecting service. The order also allowed our Wisconsin utilities to resume charging late payment fees on the full balance of all outstanding arrears, regardless of the associated dates the service was provided, after April 15, 2021.

Illinois

In March 2020, the ICC issued an order to all Illinois utilities, including PGL and NSG, requiring, among other things, a moratorium on disconnections of utility service and a suspension of late fees and penalties during the declared public health emergency. These provisions applied to all utility customer classes. Illinois utilities were also required to temporarily enact more flexible credit and collections procedures.

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In June 2020, the ICC issued a written order approving a settlement agreement negotiated by Illinois utilities, ICC staff, and certain intervenors. The key terms of the settlement agreement included the following:

• The moratorium on disconnections and the suspension of late fees and penalties were extended until July 26, 2020.

• Customers disconnected after June 18, 2019 could be reconnected without being assessed a reconnection fee if reconnection was requested prior to August 25, 2020.

• Flexible deferred payment arrangements were required to be offered to residential and commercial and industrial customers for an extended period of time and with reduced down payment requirements.

• Deposit requirements were waived until August 25, 2020 for all residential customers, and were waived for an additional four months for residential customers that verbally expressed financial hardship.

• PGL and NSG were required to establish a bill payment assistance program with approximately $12.0 million and $1.2 million, respectively, available for eligible residential customers to provide relief from high arrearages.

In addition to the above, the settlement agreement approved in June 2020 authorized PGL and NSG to implement a SPC rider for the recovery of incremental direct costs resulting from COVID-19, foregone late fees and reconnection charges, and the costs associated with their bill payment assistance programs. PGL and NSG began recovering costs under the SPC rider on October 1, 2020. Amounts deferred under the SPC rider are being recovered over 36 months and will be subject to review and reconciliation by the ICC. As of September 30, 2021, PGL's and NSG's regulatory assets related to the COVID-19 pandemic were $25.3 million, collectively.

Subsequent to the approval of the June 2020 settlement agreement, and at the request of the ICC, PGL and NSG agreed to extend the moratorium on disconnections for qualified low-income residential customers and residential customers expressing financial hardship through March 31, 2021. The annual winter moratorium in Illinois that generally prohibits PGL and NSG from disconnecting residential customers for non-payment began on December 1, 2020 and ended on March 31, 2021.

In March 2021, the ICC issued a written order approving a second settlement agreement negotiated by Illinois utilities, ICC staff, and certain intervenors. The key terms of this new settlement agreement were as follows:

• Utilities could start sending disconnection notices, on a staggered basis, as of April 1, 2021. Disconnections were done on a staggered schedule based on customer arrears and income levels (e.g. low income versus non-low income customers). Utilities were not allowed to disconnect customers for non-payment prior to June 30, 2021 if the customer's household income was below 300% of the federal poverty level and the customer was on a deferred payment plan.

• Utilities were required to continue offering flexible deferred payment arrangements with reduced down payment requirements to residential customers through June 30, 2021.

• Reconnection fees were waived for eligible low income customers through June 30, 2021. In addition, utilities will continue to exempt eligible low income customers from late payment fees and deposits.

• Each utility was required to continue, or renew, its bill payment assistance program through 2021. In addition to the $12.0 million PGL initially funded, PGL was required to fund an additional $6.0 million to its bill payment assistance program. No additional funding was required for NSG due to the amount still available for assistance from its initial funding. During April 2021, PGL's bill payment assistance program ended as all $18.0 million of funds were exhausted. NSG's bill payment assistance program ended in August 2021 when its funds were exhausted.

• Costs related to the provisions in the settlement agreement, including costs related to the bill payment assistance programs, are recoverable through the SPC rider.

Minnesota

In May 2020, the MPUC issued a written order authorizing Minnesota utilities, including MERC, to track and defer COVID-19 related expenses and certain foregone revenues. The MPUC will review the recoverability and examine the prudency of any deferred amounts in future rate proceedings. As of September 30, 2021, amounts deferred at MERC related to the COVID-19 pandemic were not significant.

In June 2020, the MPUC verbally ordered Minnesota utilities to temporarily suspend disconnections and waive reconnection fees, service deposits, late fees, interest, and penalties for all residential customers. In addition, utilities were required to immediately reconnect residential customers that were previously disconnected. In August 2020, the MPUC issued a written order affirming these temporary provisions. Prior to the June 2020 verbal order issued by the MPUC, MERC had voluntarily taken actions to ensure its customers continued to receive utility services during the pandemic. These actions included, but were not limited to, temporarily

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suspending disconnections and waiving late payment fees for residential and small commercial and industrial customers that entered into payment plans.

In March 2021, the MPUC issued an order requiring Minnesota utilities to file a transition plan to resume collections and disconnections upon the earlier of an Executive Secretary finding the transition plan was complete, or 90 days following the expiration of Minnesota's declared peacetime emergency. MERC filed its transition plan in April 2021, and it was subsequently deemed complete by the Executive Secretary. In accordance with the transition plan, MERC resumed disconnections on August 2, 2021. MERC will not disconnect residential customers with past due balances if the customer has a pending application or has been deemed eligible for a financial assistance program. In addition, MERC will continue to offer flexible deferred payment arrangements to residential customers. For customers who enter, or are complying with, a payment arrangement, MERC will not impose any service deposits, down payments, interest, late payment fees, or reconnections fees through April 30, 2022.

Michigan

In April 2020, the MPSC issued a written order requiring Michigan utilities, including MGU and UMERC, to put certain minimum protections in place during the COVID-19 pandemic. The minimum protections required by the order included the suspension of disconnections, late payment fees, deposits, and reconnection fees for certain vulnerable customers. In addition, utilities were required to extend access to and enhance the flexibility of payment plans to customers financially impacted by COVID-19.

As required in the MPSC order, MGU and UMERC filed responses with the MPSC in April 2020 affirming the actions being taken to protect customers. These actions provided protections to more customers than required by the MPSC order, and included suspending disconnections for all residential customers, waiving deposit requirements for new service, suspending the assessment of late fees for customers that entered into payment plans, and enhancing payment plan options for all customers.

The April 2020 MPSC order also authorized all Michigan utilities to defer, for potential future recovery, uncollectible expense incurred on or after March 24, 2020 that exceeded the amounts being recovered in rates. In July 2020, the MPSC issued an order denying Michigan utilities' ability to defer additional COVID-19 related expenses and certain foregone revenues. The MPSC indicated that utilities could still seek recovery of these costs and foregone revenues by filing additional information on the specifics of their request. MGU and UMERC filed comments with the MPSC in November 2020 indicating they had not experienced any material additional COVID-19 related expenses or foregone revenues, but will continue to monitor them and will notify the MPSC if they become material. At September 30, 2021, our Michigan utilities had not recorded any deferrals related to the COVID-19 pandemic.

In June 2021, MGU and UMERC worked with MPSC staff to develop a transition plan to resume collections and disconnections, while continuing to assist customers in managing their arrears balances. In accordance with the agreed upon transition plan, MGU and UMERC resumed pre-pandemic collection activities and residential service disconnections on August 2, 2021. Flexible deferred payment arrangements will continue to be available to customers.

Wisconsin Electric Power Company, Wisconsin Public Service Corporation, and Wisconsin Gas LLC

2022 Rates

In March 2021, WE, WPS, and WG filed an application with the PSCW for the approval of certain accounting treatments that will allow them to maintain their current electric, natural gas, and steam base rates through 2022 and forego filing a rate case for one year. In connection with the request, the three utilities also entered into an agreement, dated March 23, 2021, with various stakeholders. Pursuant to the terms of the agreement, the stakeholders fully supported the application. On September 22, 2021, the PSCW issued written orders approving the application.

The final orders reflect the following:

• WE, WPS, and WG will amortize, in 2022, certain previously deferred balances to offset approximately half of their forecasted revenue deficiencies.

• WG will defer interest and depreciation expense associated with capital investments since its last rate case that otherwise would have been added to rate base in a 2022 test-year rate case.

• WE, WPS, and WG are allowed to defer any increases in tax expense due to changes in tax law that occur in 2021 and/or 2022.

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• WE, WPS, and WG will maintain their earnings sharing mechanisms for 2022, with modification. The earnings sharing mechanisms will be modified to authorize the utility to retain 100% of the first 15 basis points of earnings above its currently authorized ROE. This modification expires on December 31, 2022. The earnings sharing mechanisms will otherwise remain as currently authorized.

• WE, WPS, and WG will file a full 2023-2024 test-year rate case no later than May 1, 2022.

2020 and 2021 Rates

In March 2019, WE, WPS, and WG filed applications with the PSCW to increase their retail electric, natural gas, and steam rates, as applicable, effective January 1, 2020. In August 2019, all three utilities filed applications with the PSCW for approval of settlement agreements entered into with certain intervenors to resolve several outstanding issues in each utility's respective rate case. In December 2019, the PSCW issued written orders that approved the settlement agreements without material modification and addressed the remaining outstanding issues that were not included in the settlement agreements. The new rates became effective January 1, 2020. The final orders reflect the following:

						WE												WPS												WG
2020 Effective rate increase (decrease)
Electric (1) (2)						$	15.3	million	/			0.5%						$	15.8	million	/			1.6%						N/A
Gas (3)						$	10.4	million	/			2.8%						$	4.3	million	/			1.4%						$	(1.5)	million	/			(0.2)%
Steam						$	1.9	million	/			8.6%						N/A												N/A
ROE						10.0%												10.0%												10.2%
Common equity component average on a financial basis						52.5%												52.5%												52.5%

(1)Amounts are net of certain deferred tax benefits from the Tax Legislation that were utilized to reduce near-term rate impact. The WE and WPS rate orders reflect the majority of the unprotected deferred tax benefits from the Tax Legislation being amortized over two years. For WE, approximately $65 million of tax benefits will be amortized in each of 2020 and 2021. For WPS, approximately $11 million of tax benefits were amortized in 2020 and approximately $39 million are being amortized in 2021. The unprotected deferred tax benefits related to the unrecovered balances of certain of WE's retired plants and its SSR regulatory asset were used to reduce the related regulatory asset. Unprotected deferred tax benefits by their nature are eligible to be returned to customers in a manner and timeline determined to be appropriate by our regulators.

(2)The WPS rate order is net of $21 million of refunds related to its 2018 earnings sharing mechanism. These refunds are being made to customers evenly over two years, with half returned in 2020 and the remainder being returned in 2021.

(3)The WE amount includes certain deferred tax expense from the Tax Legislation, and the WPS and WG amounts are net of certain deferred tax benefits from the Tax Legislation that were utilized to reduce near-term rate impact. The rate orders for all three gas utilities reflect all of the unprotected deferred tax expense and benefits from the Tax Legislation being amortized evenly over four years. For WE, approximately $5 million of previously deferred tax expense will be amortized each year. For WPS and WG, approximately $5 million and $3 million, respectively, of previously deferred tax benefits will be amortized each year. Unprotected deferred tax expense and benefits by their nature are eligible to be recovered from or returned to customers in a manner and timeline determined to be appropriate by our regulators.

In accordance with its rate order, WE filed an application with the PSCW in July 2020 requesting a financing order to securitize $100 million of Pleasant Prairie power plant's book value, plus the carrying costs accrued on the $100 million during the securitization process and related financing fees. In November 2020, the PSCW issued a written order approving the application. The financing order also authorized WE to form a bankruptcy-remote special purpose entity, WEPCo Environmental Trust, for the sole purpose of issuing ETBs to recover the approved costs. In May 2021, WEPCo Environmental Trust issued $118.8 million of 1.578% ETBs due December 15, 2035. See Note 9, Long-Term Debt, for more information regarding the issuance of the ETBs. See Note 19, Variable Interest Entities, for more information regarding WEPCo Environmental Trust.

The WPS rate order allows WPS to collect the previously deferred revenue requirement for ReACT™ costs above the authorized $275.0 million level. The total cost of the ReACT™ project was $342 million. This regulatory asset will be collected from customers over eight years.

The PSCW approved all three Wisconsin utilities continuing to have an earnings sharing mechanism through 2021. The earnings sharing mechanism was modified from its previous structure to one that is consistent with other Wisconsin investor-owned utilities. Under this earnings sharing mechanism, if the utility earns above its authorized ROE: (i) the utility retains 100.0% of earnings for the

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first 25 basis points above the authorized ROE; (ii) 50.0% of the next 50 basis points is refunded to customers; and (iii) 100.0% of any remaining excess earnings is refunded to customers. In addition, the rate orders also require WE, WPS, and WG to maintain residential and small commercial electric and natural gas customer fixed charges at previously authorized rates and to maintain the status quo for WE's and WPS's electric market-based rate programs for large industrial customers through 2021.

The Peoples Gas Light and Coke Company and North Shore Gas Company

Third-Party Transaction Fee Adjustment Rider

On October 27, 2021, PGL and NSG filed requests with the ICC for approval of a TPTFA rider. In accordance with the Climate and Equitable Jobs Act that was signed into law in Illinois, effective September 15, 2021, utilities are prohibited from charging customers a fee when they elect to pay for service with a credit card. Utilities are now required to incur these expenses. The proposed TPTFA rider would allow PGL and NSG to recover the third-party transaction fee expenses they are now incurring. If approved, the TPTFA rider would be effective for expenses incurred back to September 15, 2021. Amounts deferred under the rider would be recovered over a period of 12 months and would be subject to an annual reconciliation whereby costs would be reviewed by the ICC for accuracy and prudency. We expect a decision from the ICC in 2022.

North Shore Gas Company 2021 Rate Case

In October 2020, NSG filed a request with the ICC to increase its natural gas rates. On September 8, 2021, the ICC issued a written order authorizing a rate increase of $4.1 million (4.5%). The rate increase reflects a 9.67% ROE and a common equity component average of 51.58%. The natural gas rate increase is primarily driven by NSG's ongoing significant investment in its distribution system since its last rate review that resulted in revised base rates effective January 28, 2015. The new rates were effective September 15, 2021.

Qualifying Infrastructure Plant Rider

In July 2013, Illinois Public Act 98-0057, The Natural Gas Consumer, Safety & Reliability Act, became law. This law provides natural gas utilities with a cost recovery mechanism that allows collection, through a surcharge on customer bills, of prudently incurred costs to upgrade Illinois natural gas infrastructure. In January 2014, the ICC approved a QIP rider for PGL, which is in effect through 2023.

PGL's QIP rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. In March 2021, PGL filed its 2020 reconciliation with the ICC, which, along with the 2019, 2018, 2017, and 2016 reconciliations, are still pending.

As of September 30, 2021, there can be no assurance that all costs incurred under PGL's QIP rider during the open reconciliation years will be deemed recoverable by the ICC.

Michigan Gas Utilities Corporation

2021 Rate Application

In February 2020, MGU provided notification to the MPSC of its intent to file an application requesting an increase to MGU's natural gas rates to be effective January 1, 2021. However, MGU decided that it would delay its filing of the rate case as a result of the COVID-19 pandemic.

In May 2020, MGU filed an application with the MPSC requesting approval to defer $5.0 million of depreciation and interest expense during 2021 related to capital investments made by MGU since its last rate case. In July 2020, the MPSC issued a written order approving MGU's request. The deferral of these costs are helping to mitigate the impacts from delaying the filing of the rate case.

In March 2021, MGU filed its request with the MPSC to increase its natural gas rates. In July 2021, MGU filed with the MPSC, a settlement agreement it reached with certain intervenors, which the MPSC approved in a written order on September 9, 2021. The order authorizes a rate increase of $9.3 million (6.35%) and reflects a 9.85% ROE and a common equity component average of 51.5%. The natural gas rate increase was primarily driven by MGU's significant investment in capital infrastructure since its last rate review that resulted in revised base rates effective January 1, 2016. The order also allows MGU to implement a rider for its Main Replacement Program that will support recovery of planned capital investment related to pipeline replacements to maintain system

09/30/2021 Form 10-Q			44			WEC Energy Group, Inc.

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safety and reliability between 2023 and 2027, without having to file a rate case. We expect approximately $31.7 million of costs to be recovered through this rider. All costs recovered through the rider are subject to prudence review by the MPSC. New rates will be effective January 1, 2022.

NOTE 23—NEW ACCOUNTING PRONOUNCEMENTS

Simplifying the Accounting for Income Taxes

In December 2019, the FASB issued ASU 2019-12, Simplifying the Accounting for Income Taxes. The new standard removes certain exceptions for performing intraperiod allocation and calculating income taxes in interim periods and also adds guidance to reduce complexity in certain areas, including recognizing deferred taxes for tax goodwill and allocating taxes to members of a consolidated group. The guidance was effective for annual and interim periods beginning after December 15, 2020. The adoption of ASU 2019-12, effective January 1, 2021, did not have a significant impact on our financial statements and related disclosures.

Reference Rate Reform

In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met. The amendments apply only to contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform. The amendments are effective for all entities as of March 12, 2020 through December 31, 2022. We are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

09/30/2021 Form 10-Q			45			WEC Energy Group, Inc.

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