UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

(Mark One)


☒			QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, ~~2022~~2023


☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ________________ to ___________________

Commission
File Number

Registrant; State of Incorporation;
Address; and Telephone Number

IRS Employer
Identification No.

001-01245

WISCONSIN ELECTRIC POWER COMPANY

39-0476280

(A Wisconsin Corporation)

231 West Michigan Street

P.O. Box 2046

Milwaukee, WI 53201

(414) 221-2345

Securities registered pursuant to Section 12(b) of the Act:

None

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer

☐

Accelerated filer

☐

Non-accelerated filer

☒

Smaller reporting company

☐

Emerging growth company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ☐ No ☒

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date:

Common Stock, $10 Par Value,

33,289,327 shares outstanding at

June 30, ~~2022~~2023

All of the common stock of Wisconsin Electric Power Company is held by WEC Energy Group, Inc.

Table of Contents

WISCONSIN ELECTRIC POWER COMPANY

QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended June 30, ~~2022~~2023

TABLE OF CONTENTS

Page

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

PART I.

FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS (UNAUDITED)

Condensed Consolidated Income Statements

Condensed Consolidated Balance Sheets

Condensed Consolidated Statements of Cash Flows

Condensed Consolidated Statements of Equity

Notes to Condensed Consolidated Financial Statements

Page

Note 1

General Information

Note 2

~~Acquisition~~Acquisitions

Regulatory Assets and Liabilities

Note 67

Property, Plant, and Equipment

Note 78

~~Common Equity~~Jointly Owned Utility Facilities

Note 89

Common Equity

Note 10

Short-Term Debt and Lines of Credit

Note 911

Leases

Note 1012

Materials, Supplies, and Inventories

Note 1113

Income Taxes

Note 1214

Fair Value Measurements

Note 1315

Derivative Instruments

Variable Interest Entities

Note 1820

Commitments and Contingencies

Note 1921

Supplemental Cash Flow Information

2324

Note 2022

Regulatory Environment

Note 2123

New Accounting Pronouncements

ITEM 2.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

4443

ITEM 4.

CONTROLS AND PROCEDURES


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GLOSSARY OF TERMS AND ABBREVIATIONS

The abbreviations and terms set forth below are used throughout this report and have the meanings assigned to them below:


Affiliates
ATC


						American Transmission Company LLC
We Power						W.E. Power, LLC
WEC Energy Group						WEC Energy Group, Inc.
WEPCo Environmental Trust						WEPCo Environmental Trust Finance I, LLC

WPS						Wisconsin Public Service Corporation

Federal and State Regulatory Agencies
Army Corps						United States Army Corps of Engineers
CBP						United States Customs and Border Protection Agency
DOC						United States Department of Commerce
EPA						United States Environmental Protection Agency
FERC

						Federal Energy Regulatory Commission
PSCW						Public Service Commission of Wisconsin
SEC						United States Securities and Exchange Commission
WDNR						Wisconsin Department of Natural Resources

Accounting Terms
AFUDC						Allowance for Funds Used During Construction

ASU						Accounting Standards Update
FASB						Financial Accounting Standards Board
GAAP						United States Generally Accepted Accounting Principles
OPEB						Other Postretirement Employee Benefits
VIE						Variable Interest Entity

Environmental Terms
~~ACE~~						~~Affordable Clean Energy~~
BATW						Bottom Ash Transport Water

BTA						Best Technology Available
~~CAA~~						~~Clean Air Act~~
CASAC						Clean Air Scientific Advisory Committee
CCR						Coal Combustion Residuals
CO2						Carbon Dioxide
CWA						Clean Water Act
ELG						Steam Electric Effluent Limitation Guidelines
FGD						Flue Gas Desulfurization
GHG						Greenhouse Gas
LDC						Local Distribution Company
MATS						Mercury and Air Toxics Standards
NAAQS						National Ambient Air Quality Standards
NOx						Nitrogen Oxide
PM						Particulate Matter
WOTUS						Waters of the United States
WPDES						Wisconsin Pollutant Discharge Elimination System
ZLD						Zero Liquid Discharge

Measurements
Dth						Dekatherm
lb/MMBtu						Pound Per Million British Thermal Unit
MW						Megawatt
MWh						~~Megawatt-hour~~Megawatt-hours
µg/m3						Micrograms Per Cubic Meter

~~Other Terms and Abbreviations~~
~~AD/CVD~~						~~Antidumping and Countervailing Duties~~
~~AMI~~						~~Advanced Metering Infrastructure~~
~~Badger Hollow II~~						~~Badger Hollow Solar Park II~~

~~Chicago, IL-IN-WI~~						~~Chicago, Illinois, Indiana, and Wisconsin~~
~~COVID-19~~						~~Coronavirus Disease – 2019~~
~~D.C. Circuit Court of Appeals~~						~~United States Court of Appeals for the District of Columbia Circuit~~


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Other Terms and Abbreviations

AMI						Advanced Metering Infrastructure
Badger Hollow II						Badger Hollow Solar Park II
Chicago, IL-IN-WI						Chicago, Illinois, Indiana, and Wisconsin


Darien						Darien Solar-Battery Park
~~EGU~~DER						~~Electric Generating Unit~~Distributed Energy Resource
DRER						Dedicated Renewable Energy Resource


ERGS						Elm Road Generating Station


ESG Progress Plan						WEC Energy Group's Capital Investment Plan for Efficiency, Sustainability, and Growth for ~~2022-2026~~2023-2027
ETB						Environmental Trust Bond
EV						Electric Vehicle
Exchange Act						Securities Exchange Act of 1934, as amended
~~Executive Order 13990~~						~~Executive Order 13990 of January 20, 2021 – Protecting Public Health and the Environment and Restoring Science To Tackle the Climate Crisis~~
FTR						Financial Transmission Right
IRA						Inflation Reduction Act
ITC						Investment Tax Credit
Koshkonong						Koshkonong Solar-Battery Park
LIBOR						London Interbank Offered Rate
LNG						Liquefied Natural Gas
MISO						Midcontinent Independent System Operator, Inc.

OCPP						Oak Creek Power Plant


OC 7						Oak Creek Power Plant Unit 7
OC 8						Oak Creek Power Plant Unit 8
~~Paris~~						~~Paris Solar-Battery Park~~

PPA						Power Purchase Agreement
~~PSB~~						~~Public Service Building~~




PTC						Production Tax Credit
PWGS						Port Washington Generating Station
~~RNG~~						~~Renewable Natural Gas~~
RICE						Reciprocating Internal Combustion Engine
~~ROE~~RNG						~~Return on Equity~~Renewable Natural Gas

S&P						Standard & Poor's
SIP						State Implementation Plan
Supreme Court						United States Supreme Court
Tax Legislation						Tax Cuts and Jobs Act of 2017
UFLPA						Uyghur Forced Labor Prevention Act
West Riverside						West Riverside Energy Center
Whitewater						Whitewater Cogeneration Facility
WRO						Withhold Release Order
WUA						Wisconsin Utilities Association


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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

In this report, we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, and future events or performance. These statements are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act. Readers are cautioned not to place undue reliance on these forward-looking statements. Forward-looking statements may be identified by reference to a future period or periods or by the use of terms such as "anticipates," "believes," "could," "estimates," "expects," "forecasts," "goals," "guidance," "intends," "may," "objectives," "plans," "possible," "potential," "projects," "seeks," "should," "targets," "will," or variations of these terms.

Forward-looking statements include, among other things, statements concerning management's expectations and projections regarding earnings, completion of capital projects, sales and customer growth, rate actions and related filings with regulatory authorities, environmental and other regulations, including associated compliance costs, legal proceedings, effective tax rates, pension and OPEB plans, fuel costs, sources of electric energy supply, coal and natural gas deliveries, remediation costs, climate-related matters, the ESG Progress Plan, liquidity and capital resources, and other matters.

Forward-looking statements are subject to a number of risks and uncertainties that could cause our actual results to differ materially from those expressed or implied in the statements. These risks and uncertainties include those described in risk factors as set forth in our ~~2021~~2022 Annual Report on Form 10-K, and those identified below:

•Factors affecting utility operations such as catastrophic weather-related damage, environmental incidents, unplanned facility outages and repairs and maintenance, and electric transmission or natural gas pipeline system constraints;

•Factors affecting the demand for electricity and natural gas, including political or regulatory developments, varying, adverse, or unusually severe weather conditions, including those caused by climate change, changes in economic conditions, customer growth and declines, commodity prices, energy conservation efforts, and continued adoption of distributed generation by customers;

•The timing, resolution, and impact of rate cases and negotiations, including recovery of deferred and current costs and the ability to earn a reasonable return on investment, and other regulatory decisions impacting our regulated operations;

•The impact of federal, state, and local legislative and/or regulatory changes, including changes in rate-setting policies or procedures, deregulation and restructuring of the electric and/or natural gas utility industries, transmission or distribution system operation, the approval process for new construction, reliability standards, pipeline integrity and safety standards, allocation of energy assistance, energy efficiency mandates, electrification initiatives and other efforts to reduce the use of natural gas, and tax laws, including those that affect our ability to use PTCs and ITCs;

•Federal, state, and local legislative and regulatory changes relating to the environment, including climate change and other environmental regulations impacting generation facilities and renewable energy standards, the enforcement of these laws and regulations, changes in the interpretation of regulations or permit conditions by regulatory agencies, and the recovery of associated remediation and compliance costs;

•The ability to obtain and retain customers, including wholesale customers, due to increased competition in our electric and natural gas markets from retail choice and alternative electric suppliers, and continued industry consolidation;

•The timely completion of capital projects within budgets and the ability to recover the related costs through rates;

•The impact of changing expectations and demands of our customers, regulators, investors, and other stakeholders, including heightened emphasis on environmental, social, and governance concerns;

•The risk of delays and shortages, and increased costs of equipment, materials, or other resources that are critical to our business operations and corporate strategy, as a result of supply chain disruptions (including disruptions from rail congestion), inflation, and other factors;

•The impact of public health ~~pandemics,~~crises, including ~~any new developments relating to the COVID-19 pandemic,~~epidemics and pandemics, on our business functions, financial condition, liquidity, and results of operations;

•Factors affecting the implementation of WEC Energy Group's CO2 emission and/or methane emission reduction goals and opportunities and actions related to those goals, including related regulatory decisions, the cost of materials, supplies, and labor,


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technology advances, the feasibility of competing generation projects, and the ability to execute WEC Energy Group's capital plan;

•The financial and operational feasibility of taking more aggressive action to further reduce GHG emissions in order to limit future global temperature increases;

•The risks associated with inflation and changing commodity prices, including natural gas and electricity;

•The availability and cost of sources of natural gas and other fossil fuels, purchased power, materials needed to operate environmental controls at our electric generating facilities, or water supply due to high demand, shortages, transportation problems, nonperformance by electric energy or natural gas suppliers under existing power purchase or natural gas supply contracts, or other developments;

•Any impacts on the global economy, supply chains and fuel prices, generally, from the ongoing conflict between Russia and Ukraine and related sanctions;

•Changes in credit ratings, interest rates, and our ability to access the capital markets, caused by volatility in the global credit markets, our capitalization structure, and market perceptions of the utility industry or us;

•~~Changes in~~Any impacts associated with switching from LIBOR to Secured Overnight Financing Rate as the ~~method of determining LIBOR or the replacement of LIBOR with an alternative~~ reference ~~rate;~~rate for our variable rate debt;

•Costs and effects of litigation, administrative proceedings, investigations, settlements, claims, and inquiries;

•The direct or indirect effect on our business resulting from terrorist or other physical attacks and cyber security intrusions, as well as the threat of such incidents, including the failure to maintain the security of personally identifiable information, the associated costs to protect our utility assets, technology systems, and personal information, and the costs to notify affected persons to mitigate their information security concerns and to comply with state notification laws;

•The risk of financial loss, including increases in bad debt expense, associated with the inability of our customers, counterparties, and affiliates to meet their obligations;

•Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading markets and fuel suppliers and transporters;

•The investment performance of our employee benefit plan assets, as well as unanticipated changes in related actuarial assumptions, which could impact future funding requirements;

•Factors affecting the employee workforce, including loss of key personnel, internal restructuring, work stoppages, and collective bargaining agreements and negotiations with union employees;

•Advances in technology, and related legislation or regulation supporting the use of that technology, that result in competitive disadvantages and create the potential for impairment of existing assets;

•The risk associated with the value of long-lived assets, including intangible assets, and their possible impairment;

•Potential business strategies to acquire and dispose of assets, which cannot be assured to be completed timely or within budgets;

•The timing and outcome of any audits, disputes, and other proceedings related to taxes;

•The effect of accounting pronouncements issued periodically by standard-setting bodies; and

•Other considerations disclosed elsewhere herein and in other reports we file with the SEC or in other publicly disseminated written documents.

Except as may be required by law, we expressly disclaim any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.


06/30/~~2022~~2023 Form 10-Q			2			Wisconsin Electric Power Company

Table of Contents

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

WISCONSIN ELECTRIC POWER COMPANY


CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited)	CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited)	Three Months Ended				Six Months Ended				CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited)	Three Months Ended				Six Months Ended
		June 30				June 30					June 30				June 30
(in millions)	(in millions)	2022		2021		2022		2021		(in millions)	2023		2022		2023		2022
Operating revenues	Operating revenues	$	943.5	$	827.5	$	2,015.5	$	1,832.7	Operating revenues	$	900.3	$	943.5	$	1,992.2	$	2,015.5

Operating expenses	Operating expenses									Operating expenses
Cost of sales	Cost of sales	385.5		276.4		829.7		680.6		Cost of sales	292.5		385.5		737.0		829.7
Other operation and maintenance	Other operation and maintenance	205.3		213.1		397.9		422.4		Other operation and maintenance	206.0		205.3		438.3		397.9
Depreciation and amortization	Depreciation and amortization	119.7		113.3		238.8		224.0		Depreciation and amortization	129.3		119.7		257.1		238.8
Property and revenue taxes	Property and revenue taxes	26.5		24.7		53.5		50.1		Property and revenue taxes	28.4		26.5		58.3		53.5
Total operating expenses	Total operating expenses	737.0		627.5		1,519.9		1,377.1		Total operating expenses	656.2		737.0		1,490.7		1,519.9

Operating income	Operating income	206.5		200.0		495.6		455.6		Operating income	244.1		206.5		501.5		495.6

Other income, net	Other income, net	11.4		7.3		22.0		14.7		Other income, net	19.0		11.4		34.1		22.0
Interest expense	Interest expense	113.1		116.0		226.5		232.2		Interest expense	116.9		113.1		234.7		226.5
Other expense	Other expense	(101.7)		(108.7)		(204.5)		(217.5)		Other expense	(97.9)		(101.7)		(200.6)		(204.5)

Income before income taxes	Income before income taxes	104.8		91.3		291.1		238.1		Income before income taxes	146.2		104.8		300.9		291.1
Income tax expense	Income tax expense	26.7		12.2		74.2		31.7		Income tax expense	34.3		26.7		67.0		74.2
Net income	Net income	78.1		79.1		216.9		206.4		Net income	111.9		78.1		233.9		216.9

Preferred stock dividend requirements	Preferred stock dividend requirements	0.3		0.3		0.6		0.6		Preferred stock dividend requirements	0.3		0.3		0.6		0.6
Net income attributed to common shareholder	Net income attributed to common shareholder	$	77.8	$	78.8	$	216.3	$	205.8	Net income attributed to common shareholder	$	111.6	$	77.8	$	233.3	$	216.3

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


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WISCONSIN ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)
(in millions, except share and per share amounts)
June 30, 2022 December 31, 2021
Assets
Current assets
Cash and cash equivalents $ 2.0 $ —
Accounts receivable and unbilled revenues, net of reserves of $47.6 and $51.4, respectively 571.0 565.5
Accounts receivable from related parties 92.3 79.1
Materials, supplies, and inventories 258.2 246.4
Prepaid taxes 99.8 97.4
Other prepayments 11.9 24.3
Derivative assets 81.8 48.7
Other 9.1 9.6
Current assets 1,126.1 1,071.0
Long-term assets
Property, plant, and equipment, net of accumulated depreciation and amortization of $5,312.2 and $5,136.4, respectively 10,432.0 10,115.5
Regulatory assets (June 30, 2022 and December 31, 2021 include $96.1 and $100.7, respectively, related to WEPCo Environmental Trust) 2,751.1 2,763.1
Pension and OPEB assets 112.2 96.8
Other 108.1 98.1
Long-term assets 13,403.4 13,073.5
Total assets $ 14,529.5 $ 14,144.5
Liabilities and Equity
Current liabilities
Short-term debt $ 413.8 $ 375.0
Current portion of long-term debt (related to WEPCo Environmental Trust) 8.8 8.8
Current portion of finance lease obligations 109.6 109.3
Accounts payable 402.3 347.8
Accounts payable to related parties 196.4 170.9
Other 195.7 155.6
Current liabilities 1,326.6 1,167.4
Long-term liabilities
Long-term debt (June 30, 2022 and December 31, 2021 include $98.4 and $102.7, respectively, related to WEPCo Environmental Trust) 2,860.1 2,863.3
Finance lease obligations 2,734.0 2,717.9
Deferred income taxes 1,435.1 1,401.6
Regulatory liabilities 1,749.4 1,723.2
Pension and OPEB obligations 37.8 38.8
Other 284.8 287.6
Long-term liabilities 9,101.2 9,032.4
Commitments and contingencies (Note 18) 0 0
Common shareholder's equity
Common stock – $10 par value; 65,000,000 shares authorized; 33,289,327 shares outstanding 332.9 332.9
Additional paid in capital 1,571.7 1,290.9
Retained earnings 2,166.7 2,290.5
Common shareholder's equity 4,071.3 3,914.3
Preferred stock 30.4 30.4
Total liabilities and equity $ 14,529.5 $ 14,144.5


CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (in millions, except share and per share amounts)	June 30, 2023		December 31, 2022
Assets
Current assets
Cash and cash equivalents	$	28.7	$	6.1
Accounts receivable and unbilled revenues, net of reserves of $45.1 and $49.7, respectively	526.0		582.6
Accounts receivable from related parties	110.4		113.2
Materials, supplies, and inventories	255.5		292.9
Prepaid taxes	128.8		113.1
Other prepayments	12.5		25.6
Collateral on deposit	54.2		46.7
Other	10.0		27.1
Current assets	1,126.1		1,207.3

Long-term assets
Property, plant, and equipment, net of accumulated depreciation and amortization of $5,588.5 and $5,450.3, respectively	11,092.1		10,718.6
Regulatory assets (June 30, 2023 and December 31, 2022 include $89.5 and $92.4, respectively, related to WEPCo Environmental Trust)	2,846.6		2,817.5
Pension and OPEB assets	147.8		143.3
Other	82.4		133.5
Long-term assets	14,168.9		13,812.9
Total assets	$	15,295.0	$	15,020.2

Liabilities and Equity
Current liabilities
Short-term debt	$	43.0	$	460.7
Current portion of long-term debt (related to WEPCo Environmental Trust)	9.0		8.9
Current portion of finance lease obligations	81.2		112.3
Accounts payable	291.0		400.5
Accounts payable to related parties	164.2		179.4
Derivative liabilities	52.8		28.8
Customer credit balances	44.8		40.2
Other	113.0		141.5
Current liabilities	799.0		1,372.3

Long-term liabilities
Long-term debt (June 30, 2023 and December 31, 2022 include $89.7 and $94.1, respectively, related to WEPCo Environmental Trust)	3,348.5		3,351.5
Finance lease obligations	2,716.3		2,702.3
Deferred income taxes	1,493.5		1,467.3
Regulatory liabilities	1,627.1		1,637.4

Other	324.5		322.2
Long-term liabilities	9,509.9		9,480.7

Commitments and contingencies (Note 20)

Common shareholder's equity
Common stock – $10 par value; 65,000,000 shares authorized; 33,289,327 shares outstanding	332.9		332.9
Additional paid in capital	2,452.3		1,746.8
Retained earnings	2,170.5		2,057.1
Common shareholder's equity	4,955.7		4,136.8

Preferred stock	30.4		30.4
Total liabilities and equity	$	15,295.0	$	15,020.2

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


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WISCONSIN ELECTRIC POWER COMPANY


CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)	CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)	Six Months Ended				CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)	Six Months Ended
		June 30					June 30
(in millions)	(in millions)	2022		2021		(in millions)	2023		2022
Operating activities	Operating activities					Operating activities
Net income	Net income	$	216.9	$	206.4	Net income	$	233.9	$	216.9
Reconciliation to cash provided by operating activities	Reconciliation to cash provided by operating activities					Reconciliation to cash provided by operating activities
Depreciation and amortization	Depreciation and amortization	238.8		224.0		Depreciation and amortization	257.1		238.8
Deferred income taxes and ITCs, net	Deferred income taxes and ITCs, net	33.5		(14.3)		Deferred income taxes and ITCs, net	14.6		33.5

Change in –	Change in –					Change in –
Accounts receivable and unbilled revenues, net	Accounts receivable and unbilled revenues, net	(29.9)		(37.6)		Accounts receivable and unbilled revenues, net	75.4		(29.9)
Materials, supplies, and inventories	Materials, supplies, and inventories	(11.8)		10.4		Materials, supplies, and inventories	42.2		(11.8)
Prepaid taxes						Prepaid taxes	(15.7)		(2.4)
Other prepayments						Other prepayments	8.5		12.4

Other prepayments		12.4		14.0

Other current assets	Other current assets	(1.3)		9.0		Other current assets	(7.0)		1.1
Accounts payable	Accounts payable	(3.3)		30.3		Accounts payable	(101.0)		(3.3)

Amounts refundable to customers	Amounts refundable to customers	16.8		(1.4)		Amounts refundable to customers	13.0		16.8

Collateral received						Collateral received	—		22.0
Other current liabilities	Other current liabilities	17.9		32.4		Other current liabilities	(36.7)		(4.1)
Other, net	Other, net	(39.5)		0.5		Other, net	(26.0)		(39.5)
Net cash provided by operating activities	Net cash provided by operating activities	450.5		473.7		Net cash provided by operating activities	458.3		450.5

Investing activities	Investing activities					Investing activities
Capital expenditures	Capital expenditures	(419.3)		(387.6)		Capital expenditures	(467.8)		(419.3)
Acquisition of Whitewater						Acquisition of Whitewater	(38.0)		—
Acquisition of West Riverside						Acquisition of West Riverside	(95.3)		—
Proceeds from the sale of assets						Proceeds from the sale of assets	24.2		0.1
Payments for ATC's construction costs that will be reimbursed						Payments for ATC's construction costs that will be reimbursed	(15.9)		(9.0)

Proceeds from assets transferred to affiliates		—		10.7

Insurance proceeds received for property damage	Insurance proceeds received for property damage	41.0		—		Insurance proceeds received for property damage	—		41.0
Other, net	Other, net	(6.2)		3.4		Other, net	(7.4)		2.7
Net cash used in investing activities	Net cash used in investing activities	(384.5)		(373.5)		Net cash used in investing activities	(600.2)		(384.5)

Financing activities	Financing activities					Financing activities
Change in short-term debt	Change in short-term debt	38.8		(90.0)		Change in short-term debt	(417.7)		38.8
Issuance of long-term debt		—		418.8

Retirement of long-term debt	Retirement of long-term debt	(4.4)		(300.0)		Retirement of long-term debt	(4.4)		(4.4)
Payments for finance lease obligations	Payments for finance lease obligations	(37.1)		(32.5)		Payments for finance lease obligations	(37.3)		(37.1)
Equity contribution from parent	Equity contribution from parent	280.0		30.0		Equity contribution from parent	705.0		280.0
Payment of dividends to parent	Payment of dividends to parent	(340.0)		(120.0)		Payment of dividends to parent	(120.0)		(340.0)
Other, net	Other, net	(0.6)		(6.8)		Other, net	(0.6)		(0.6)
Net cash used in financing activities		(63.3)		(100.5)
Net cash provided by (used in) financing activities						Net cash provided by (used in) financing activities	125.0		(63.3)

Net change in cash, cash equivalents, and restricted cash	Net change in cash, cash equivalents, and restricted cash	2.7		(0.3)		Net change in cash, cash equivalents, and restricted cash	(16.9)		2.7
Cash, cash equivalents, and restricted cash at beginning of period	Cash, cash equivalents, and restricted cash at beginning of period	3.0		7.2		Cash, cash equivalents, and restricted cash at beginning of period	47.7		3.0
Cash, cash equivalents, and restricted cash at end of period	Cash, cash equivalents, and restricted cash at end of period	$	5.7	$	6.9	Cash, cash equivalents, and restricted cash at end of period	$	30.8	$	5.7

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


06/30/~~2022~~2023 Form 10-Q			5			Wisconsin Electric Power Company

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WISCONSIN ELECTRIC POWER COMPANY


CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (Unaudited)	CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (Unaudited)													CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (Unaudited)

		Wisconsin Electric Power Company Common Shareholder's Equity													Wisconsin Electric Power Company Common Shareholder's Equity
(in millions)	(in millions)	Common Stock		Additional Paid In Capital		Retained Earnings		Total Common Shareholder's Equity		Preferred Stock		Total Equity		(in millions)	Common Stock		Additional Paid In Capital		Retained Earnings		Total Common Shareholder's Equity		Preferred Stock		Total Equity
Balance at December 31, 2021		$	332.9	$	1,290.9	$	2,290.5	$	3,914.3	$	30.4	$	3,944.7
Balance at December 31, 2022														Balance at December 31, 2022	$	332.9	$	1,746.8	$	2,057.1	$	4,136.8	$	30.4	$	4,167.2
Net income attributed to common shareholder	Net income attributed to common shareholder	—		—		138.5		138.5		—		138.5		Net income attributed to common shareholder	—		—		121.7		121.7		—		121.7
Payment of dividends to parent	Payment of dividends to parent	—		—		(110.0)		(110.0)		—		(110.0)		Payment of dividends to parent	—		—		(60.0)		(60.0)		—		(60.0)
Equity contribution from parent	Equity contribution from parent	—		280.0		—		280.0		—		280.0		Equity contribution from parent	—		415.0		—		415.0		—		415.0
Stock-based compensation and other	Stock-based compensation and other	—		0.7		(0.1)		0.6		—		0.6		Stock-based compensation and other	—		0.5		0.1		0.6		—		0.6
Balance at March 31, 2022		$	332.9	$	1,571.6	$	2,318.9	$	4,223.4	$	30.4	$	4,253.8
Balance at March 31, 2023														Balance at March 31, 2023	$	332.9	$	2,162.3	$	2,118.9	$	4,614.1	$	30.4	$	4,644.5
Net income attributed to common shareholder	Net income attributed to common shareholder	—		—		77.8		77.8		—		77.8		Net income attributed to common shareholder	—		—		111.6		111.6		—		111.6
Payment of dividends to parent	Payment of dividends to parent	—		—		(230.0)		(230.0)		—		(230.0)		Payment of dividends to parent	—		—		(60.0)		(60.0)		—		(60.0)
Stock-based compensation and other		—		0.1		—		0.1		—		0.1
Balance at June 30, 2022		$	332.9	$	1,571.7	$	2,166.7	$	4,071.3	$	30.4	$	4,101.7
Equity contribution from parent														Equity contribution from parent	—		290.0		—		290.0		—		290.0
Balance at June 30, 2023														Balance at June 30, 2023	$	332.9	$	2,452.3	$	2,170.5	$	4,955.7	$	30.4	$	4,986.1

Wisconsin Electric Power Company Common Shareholder's Equity
(in millions) Common Stock Additional Paid In Capital Retained Earnings Total Common Shareholder's Equity Preferred Stock Total Equity
Balance at December 31, 2020 $ 332.9 $ 1,060.1 $ 2,269.2 $ 3,662.2 $ 30.4 $ 3,692.6
Net income attributed to common shareholder — — 127.0 127.0 — 127.0
Payment of dividends to parent — — (60.0) (60.0) — (60.0)
Equity contribution from parent — 30.0 — 30.0 — 30.0
Stock-based compensation and other — 0.5 0.1 0.6 — 0.6
Balance at March 31, 2021 $ 332.9 $ 1,090.6 $ 2,336.3 $ 3,759.8 $ 30.4 $ 3,790.2
Net income attributed to common shareholder — — 78.8 78.8 — 78.8
Payment of dividends to parent — — (60.0) (60.0) — (60.0)
Stock-based compensation and other — 0.1 (0.1) — $ — $ —
Balance at June 30, 2021 $ 332.9 $ 1,090.7 $ 2,355.0 $ 3,778.6 $ 30.4 $ 3,809.0


	Wisconsin Electric Power Company Common Shareholder's Equity
(in millions)	Common Stock		Additional Paid In Capital		Retained Earnings		Total Common Shareholder's Equity		Preferred Stock		Total Equity
Balance at December 31, 2021	$	332.9	$	1,290.9	$	2,290.5	$	3,914.3	$	30.4	$	3,944.7
Net income attributed to common shareholder	—		—		138.5		138.5		—		138.5
Payment of dividends to parent	—		—		(110.0)		(110.0)		—		(110.0)
Equity contribution from parent	—		280.0		—		280.0		—		280.0
Stock-based compensation and other	—		0.7		(0.1)		0.6		—		0.6
Balance at March 31, 2022	$	332.9	$	1,571.6	$	2,318.9	$	4,223.4	$	30.4	$	4,253.8
Net income attributed to common shareholder	—		—		77.8		77.8		—		77.8
Payment of dividends to parent	—		—		(230.0)		(230.0)		—		(230.0)
Stock-based compensation and other	—		0.1		—		0.1		—		0.1
Balance at June 30, 2022	$	332.9	$	1,571.7	$	2,166.7	$	4,071.3	$	30.4	$	4,101.7

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


06/30/~~2022~~2023 Form 10-Q			6			Wisconsin Electric Power Company

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WISCONSIN ELECTRIC POWER COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

June 30, ~~2022~~2023

NOTE 1—GENERAL INFORMATION

Wisconsin Electric Power Company serves approximately ~~1.1~~1.2 million electric customers and 0.5 million natural gas customers.

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

On our financial statements, we consolidate VIEs of which we are the primary beneficiary.

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, ~~2021.~~2022. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three and six months ended June 30, ~~2022,~~2023, are not necessarily indicative of expected results for ~~2022~~2023 due to seasonal variations and other factors.

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

NOTE 2—~~ACQUISITION~~ACQUISITIONS

In accordance with Topic 805: Clarifying the Definition of a Business (ASU 2017-01), transactions are evaluated and are accounted for as acquisitions ~~(or disposals)~~ of assets or businesses, and transaction costs are capitalized in asset acquisitions. It was determined that all of the below acquisitions met the criteria of an asset acquisition.

~~Acquisition~~Acquisitions of Electric Generation ~~Facility~~Facilities in Wisconsin

In ~~November 2021,~~June 2023, we completed the acquisition of 100 MWs of West Riverside's nameplate capacity, in the first of two potential option exercises. West Riverside is a commercially operational dual fueled combined cycle generation facility in Beloit, Wisconsin. Our investment was $95.3 million.

In January 2023, we, along with WPS, ~~signed an asset purchase agreement to acquire~~completed the acquisition of Whitewater, a commercially operational 236.5 MW ~~dual-fueled~~dual fueled (natural gas and low sulfur fuel oil) ~~combined-cycle electrical~~combined cycle electric generation facility in Whitewater, Wisconsin. We currently purchase all of the capacity from this generation facility pursuant to a PPA. In December 2021, we, along with WPS, filed an application with the PSCW for approval to acquire Whitewater. If approved, ourOur share of the cost of this facility ~~is estimated to be $36.3~~was $38.0 million for 50% of the capacity. ~~The transaction is expected to close in early 2023.~~

NOTE 3—DISPOSITION

Sale of Real Estate

In June 2023, we sold approximately 192 acres of real estate at our former Pleasant Prairie power plant site that was no longer being utilized in our operations, for $23.0 million, which is net of closing costs. As a result of the sale, a pre-tax gain in the amount of $22.2 million was recorded within other operation and maintenance expense on our income statement. The book value of the real estate included in the sale was not material and, therefore, was not presented as held for sale.


06/30/~~2022~~2023 Form 10-Q			7			Wisconsin Electric Power Company

Table of Contents

NOTE 3—4—OPERATING REVENUES

For more information about our operating revenues, see Note 1(d), Operating Revenues, in our ~~2021~~2022 Annual Report on Form 10-K.

Disaggregation of Operating Revenues

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


		Three Months Ended June 30				Six Months Ended June 30					Three Months Ended June 30				Six Months Ended June 30
(in millions)	(in millions)	2022		2021		2022		2021		(in millions)	2023		2022		2023		2022
Wisconsin Electric Power Company	Wisconsin Electric Power Company									Wisconsin Electric Power Company
Electric utility	Electric utility	$	843.1	$	758.9	$	1,674.2	$	1,542.4	Electric utility	$	824.9	$	843.1	$	1,668.8	$	1,674.2
Natural gas utility	Natural gas utility	96.9		62.3		332.8		278.1		Natural gas utility	70.7		96.9		314.3		332.8
Total revenues from contracts with customers	Total revenues from contracts with customers	940.0		821.2		2,007.0		1,820.5		Total revenues from contracts with customers	895.6		940.0		1,983.1		2,007.0
Other operating revenues	Other operating revenues	3.5		6.3		8.5		12.2		Other operating revenues	4.7		3.5		9.1		8.5
Total operating revenues	Total operating revenues	$	943.5	$	827.5	$	2,015.5	$	1,832.7	Total operating revenues	$	900.3	$	943.5	$	1,992.2	$	2,015.5

Revenues from Contracts with Customers

Electric Utility Operating Revenues

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


		Three Months Ended June 30				Six Months Ended June 30					Three Months Ended June 30				Six Months Ended June 30
(in millions)	(in millions)	2022		2021		2022		2021		(in millions)	2023		2022		2023		2022
Residential	Residential	$	328.8	$	307.6	$	664.2	$	619.8	Residential	$	338.3	$	328.8	$	695.7	$	664.2
Small commercial and industrial	Small commercial and industrial	268.9		248.7		536.9		491.2		Small commercial and industrial	287.5		268.9		572.1		536.9
Large commercial and industrial	Large commercial and industrial	159.7		138.0		296.5		267.1		Large commercial and industrial	151.6		159.7		290.7		296.5
Other	Other	4.8		4.6		10.2		10.2		Other	4.8		4.8		10.5		10.2
Total retail revenues	Total retail revenues	762.2		698.9		1,507.8		1,388.3		Total retail revenues	782.2		762.2		1,569.0		1,507.8
Wholesale	Wholesale	17.2		17.9		37.8		38.7		Wholesale	10.3		17.2		22.0		37.8
Resale	Resale	52.6		36.1		103.6		92.6		Resale	26.6		52.6		60.0		103.6
Steam	Steam	4.7		4.2		16.8		19.0		Steam	4.7		4.7		15.7		16.8
Other utility revenues	Other utility revenues	6.4		1.8		8.2		3.8		Other utility revenues	1.1		6.4		2.1		8.2
Total electric utility operating revenues	Total electric utility operating revenues	$	843.1	$	758.9	$	1,674.2	$	1,542.4	Total electric utility operating revenues	$	824.9	$	843.1	$	1,668.8	$	1,674.2

Natural Gas Utility Operating Revenues

The following table disaggregates natural gas utility operating revenues ~~into~~by customer class:


		Three Months Ended June 30				Six Months Ended June 30					Three Months Ended June 30				Six Months Ended June 30
(in millions)	(in millions)	2022		2021		2022		2021		(in millions)	2023		2022		2023		2022
Residential	Residential	$	64.1	$	70.3	$	229.8	$	183.0	Residential	$	35.1	$	64.1	$	214.3	$	229.8
Commercial and industrial	Commercial and industrial	28.2		31.6		111.5		84.2		Commercial and industrial	13.0		28.2		100.9		111.5
Total retail revenues	Total retail revenues	92.3		101.9		341.3		267.2		Total retail revenues	48.1		92.3		315.2		341.3
Transportation	Transportation	3.9		3.8		9.5		9.1		Transportation	4.6		3.9		11.4		9.5
Other utility revenues (1)	Other utility revenues (1)	0.7		(43.4)		(18.0)		1.8		Other utility revenues (1)	18.0		0.7		(12.3)		(18.0)
Total natural gas utility operating revenues	Total natural gas utility operating revenues	$	96.9	$	62.3	$	332.8	$	278.1	Total natural gas utility operating revenues	$	70.7	$	96.9	$	314.3	$	332.8

(1)Includes the revenues subject to our purchased gas recovery ~~mechanism. The negative amount for~~mechanism, which fluctuate based on actual natural gas costs incurred, compared with the ~~six months ended June 30, 2022 primarily relates to the over-collection~~recovery of natural gas costs ~~recorded in a regulatory liability due to these costs being lower than what was~~that were anticipated in rates. ~~See Note 5, Regulatory Assets and Liabilities, for more information.~~


06/30/~~2022~~2023 Form 10-Q			8			Wisconsin Electric Power Company

Table of Contents

The negative amount for the three months ended June 30, 2021 primarily relates to the approval by the PSCW to recover from customers, over the second quarter of 2021, the higher natural gas costs that were incurred as a result of the extreme winter weather conditions in February 2021. As these amounts were billed to customers, they were reflected in retail revenues with an offsetting decrease in other utility revenues.

Other Operating Revenues

Other operating revenues consist primarily of the following:


		Three Months Ended June 30				Six Months Ended June 30					Three Months Ended June 30				Six Months Ended June 30
(in millions)	(in millions)	2022		2021		2022		2021		(in millions)	2023		2022		2023		2022
Late payment charges	Late payment charges	$	3.1	$	4.4	$	6.6	$	8.1	Late payment charges	$	3.3	$	3.1	$	7.0	$	6.6
Rental revenues	Rental revenues	1.3		1.6		1.9		2.4		Rental revenues	1.3		1.3		1.7		1.9
Alternative revenues (1)	Alternative revenues (1)	(0.9)		0.3		—		1.7		Alternative revenues (1)	0.1		(0.9)		0.4		—
Total other operating revenues	Total other operating revenues	$	3.5	$	6.3	$	8.5	$	12.2	Total other operating revenues	$	4.7	$	3.5	$	9.1	$	8.5

(1)Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. Negative amounts can also result from revenues to be refunded to wholesale customers subject to true-ups, as discussed in Note 1(d), Operating Revenues, in our ~~2021~~2022 Annual Report on Form ~~10-K~~10-K.

NOTE 4—5—CREDIT LOSSES

Our exposure to credit losses is related to our accounts receivable and unbilled revenue balances, which are generated from the sale of electricity and natural gas by our regulated utility operations. Our regulated utility operations are included in our utility segment. No accounts receivable and unbilled revenue balances were reported in the other segment at June 30, ~~2022~~2023 and December 31, ~~2021.~~2022.

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

We monitor our ongoing credit exposure through active review of counterparty accounts receivable balances against contract terms and due dates. Our activities include timely account reconciliation, dispute resolution and payment confirmation. To the extent possible, we work with customers with past due balances to negotiate payment plans, but will disconnect customers for non-payment as allowed by the PSCW, if necessary, and employ collection agencies and legal counsel to pursue recovery of defaulted receivables. For our larger customers, detailed credit review procedures may be performed in advance of any sales being made. We sometimes require letters of credit, parental guarantees, prepayments or other forms of credit assurance from our larger customers to mitigate credit risk.

We have included a table below that shows our gross third-party receivable balances and related allowance for credit losses.


(in millions)	(in millions)	June 30, 2022			December 31, 2021			(in millions)	June 30, 2023			December 31, 2022
Accounts receivable and unbilled revenues	Accounts receivable and unbilled revenues	$	618.6		$	616.9		Accounts receivable and unbilled revenues	$	571.1		$	632.3
Allowance for credit losses	Allowance for credit losses	47.6			51.4			Allowance for credit losses	45.1			49.7
Accounts receivable and unbilled revenues, net (1)	Accounts receivable and unbilled revenues, net (1)	$	571.0		$	565.5		Accounts receivable and unbilled revenues, net (1)	$	526.0		$	582.6

Total accounts receivable, net – past due greater than 90 days (1)	Total accounts receivable, net – past due greater than 90 days (1)	$	38.3		$	32.9		Total accounts receivable, net – past due greater than 90 days (1)	$	39.3		$	35.8
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)	Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)	98.4		%	98.3		%	Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)	96.6		%	97.5		%

(1)Our exposure to credit losses for certain regulated utility customers is mitigated by a regulatory mechanism we have in place. Specifically, our residential tariffs include a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. As a result, at June 30, ~~2022, $227.1~~2023, $270.4 million, or ~~39.8%~~51.4%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses.


06/30/~~2022~~2023 Form 10-Q			9			Wisconsin Electric Power Company

Table of Contents

A rollforward of the allowance for credit losses is included below:


		Three Months Ended June 30				Six Months Ended June 30					Three Months Ended June 30
(in millions)	(in millions)	2022		2021		2022		2021		(in millions)	2023		2022
Balance at the beginning of the period		$	51.8	$	78.8	$	51.4	$	59.3
Balance at April 1										Balance at April 1	$	53.7	$	51.8
Provision for credit losses	Provision for credit losses	6.6		4.4		12.7		12.5		Provision for credit losses	4.7		6.6
Provision for credit losses deferred for future recovery or refund	Provision for credit losses deferred for future recovery or refund	0.2		(3.5)		7.3		13.9		Provision for credit losses deferred for future recovery or refund	1.7		0.2
Write-offs charged against the allowance	Write-offs charged against the allowance	(15.5)		(10.7)		(34.3)		(22.2)		Write-offs charged against the allowance	(21.3)		(15.5)
Recoveries of amounts previously written off	Recoveries of amounts previously written off	4.5		2.3		10.5		7.8		Recoveries of amounts previously written off	6.3		4.5
Balance at the end of the period		$	47.6	$	71.3	$	47.6	$	71.3
Balance at June 30										Balance at June 30	$	45.1	$	47.6


	Six Months Ended June 30
(in millions)	2023		2022
Balance at January 1	$	49.7	$	51.4
Provision for credit losses	11.3		12.7
Provision for credit losses deferred for future recovery or refund	15.5		7.3
Write-offs charged against the allowance	(41.6)		(34.3)
Recoveries of amounts previously written off	10.2		10.5
Balance at June 30	$	45.1	$	47.6

There was a $4.6 million decrease in the allowance for credit losses at June 30, 2023, compared to January 1, 2023, driven by customer write-offs related to the winter moratorium months ending. After a customer is disconnected for a period of time without payment on their account, we will write off that customer balance. The winter moratorium begins on November 1 and ends on April 15. Also contributing to the decrease in the allowance for credit losses, we believe that the lower energy costs that customers were seeing, which were driven by lower natural gas prices, contributed to a reduction in past due accounts receivable balances and a related decrease in the allowance for credit losses.

There was a $3.8 million decrease in the allowance for credit losses at June 30, 2022, compared to ~~December 31, 2021.~~January 1, 2022. The decrease was driven by customer write-offs related to collection practices returning to pre-pandemic levels in 2021, including the restoration of our ability to disconnect customers. ~~After a customer is disconnected for a period of time without payment on their account, we will write off that customer balance.~~ Partially offsetting the decrease in the allowance for credit losses, we believe that the high energy costs that customers ~~are~~were seeing, which ~~have been~~were driven by high natural gas prices, contributed to higher past due accounts receivable balances and a related increase in the allowance for credit losses.

The increase in the allowance for credit losses at June 30, 2021, compared to December 31, 2020, was driven by higher past due accounts receivable balances, primarily related to residential customers. This increase in accounts receivable balances in arrears related to the continued economic disruptions caused by the COVID-19 pandemic, including high unemployment rates. However, as seen in the quarterly rollforward above, the allowance for credit losses began to decrease in the second quarter of 2021, which we believe was related to the start of normal collection practices.

NOTE 5—6—REGULATORY ASSETS AND LIABILITIES

The following regulatory assets and liabilities were reflected on our balance sheets at June 30, ~~2022~~2023 and December 31, ~~2021.~~2022. For more information on our regulatory assets and liabilities, see Note 6, Regulatory Assets and Liabilities, in our ~~2021~~2022 Annual Report on Form 10-K.


(in millions)	(in millions)	June 30, 2022		December 31, 2021		(in millions)	June 30, 2023		December 31, 2022
Regulatory assets	Regulatory assets					Regulatory assets
Finance leases	Finance leases	$	1,052.0	$	1,032.6	Finance leases	$	1,092.8	$	1,072.0
Plant retirement related items	Plant retirement related items	646.9		659.1		Plant retirement related items	614.1		632.7
Income tax related items	Income tax related items	383.8		387.3		Income tax related items	376.9		382.1
Pension and OPEB costs	Pension and OPEB costs	370.8		386.1		Pension and OPEB costs	332.7		337.2
System support resource	System support resource	126.6		129.5		System support resource	118.3		123.5
Securitization	Securitization	96.1		100.7		Securitization	89.5		92.4
Derivatives						Derivatives	73.2		40.3
Asset retirement obligations	Asset retirement obligations	42.2		42.0		Asset retirement obligations	41.3		41.1
Environmental remediation costs		15.9		16.8
Uncollectible expense						Uncollectible expense	31.9		16.4
Energy efficiency programs						Energy efficiency programs	15.4		17.7
We Power generation						We Power generation	12.0		21.6
Other, net	Other, net	16.8		10.3		Other, net	48.5		40.5
Total regulatory assets	Total regulatory assets	$	2,751.1	$	2,764.4	Total regulatory assets	$	2,846.6	$	2,817.5

Balance sheet presentation
Other current assets		$	—	$	1.3
Regulatory assets		2,751.1		2,763.1
Total regulatory assets		$	2,751.1	$	2,764.4


06/30/~~2022~~2023 Form 10-Q			10			Wisconsin Electric Power Company

Table of Contents

(in millions) June 30, 2022 December 31, 2021
Regulatory liabilities
Income tax related items $ 724.3 $ 728.6
Removal costs 708.8 697.8
Pension and OPEB benefits 145.9 148.4
Derivatives (1)
109.6 55.6
Electric transmission costs (2)
33.4 64.4
Energy costs refundable through rate adjustments (3)
17.2 0.3
Uncollectible expense 10.3 17.8
Other, net 16.7 10.3
Total regulatory liabilities $ 1,766.2 $ 1,723.2
Balance sheet presentation
Other current liabilities $ 16.8 $ —
Regulatory liabilities 1,749.4 1,723.2
Total regulatory liabilities $ 1,766.2 $ 1,723.2

~~(1)~~ For most energy-related physical and financial contracts that qualify as derivatives, the PSCW allows the effects of fair value accounting to be offset to regulatory assets and liabilities. See Note 13, Derivative Instruments, for more information on our derivative asset and liability balances.

~~(2)~~ The decrease in this regulatory liability balance was primarily related to the PSCW's approval of certain accounting treatments that allowed us to forego applying for a 2022 base rate increase, and instead maintain base rates consistent with 2021 levels. Among the accounting treatments approved was the amortization of our electric transmission regulatory liability balance in 2022, to offset a portion of our forecasted revenue deficiency. See Note 22, Regulatory Environment, in our 2021 Annual Report on Form 10-K for additional information on our 2022 base rates.

~~(3)~~ ~~The increase in these regulatory liabilities was primarily related to lower natural gas costs incurred during 2022, compared to what was anticipated in rates.~~


(in millions)	June 30, 2023		December 31, 2022
Regulatory liabilities
Removal costs	$	738.5	$	718.1
Income tax related items	701.2		716.1
Pension and OPEB benefits	142.5		144.4
Electric transmission costs	15.9		0.2
Energy costs refundable through rate adjustments	14.7		1.8
Derivatives	8.6		39.1
Other, net	20.1		19.1
Total regulatory liabilities	$	1,641.5	$	1,638.8

Balance sheet presentation
Other current liabilities	$	14.4	$	1.4
Regulatory liabilities	1,627.1		1,637.4
Total regulatory liabilities	$	1,641.5	$	1,638.8

NOTE 6—7—PROPERTY, PLANT, AND EQUIPMENT

~~During a significant rain event in May 2020, an underground steam tunnel in downtown Milwaukee flooded and steam vented into our PSB. The damage~~Plant to ~~the building and adjacent steam tunnel assets from the flooding and steam was extensive and required significant repairs and restorations.~~ be Retired

Oak Creek Power Plant Units 5 – 8

As of June 30, 2022, we had incurred $95.3 million of costs related to these repairs and restorations. In 2020, we received $20.0 million of insurance proceeds to cover a portion of these costs and wrote off $12.5 million of costs that we do not intend to seek recovery for through other operation and maintenance expense. In the first quarter of 2022, we received $41.0 million of insurance proceeds as a result of a ~~settlement that~~PSCW approval for the construction of a solar and battery project received in December 2022, retirement of the OCPP generating units 5 – 8 became probable. In early 2023, we received additional approvals for electric generation facilities, including West Riverside and Koshkonong. See Note 2, Acquisitions, for more information on the acquisition of West Riverside, which was ~~reached~~completed in ~~February 2022. The remaining $21.8 million of costs is~~June 2023. OCPP units 5 and 6 are expected to be ~~recovered through rates.~~retired by May 2024, while units 7 and 8 are expected to be retired by late 2025. The total net book value of our ownership share of units 5 – 8 was $808.1 million at June 30, 2023, which does not include deferred taxes. 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 we continue to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW.

NOTE 8—JOINTLY OWNED UTILITY FACILITIES

We hold joint ownership interests in certain electric generating facilities. We are entitled to our share of generating capability and output of each facility equal to our respective ownership interest. We pay our ownership share of additional construction costs and have supplied our own financing for all jointly owned projects. We record our proportionate share of significant jointly owned electric generating facilities as property, plant, and equipment on the balance sheets. In addition, our proportionate share of direct expenses for the joint operation of these plants is recorded within operating expenses in the income statements.

In January 2023, we, along with WPS, completed the acquisition of Whitewater, a commercially operational 236.5 MW dual fueled (natural gas and low sulfur fuel oil) combined cycle electrical generation facility. We own 50% of this facility. See Note 2, Acquisitions, for more information.

In June ~~2021,~~2023, we ~~received approval from~~completed the ~~PSCW to restore the PSB and adjacent steam tunnel assets and to defer the project costs, net~~acquisition of ~~insurance proceeds, as~~ a ~~component~~13.8% ownership interest, or 100 MWs, of ~~rate base. As such, and in light of the agreement with insurers noted above, we do not currently expect~~West Riverside, a ~~significant impact to our future results of operations.~~commercially operational dual fueled combined cycle generation facility. See Note 2, Acquisitions, for more information.

In July 2023, we, along with WPS, completed the construction of a natural gas-fired generation facility at WPS's existing Weston power plant site. The new facility consists of seven RICE units. We own 50%, or 64 MWs, of the Weston RICE units. Our construction work in progress balance for the Weston RICE units was $86.1 million as of June 30, 2023.


06/30/2023 Form 10-Q			11			Wisconsin Electric Power Company

Table of Contents

NOTE 7—9—COMMON EQUITY

Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to WEC Energy Group in the form of cash dividends, loans, or advances. In addition, Wisconsin law prohibits us from making loans to or guaranteeing obligations of WEC Energy Group or its subsidiaries. See Note 9,10, Common Equity, in our ~~2021~~2022 Annual Report on Form 10-K for additional information on these and other restrictions.

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


~~06/30/2022 Form 10-Q~~			11			~~Wisconsin Electric Power Company~~

~~Table of Contents~~

NOTE 8—10—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)	(in millions, except percentages)	June 30, 2022			December 31, 2021			(in millions, except percentages)	June 30, 2023			December 31, 2022
Commercial paper	Commercial paper							Commercial paper
Amount outstanding	Amount outstanding	$	413.8		$	375.0		Amount outstanding	$	43.0		$	460.7
Weighted-average interest rate on amounts outstanding	Weighted-average interest rate on amounts outstanding	1.81		%	0.21		%	Weighted-average interest rate on amounts outstanding	5.20		%	4.59		%

Our average amount of commercial paper borrowings based on daily outstanding balances during the six months ended June 30, ~~2022~~2023 was ~~$134.7~~$123.8 million with a weighted-average interest rate during the period of ~~0.66%~~4.93%.

The information in the table below relates to our revolving credit facility used to support our commercial paper borrowing program, including available capacity under this facility:

(in millions)

Maturity

June 30, ~~2022~~2023

Revolving credit facility

September 2026

500.0

Less:

Letters of credit issued inside credit facility

1.0

Commercial paper outstanding

~~413.8~~43.0

Available capacity under existing credit facility

~~85.2~~456.0

NOTE 9—11—LEASES

Obligations Under Finance Leases

Land Leases – Utility Solar Generation

We, along with WPS and an unaffiliated utility, partnered to acquire and construct ~~Paris,~~Darien, a utility-scale solar-powered electric generating facility with a battery energy storage system in ~~Kenosha County,~~Rock and Walworth counties, Wisconsin. We own 75% of ~~Paris.~~ ~~Once fully constructed, we will own 150 MW~~Darien. Commercial operation of ~~solar generation and 82 MW of battery storage of this project. The PSCW has approved the acquisition and construction of Paris, and commercial operation for~~ the solar portion of the project is targeted in ~~2023.~~2024.

Related to our investment in ~~Paris,~~Darien, we, along with WPS and an unaffiliated utility, entered into several land leases ~~in Kenosha County, Wisconsin~~ that commenced in the second quarter of ~~2022.~~2023. Each lease has an initial construction term that ends upon achieving commercial operation, then automatically extends for 25 years with an option for an additional 25-year extension. We expect the optional extension to be exercised, and, as a result, the land leases are being amortized over the extended term of the leases. Once Darien achieves commercial operation, the lease liability will be remeasured to reflect the final total acres being leased. The lease payments will be recovered through rates.

Our total obligation under the land-related finance leases for ~~Paris~~Darien was ~~approximately $43.8~~$33.1 million at June 30, ~~2022,~~2023, and ~~will decrease to zero over the remaining lives of the leases. Long-term lease liabilities related to our finance land leases for Paris were~~was included in finance lease obligations on ~~the~~our balance sheet. Our finance lease right of use asset related to ~~Paris~~Darien was ~~approximately $43.8~~$32.8 million as of June 30, ~~2022,~~2023, and was included in property, plant, and equipment on our balance sheet.

In accordance with Accounting Standards Codification Subtopic 980-842, Regulated Operations – Leases (Subtopic 980-842), the expense recognition pattern associated with ~~Paris~~the Darien leases resembles that of an operating ~~lease, as amortization of the right of use assets has been modified from what would typically be recorded for a finance lease under Topic 842.~~lease. The difference between the minimum lease payments and the sum of imputed interest and unadjusted amortization costs calculated under Topic 842 is deferred as a regulatory asset on our balance sheet in accordance with Subtopic ~~980-842 on our balance sheet.~~980-842.


06/30/2023 Form 10-Q			12			Wisconsin Electric Power Company

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At June 30, ~~2022,~~2023, our weighted-average discount rate for the ~~Paris~~Darien finance leases was ~~5.28%~~5.96%. We used the fully collateralized incremental borrowing rates based upon information available for similarly rated companies in determining the present value of lease payments.


~~06/30/2022 Form 10-Q~~			12			~~Wisconsin Electric Power Company~~

~~Table of Contents~~

Future minimum lease payments and the corresponding present value of our net minimum lease payments under the finance leases for ~~Paris~~Darien as of June 30, ~~2022,~~2023, were as follows:


(in millions)	(in millions)			(in millions)
Six months ended December 31, 2022		$	0.6
2023		1.8
Six months ended December 31, 2023				Six months ended December 31, 2023	$	—
2024	2024	1.9		2024	0.6
2025	2025	1.9		2025	1.6
2026	2026	2.0		2026	1.7
2027	2027	2.0		2027	1.7
2028				2028	1.7
Thereafter	Thereafter	146.7		Thereafter	131.4
Total minimum lease payments	Total minimum lease payments	156.9		Total minimum lease payments	138.7
Less: Interest	Less: Interest	(113.1)		Less: Interest	(105.6)
Present value of minimum lease payments	Present value of minimum lease payments	43.8		Present value of minimum lease payments	33.1
Less: Short-term lease liabilities	Less: Short-term lease liabilities	—		Less: Short-term lease liabilities	—
Long-term lease liabilities	Long-term lease liabilities	$	43.8	Long-term lease liabilities	$	33.1

NOTE ~~10—~~12—MATERIALS, SUPPLIES, AND INVENTORIES

Our inventory consisted of:


(in millions)	(in millions)	June 30, 2022		December 31, 2021		(in millions)	June 30, 2023		December 31, 2022
Materials and supplies	Materials and supplies	$	144.6	$	138.2	Materials and supplies	$	161.6	$	150.6
Fossil fuel	Fossil fuel	60.0		54.7		Fossil fuel	60.5		62.7
Natural gas in storage	Natural gas in storage	53.6		53.5		Natural gas in storage	33.4		79.6
Total	Total	$	258.2	$	246.4	Total	$	255.5	$	292.9

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


06/30/~~2022~~2023 Form 10-Q			13			Wisconsin Electric Power Company

Table of Contents

NOTE ~~11—~~13—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 June 30, 2022				Three Months Ended June 30, 2021					Three Months Ended June 30, 2023				Three Months Ended June 30, 2022
(in millions)	(in millions)	Amount		Effective Tax Rate		Amount		Effective Tax Rate		(in millions)	Amount		Effective Tax Rate		Amount		Effective Tax Rate
Statutory federal income tax	Statutory federal income tax	$	21.9	21.0	%	$	19.1	21.0	%	Statutory federal income tax	$	30.7	21.0	%	$	21.9	21.0	%
State income taxes net of federal tax benefit	State income taxes net of federal tax benefit	6.6		6.3	%	5.9		6.4	%	State income taxes net of federal tax benefit	8.7		6.0	%	6.6		6.3	%
Federal excess deferred tax amortization										Federal excess deferred tax amortization	(4.7)		(3.2)	%	(4.6)		(4.4)	%
AFUDC–Equity										AFUDC–Equity	(1.9)		(1.3)	%	(0.5)		(0.4)	%
PTCs										PTCs	(1.8)		(1.2)	%	(0.4)		(0.4)	%
Domestic production activities deferral	Domestic production activities deferral	1.3		1.2	%	1.3		1.4	%	Domestic production activities deferral	1.4		1.0	%	1.3		1.2	%
Federal excess deferred tax amortization – Wisconsin unprotected		1.1		1.0	%	(9.0)		(9.9)	%
Federal excess deferred tax amortization		(4.6)		(4.4)	%	(4.8)		(5.3)	%
PTCs		(0.4)		(0.4)	%	(1.4)		(1.4)	%
Other		0.8		0.8	%	1.1		1.2	%

Other, net										Other, net	1.9		1.2	%	2.4		2.2	%
Total income tax expense	Total income tax expense	$	26.7	25.5	%	$	12.2	13.4	%	Total income tax expense	$	34.3	23.5	%	$	26.7	25.5	%

		Six Months Ended June 30, 2022				Six Months Ended June 30, 2021					Six Months Ended June 30, 2023				Six Months Ended June 30, 2022
(in millions)	(in millions)	Amount		Effective Tax Rate		Amount		Effective Tax Rate		(in millions)	Amount		Effective Tax Rate		Amount		Effective Tax Rate
Statutory federal income tax	Statutory federal income tax	$	61.0	21.0	%	$	49.9	21.0	%	Statutory federal income tax	$	63.1	21.0	%	$	61.0	21.0	%
State income taxes net of federal tax benefit	State income taxes net of federal tax benefit	18.2		6.3	%	15.2		6.4	%	State income taxes net of federal tax benefit	18.0		6.0	%	18.2		6.3	%
Domestic production activities deferral		3.3		1.1	%	3.4		1.4	%
Federal excess deferred tax amortization – Wisconsin unprotected		2.8		1.0	%	(23.3)		(9.8)	%

Federal excess deferred tax amortization	Federal excess deferred tax amortization	(12.1)		(4.2)	%	(12.6)		(5.3)	%	Federal excess deferred tax amortization	(10.0)		(3.3)	%	(12.1)		(4.2)	%
PTCs	PTCs	(0.9)		(0.3)	%	(3.8)		(1.6)	%	PTCs	(6.9)		(2.3)	%	(0.9)		(0.3)	%
Other		1.9		0.6	%	2.9		1.2	%
AFUDC–Equity										AFUDC–Equity	(4.1)		(1.4)	%	(1.8)		(0.6)	%
Domestic production activities deferral										Domestic production activities deferral	3.0		1.0	%	3.3		1.1	%
Other, net										Other, net	3.9		1.3	%	6.5		2.2	%
Total income tax expense	Total income tax expense	$	74.2	25.5	%	$	31.7	13.3	%	Total income tax expense	$	67.0	22.3	%	$	74.2	25.5	%

The effective tax rates ~~of 25.5%~~ for ~~both~~ the three and six months ended June 30, 2023 and 2022, differ from the United States statutory federal income tax rate of 21%, primarily due to state income taxes. This item was partially offset by the impact of the protected deferred tax benefits associated with the Tax Legislation, as discussed in more detail below.

The effective tax rates of 13.4% and 13.3% for the three and six months ended June 30, 2021, 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. Effective January 1, 2020, in accordance with the rate order received from the PSCW in December 2019, we began amortizing the unprotected deferred tax benefits over periods ranging from two years to four years, to reduce near-term rate impacts to our customers. In addition, the impact of the protected deferred tax benefits associated with the Tax Legislation, as discussed in more detail below, and PTCs drove a decrease in the effective tax rate. These items were partially offset by state income taxes.

The Tax Legislation required us to remeasure the deferred income taxes at our utility segment and we began to amortize the resulting excess protected deferred income taxes beginning in 2018 in accordance with normalization requirements (see federal excess deferred tax amortization lines above).

See Note ~~22,~~23, Regulatory Environment, in our ~~2021~~2022 Annual Report on Form 10-K for ~~additional~~more information ~~on unprotected tax benefits.~~about the impact of the Tax Legislation.

NOTE ~~12—~~14—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).


~~06/30/2022 Form 10-Q~~			14			~~Wisconsin Electric Power Company~~

~~Table of Contents~~

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.


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

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

When possible, we base the valuations of our derivative assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. Certain derivatives, such as FTRs, are categorized in Level 3 due to the significance of unobservable or internally-developed inputs. Our ~~derivative instruments categorized as Level 3 consisted of~~ FTRs ~~at June 30, 2022 and December 31, 2021. These derivative instruments~~ are valued using MISO auction prices.

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


		June 30, 2022									June 30, 2023
(in millions)	(in millions)	Level 1		Level 2		Level 3		Total		(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets	Derivative assets									Derivative assets
Natural gas contracts	Natural gas contracts	$	25.7	$	2.2	$	—	$	27.9	Natural gas contracts	$	0.5	$	1.1	$	—	$	1.6
FTRs	FTRs	—		—		6.1		6.1		FTRs	—		—		6.9		6.9
Coal contracts	Coal contracts	—		67.6		—		67.6		Coal contracts	—		0.2		—		0.2
Total derivative assets	Total derivative assets	$	25.7	$	69.8	$	6.1	$	101.6	Total derivative assets	$	0.5	$	1.3	$	6.9	$	8.7

Derivative liabilities	Derivative liabilities									Derivative liabilities
Natural gas contracts	Natural gas contracts	$	6.9	$	1.2	$	—	$	8.1	Natural gas contracts	$	35.5	$	1.6	$	—	$	37.1

Coal contracts										Coal contracts	—		27.5		—		27.5
Total derivative liabilities										Total derivative liabilities	$	35.5	$	29.1	$	—	$	64.6


		December 31, 2021									December 31, 2022
(in millions)	(in millions)	Level 1		Level 2		Level 3		Total		(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets	Derivative assets									Derivative assets
Natural gas contracts	Natural gas contracts	$	11.5	$	4.2	$	—	$	15.7	Natural gas contracts	$	1.6	$	2.5	$	—	$	4.1
FTRs	FTRs	—		—		1.0		1.0		FTRs	—		—		2.0		2.0
Coal contracts	Coal contracts	—		37.6		—		37.6		Coal contracts	—		32.7		—		32.7
Total derivative assets	Total derivative assets	$	11.5	$	41.8	$	1.0	$	54.3	Total derivative assets	$	1.6	$	35.2	$	2.0	$	38.8

Derivative liabilities	Derivative liabilities									Derivative liabilities
Natural gas contracts	Natural gas contracts	$	2.4	$	0.3	$	—	$	2.7	Natural gas contracts	$	29.3	$	0.7	$	—	$	30.0

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

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


	Three Months Ended June 30				Six Months Ended June 30
(in millions)	2023		2022		2023		2022
Balance at the beginning of the period	$	0.8	$	0.4	$	2.0	$	1.0
Purchases	8.1		7.4		8.1		7.4
Settlements	(2.0)		(1.7)		(3.2)		(2.3)
Balance at the end of the period	$	6.9	$	6.1	$	6.9	$	6.1


06/30/~~2022~~2023 Form 10-Q			15			Wisconsin Electric Power Company

Table of Contents

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

Three Months Ended June 30 Six Months Ended June 30
(in millions) 2022 2021 2022 2021
Balance at the beginning of the period $ 0.4 $ 0.4 $ 1.0 $ 1.1
Purchases 7.4 3.0 7.4 3.0
Settlements (1.7) (0.8) (2.3) (1.5)
Balance at the end of the period $ 6.1 $ 2.6 $ 6.1 $ 2.6

Fair Value of Financial Instruments

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


		June 30, 2022				December 31, 2021					June 30, 2023				December 31, 2022
(in millions)	(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value		(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock	Preferred stock	$	30.4	$	26.4	$	30.4	$	30.3	Preferred stock	$	30.4	$	22.8	$	30.4	$	22.7
Long-term debt, including current portion	Long-term debt, including current portion	2,868.9		2,831.1		2,872.1		3,403.4		Long-term debt, including current portion	3,357.5		3,139.9		3,360.4		3,143.2

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

NOTE ~~13—~~15—DERIVATIVE INSTRUMENTS

We use derivatives as part of our risk management program to manage the risks associated with the price volatility of purchased power, generation, and natural gas costs for the benefit of our customers. Our approach is non-speculative and designed to mitigate risk. Our regulated hedging programs are approved by the PSCW.

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

~~None of our derivatives are designated as hedging instruments.~~ On our balance sheets, we classify derivative assets and liabilities as current or long-term based on the maturities of the underlying contracts. Derivative assets and liabilities not shown separately on our balance sheets are included in the other current and other long-term line items. The following table shows our derivative assets and derivative liabilities. None of the derivatives shown below are designated as hedging instruments.

June 30, 2022 December 31, 2021
(in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities
Current
Natural gas contracts (1)
$ 26.9 $ 6.9 $ 15.3 $ 2.6
FTRs 6.1 — 1.0 —
Coal contracts 48.8 — 32.4 —
Total current 81.8 6.9 48.7 2.6
Long-term
Natural gas contracts (1)
1.0 1.2 0.4 0.1
Coal contracts 18.8 — 5.2 —
Total long-term 19.8 1.2 5.6 0.1
Total $ 101.6 $ 8.1 $ 54.3 $ 2.7

~~(1)Our natural gas derivative assets increased from December 31, 2021 to June 30, 2022 primarily due to the significant increase in natural gas prices.~~


	June 30, 2023				December 31, 2022
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Current
Natural gas contracts	$	1.6	$	36.7	$	4.1	$	28.8
FTRs	6.9		—		2.0		—
Coal contracts	0.1		16.1		17.6		—
Total current	8.6		52.8		23.7		28.8

Long-term
Natural gas contracts	—		0.4		—		1.2
Coal contracts	0.1		11.4		15.1		—
Total long-term	0.1		11.8		15.1		1.2
Total	$	8.7	$	64.6	$	38.8	$	30.0


06/30/~~2022~~2023 Form 10-Q			16			Wisconsin Electric Power Company

Table of Contents

Realized gains and losses on derivatives are primarily recorded in cost of sales upon settlement; however, they may be subsequently deferred for future rate recovery or refund as the gains and losses are included in our fuel and natural gas cost recovery mechanisms. Our estimated notional sales volumes and realized gains and losses were as follows:

Three Months Ended June 30, 2022

Three Months Ended June 30, 2021

Three Months Ended June 30, 2023

Three Months Ended June 30, 2022

(in millions)

Volumes

Gains

Volumes

Gains

(in millions)

Volumes

Gains (Losses)

Volumes

Gains

Natural gas contracts

12.7 Dth

31.3

16.5 Dth

1.1

Natural gas contracts

17.0 Dth

(25.3)

12.7 Dth

31.3

FTRs

4.9 MWh

3.2

5.5 MWh

5.4

FTRs

5.2 MWh

1.9

4.9 MWh

3.2

Total

34.5

6.5

Total

(23.4)

34.5

Six Months Ended June 30, 2022

Six Months Ended June 30, 2021

Six Months Ended June 30, 2023

Six Months Ended June 30, 2022

(in millions)

Volumes

Gains

Volumes

Gains (Losses)

(in millions)

Volumes

Gains (Losses)

Volumes

Gains

Natural gas contracts

31.4 Dth

39.5

35.6 Dth

(1.6)

Natural gas contracts

35.9 Dth

(54.5)

31.4 Dth

39.5

FTRs

9.9 MWh

3.4

11.1 MWh

6.5

FTRs

10.1 MWh

2.0

9.9 MWh

3.4

Total

42.9

4.9

Total

(52.5)

42.9

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 ~~both~~ June 30, ~~2022~~2023 and December 31, ~~2021,~~2022, we had posted cash collateral of ~~$5.5 million. These amounts were recorded on our balance sheets in other current assets. At June 30, 2022 and December 31, 2021, we had also received cash collateral of $22.7~~$54.2 million and ~~$0.3~~$46.7 million, respectively. These amounts were recorded on our balance sheets ~~in other current liabilities.~~as collateral on deposit.

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


		June 30, 2022					December 31, 2021						June 30, 2023					December 31, 2022
(in millions)	(in millions)	Derivative Assets			Derivative Liabilities		Derivative Assets			Derivative Liabilities		(in millions)	Derivative Assets		Derivative Liabilities			Derivative Assets		Derivative Liabilities
Gross amount recognized on the balance sheet	Gross amount recognized on the balance sheet	$	101.6		$	8.1	$	54.3		$	2.7	Gross amount recognized on the balance sheet	$	8.7	$	64.6		$	38.8	$	30.0
Gross amount not offset on the balance sheet	Gross amount not offset on the balance sheet	(26.1)		(1)	(7.4)		(2.7)		(2)	(2.4)		Gross amount not offset on the balance sheet	(1.1)		(36.0)		(1)	(1.8)		(29.5)		(2)
Net amount	Net amount	$	75.5		$	0.7	$	51.6		$	0.3	Net amount	$	7.6	$	28.6		$	37.0	$	0.5

(1) Includes cash collateral ~~received~~posted of ~~$18.7~~$34.9 million.

(2) Includes cash collateral ~~received~~posted of ~~$0.3~~$27.7 million.

NOTE ~~14—~~16—GUARANTEES

As of June 30, ~~2022,~~2023, we had $26.0 million of standby letters of credit issued by financial institutions for the benefit of third parties that have extended credit to us, which automatically renew each year unless proper termination notice is given. These amounts are not reflected on our balance sheets.

NOTE ~~15—~~17—EMPLOYEE BENEFITS

The following tables show the components of net periodic benefit cost (credit) (including amounts capitalized to our balance sheets) for our benefit plans.


		Pension Benefits									Pension Benefits
		Three Months Ended June 30				Six Months Ended June 30					Three Months Ended June 30				Six Months Ended June 30
(in millions)	(in millions)	2022		2021		2022		2021		(in millions)	2023		2022		2023		2022
Service cost	Service cost	$	3.0	$	3.9	$	6.7	$	7.2	Service cost	$	2.3	$	3.0	$	5.1	$	6.7
Interest cost	Interest cost	8.1		7.7		16.3		15.5		Interest cost	11.7		8.1		23.6		16.3
Expected return on plan assets	Expected return on plan assets	(17.8)		(17.4)		(35.7)		(35.1)		Expected return on plan assets	(15.8)		(17.8)		(32.2)		(35.7)

Amortization of prior service credit	Amortization of prior service credit	—		(0.1)		(0.1)		(0.1)		Amortization of prior service credit	—		—		—		(0.1)
Amortization of net actuarial loss	Amortization of net actuarial loss	7.6		11.0		14.9		21.0		Amortization of net actuarial loss	2.7		7.6		4.6		14.9
Net periodic benefit cost	Net periodic benefit cost	$	0.9	$	5.1	$	2.1	$	8.5	Net periodic benefit cost	$	0.9	$	0.9	$	1.1	$	2.1


06/30/~~2022~~2023 Form 10-Q			17			Wisconsin Electric Power Company

Table of Contents


		OPEB Benefits									OPEB Benefits
		Three Months Ended June 30				Six Months Ended June 30					Three Months Ended June 30				Six Months Ended June 30
(in millions)	(in millions)	2022		2021		2022		2021		(in millions)	2023		2022		2023		2022
Service cost	Service cost	$	1.0	$	0.9	$	2.0	$	2.1	Service cost	$	0.6	$	1.0	$	1.3	$	2.0
Interest cost	Interest cost	1.4		1.4		2.8		2.7		Interest cost	1.9		1.4		3.8		2.8
Expected return on plan assets	Expected return on plan assets	(4.4)		(4.2)		(8.8)		(8.4)		Expected return on plan assets	(3.3)		(4.4)		(6.7)		(8.8)
Amortization of prior service credit	Amortization of prior service credit	(0.4)		(0.3)		(0.7)		(0.6)		Amortization of prior service credit	(0.2)		(0.4)		(0.4)		(0.7)
Amortization of net actuarial gain	Amortization of net actuarial gain	(3.1)		(2.8)		(6.1)		(5.5)		Amortization of net actuarial gain	(2.2)		(3.1)		(4.4)		(6.1)
Net periodic benefit credit	Net periodic benefit credit	$	(5.5)	$	(5.0)	$	(10.8)	$	(9.7)	Net periodic benefit credit	$	(3.2)	$	(5.5)	$	(6.4)	$	(10.8)

During the six months ended June 30, ~~2022,~~2023, we made contributions and payments of ~~$2.0~~$4.5 million related to our pension plans and ~~$2.0 million~~an insignificant amount related to our OPEB plans. We expect to make contributions and payments of ~~$1.4~~$0.2 million related to our OPEB plans and no further contributions related to our pension plans during the remainder of ~~2022,~~2023, dependent upon various factors affecting us, including our liquidity position and possible tax law changes. We

Effective January 1, 2023, the PSCW approved escrow accounting for pension and OPEB costs. As a result, as of June 30, 2023, we recorded a $1.1 million regulatory asset for pension costs and a $2.6 million regulatory asset for OPEB costs. The above tables do not ~~expect to make~~reflect any ~~contributions or payments related to our OPEB plans during~~adjustments for the ~~remainder~~creation of ~~2022.~~these regulatory assets.

NOTE ~~16—~~18—SEGMENT INFORMATION

We use net income attributed to common shareholder to measure segment profitability and to allocate resources to our ~~businesses.~~business. At June 30, ~~2022,~~2023, we reported 2two segments, our utility segment and our other segment, which are described below.

Our utility segment includes our electric utility operations, including steam operations, and our natural gas utility operations.

•Our electric utility operations are engaged in the generation, distribution, and sale of electricity to customers in southeastern Wisconsin (including metropolitan Milwaukee), east central Wisconsin, and northern Wisconsin. In addition, our steam operations produce, distribute, and sell steam to customers in metropolitan Milwaukee.

•Our natural gas utility operations are engaged in the purchase, distribution, and sale of natural gas to retail customers as well as the transportation of customer-owned natural gas in southeastern, east central, and northern Wisconsin.

No significant items were reported in the other segment during the three and six months ended June 30, ~~2022~~2023 and ~~2021.~~2022.

All of our operations and assets are located within the United States.

NOTE ~~17—~~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 our retired Pleasant Prairie power plant, the carrying costs accrued on the $100 million during the securitization process, and the related financing fees. The financing order also authorized us to form WEPCo Environmental Trust, a bankruptcy-remote special purpose entity, for the sole purpose of issuing ETBs to recover the costs approved in the financing order. WEPCo Environmental Trust is our ~~wholly-owned~~wholly owned subsidiary.


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


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affiliates.

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

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

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


(in millions)	(in millions)	June 30, 2022		December 31, 2021		(in millions)	June 30, 2023		December 31, 2022
Assets	Assets					Assets
Other current assets (restricted cash)	Other current assets (restricted cash)	$	3.1	$	2.4	Other current assets (restricted cash)	$	1.5	$	3.0
Regulatory assets	Regulatory assets	96.1		100.7		Regulatory assets	89.5		92.4
Other long-term assets (restricted cash)	Other long-term assets (restricted cash)	0.6		0.6		Other long-term assets (restricted cash)	0.6		0.6

Liabilities	Liabilities					Liabilities
Current portion of long-term debt	Current portion of long-term debt	8.8		8.8		Current portion of long-term debt	9.0		8.9

Other current liabilities (accrued interest)	Other current liabilities (accrued interest)	0.1		0.1		Other current liabilities (accrued interest)	0.1		0.1
Long-term debt	Long-term debt	98.4		102.7		Long-term debt	89.7		94.1

Power Purchase Commitment

On May 31, 2022, our PPA with LSP-Whitewater Limited Partnership that represented a variable interest expired. This agreement was for 236.5 MWs of firm capacity from a natural gas-fired cogeneration facility, and we accounted for it as a finance lease.

In November 2021, we entered into a tolling agreement with LSP-Whitewater Limited Partnership that commenced on June 1, 2022, upon the expiration of the PPA. Concurrent with the execution of the tolling agreement, we, along with WPS, entered into an agreement to purchase the natural gas-fired cogeneration facility. ~~Under~~This asset purchase agreement was approved by the PSCW in December 2022, and the acquisition closed effective January 1, 2023. In accordance with the purchase agreement, we ~~would acquire~~acquired a 50% ownership ~~interest, and our share~~interest. See Note 2, Acquisitions, for more information on the acquisition of ~~the cost is estimated to be $36.3 million. This purchase agreement is subject to regulatory approval by the PSCW, which is expected by the end of 2022.~~this facility. The tolling agreement ~~extends until the earlier of the closing of the asset purchase or December 31, 2022. The tolling agreement continues to represent~~represented a variable interest until the facility was acquired since its terms ~~are~~were substantially similar to the terms of the PPA. ~~After examining~~Based on the risks of the entity, including operations, maintenance, dispatch, financing, fuel costs, and other factors, we ~~have determined we are~~were not the primary beneficiary of the entity. We dodid not hold an equity or debt interest in the entity, and there iswas no residual guarantee associated with the tolling agreement. Similar to the PPA, we ~~account~~accounted for the tolling agreement as a finance lease.

We have $1.9 million of required capacity payments over the remaining term of the tolling agreement. We believe that the required capacity payments under the agreement will continue to be recoverable in rates, and our maximum exposure to loss is limited to these capacity payments.

NOTE ~~18—~~20—COMMITMENTS AND CONTINGENCIES

We have significant commitments and contingencies arising from our operations, including those related to unconditional purchase obligations, environmental matters, and enforcement and litigation matters.


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Unconditional Purchase Obligations

We have obligations to distribute and sell electricity and natural gas to our customers and expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. Our minimum future commitments related to these purchase obligations as of June 30, ~~2022,~~2023, were approximately ~~$8.3~~$7.6 billion.


~~06/30/2022 Form 10-Q~~			19			~~Wisconsin Electric Power Company~~

~~Table of Contents~~

Environmental Matters

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

Air Quality

Cross State Air Pollution Rule – Good Neighbor Plan

~~The~~In March 2023, the EPA issued ~~a proposed~~its final Good Neighbor Plan, which requires significant reductions in ozone-forming emissions of NOx from power plants and industrial facilities. The rule that would update and expand the Cross-State Air Pollution Rule's ozone-season NOx program to address the 2015 ozone NAAQS, resulting in more stringent regulation of ozone-season NOx emissions from EGUs in 26 states, relying on authorization through the CAA's “good neighbor provision." As part of the proposed rule, expected towill take effect in ~~May~~August 2023, during the EPA would establish a new trading program that would impose lower NOx emissions budgets on states, at levels that the EPA projected would be achievable through full operation of existing EGU emissions control equipment beginning during ozone season 2023, and through installation of additional control equipment at both EGU and non-EGU stationary sources by the startlatter half of the ~~2026~~2023 ozone ~~season, as well as planned plant retirements.~~

~~Based on a~~season. After review of ~~our existing units' 2020 and 2021 actual ozone season emissions and projected future emissions versus proposed NOx ozone season allocations,~~the final rule, we ~~anticipate~~believe that we ~~should be able~~are well positioned to ~~comply with~~meet the ~~expanded rule requirements without procuring additional allowances on the open market.~~requirements.

Our ~~planned~~ RICE units in Wisconsin are not currently subject to ~~this~~the final rule ~~as proposed~~ as each unit is ~~expected to be~~ less than 25 ~~MW. We note that, to~~MWs. To the extent we use RICE engines for natural gas distribution operations, those engines may be subject to the emission limits and operational requirements of the rule beginning in 2026. ~~In June 2022, we submitted comments on this proposed rule seeking clarification of its applicability, as well as other items, and we will closely monitor~~The EPA has exempted LDCs from the final rule ~~for any changes~~but included new language defining an LDC that we are still evaluating.

Mercury and Air Toxics Standards

In 2012, the EPA issued the MATS to limit emissions of mercury, acid gases, and other hazardous air pollutants. In April 2023, the EPA issued the pre-publication version of a proposed rule to strengthen and update MATS to reflect recent developments in control technologies and performance of coal and oil-fired units. The EPA proposed three revisions including a proposal to lower the PM limit from 0.03 lb/MMBtu to 0.01 lb/MMBtu, which could have an adverse effect on our utilities. The EPA is also seeking comments on an even lower limit of 0.006 lb/MMBtu. We submitted comments to the EPA in June 2023 addressing several concerning portions of the proposed ~~rule.~~rule revisions.

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,~~November 2022, the EPA's 2022 CASAC Ozone Review Panel issued a draft report supporting a previously issued EPA ~~completed its 5-year review~~staff-written Integrated Science Assessment for ozone which supported the reconsideration of the ~~ozone standard and~~2015 standard. The EPA staff issued a ~~final decision to retain, without any changes,~~draft Policy Assessment in March 2023 in support of revisiting 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. In October 2021, the EPA announced that it will reconsider the December 2020 decision to retain the 2015 ozone standards with no changes and indicated that ~~it is targeting the end of 2023~~they intend to ~~complete this reconsideration.~~publish their reconsideration in early 2024, with an anticipated final rule by early 2025.

~~The EPA issued final nonattainment area designations for~~In February 2022, revisions to the Wisconsin Administrative Code to adopt the 2015 ~~ozone~~ standard ~~in April 2018.~~were finalized. The ~~following counties within our service territory were designated as partial nonattainment: Door, Kenosha, Sheboygan, Manitowoc, and Northern Milwaukee/Ozaukee.~~amended regulations incorporated by reference the federal air pollution monitoring requirements related to the standard. The ~~area designations were 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~~WDNR submitted the rule updates as a SIP revision to the EPA, ~~for further evaluation. As a result of the July 2020 remand, in June 2021,~~which the EPA ~~published its final action to revise the nonattainment area designations and/or boundaries for 13 counties associated with 6 nonattainment areas, including several~~approved 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, IL-IN-WI nonattainment area now includes an expanded portion of Kenosha County, and the partial nonattainment areas of Sheboygan, Door, and Manitowoc counties were also expanded.February 2023.

In April 2022, the EPA proposed to find that the Milwaukee and Chicago, IL-IN-WI nonattainment areas did not meet the marginal attainment deadline of August 2021 and ~~will~~should be adjusted to "moderate" nonattainment status for the 2015 standard. In October 2022, the EPA published its final reclassifications from "marginal" to "moderate" for these areas, effective November 7, 2022. Accordingly, ~~Wisconsin must submit State Implementation Plan revisions~~the WDNR submitted a SIP revision to the EPA in December 2022 to address the ~~reclassifications. A final rulemaking for the designations is expected in October 2022.~~moderate nonattainment status.


06/30/~~2022~~2023 Form 10-Q			20			Wisconsin Electric Power Company

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In February 2022, revisions to the Wisconsin Administrative Code to adopt the 2015 standard were finalized. The amended regulations adopted the standard and incorporated by reference the federal air pollution monitoring requirements related to the standard. We believe that we are well positioned to meet the requirements associated with the 2015 ozone standard and do not expect to incur significant costs to comply with the associated state and federal rules.

Particulate Matter

In December 2020, the EPA completed its 5-year review of the 2012 annual and 24-hour standards for fine ~~particulate matter. The EPA~~PM and determined that no revisions were necessary to the current annual standard of 12 µg/m3 or the 24-hour standard of 35 µg/m3. ~~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~~PM NAAQS to below the current level of 12 µg/m3, while retaining the 24-hour standard. In ~~March 2022, the EPA’s CASAC sent a letter to~~January 2023, the EPA ~~finalizing~~announced its ~~peer review~~proposed decision to revise the primary (health-based) annual PM2.5 standard from its current level of ~~the particulate matter standards. Based on their review, the majority of the members of the CASAC found that lowering the annual standard~~12 µg/m3 to within athe range of 89 to 10 µg/m3 ~~was appropriate, while a minority of~~. The EPA also proposed not to change the ~~members of~~current secondary (welfare-based) annual PM2.5 standard, primary and secondary 24-hour PM2.5 standards, and primary and secondary PM10 standards. The EPA did, however, take comments on the ~~committee found that a~~full range ~~of 10 to~~(between 8 and 11 µg/m3 ~~would be appropriate. Additionally, a majority of~~) included in the CASAC members favored lowering the 24-hour standard, while a minority concurred with EPA’s preliminary conclusion to retain the 24-hour standard without revision. In May 2022, the EPA released its staff-written Policy Assessment forCASAC's latest report. A final decision on the reconsideration ~~of the standard. Similar to the CASAC findings, the EPA staff found that conditions supported either an annual standard~~is anticipated in ~~the 10 to 12 µg/m~~3 ~~range or in the 8 to 10 µg/m~~3 ~~range.~~

~~A proposed rule is expected in August 2022, and a final rule is expected in spring~~late summer 2023. All counties within our service territory are in attainment with the current 2012 standards. If the EPA lowers the annual standard to 10 or 11 µg/m3, our generating facilities within our service territory should remain in attainment. If the EPA lowers it to below 10 µg/m3, there could be some ~~non-attainment~~nonattainment areas that may affect permitting of some smaller ancillary equipment located at our facilities. After finalization of the rule, the WDNR will need to draft and submit a SIP for the EPA's approval.

Climate Change

~~The ACE~~In May 2023, the EPA proposed GHG performance standards for existing fossil-fired steam generating and gas combustion units and also proposed to repeal the Affordable Clean Energy rule, which replaced the Clean Power ~~Plan, was vacated by~~Plan. For coal plants, there are no applicable standards until 2032, and after 2032 the ~~D.C. Circuit Court of Appeals in January 2021. In October 2021,~~applicable standard is dependent on the ~~Supreme Court agreed to review~~unit's retirement date. For combined cycle natural gas plants above a 50% capacity factor, the ~~D.C. Circuit Court's ruling vacating~~rule is highly dependent on hydrogen as an alternative fuel, or carbon capture. For simple cycle natural gas-fired combustion turbines, there are no applicable limits as long as the ~~EPA's ACE~~capacity factor is less than 20%. The new Weston RICE project is not affected under the rule ~~and in June 2022,~~because each RICE unit is less than 25 MWs. We are evaluating the Supreme Court issued its decision. The Supreme Court found that the EPA may regulate GHGs under section 111 of the CAA but cannot rely on generation shifting to lower carbon emitting sources to do so. Based on an updated EPA regulatory timeline, we expect a new GHG replacementproposed rule to ~~be proposed in March 2023.~~understand the impacts to our operations.

In ~~January 2021,~~May 2023, the EPA ~~finalized a rule~~proposed to revise the New Source Performance Standards for GHG emissions from new, modified, and reconstructed fossil-fueled power ~~plants; however, it was vacated~~plants. The EPA is proposing two distinct 111(b) rules – one for natural gas-fired stationary combustion turbines and the other for coal-fired units. New stationary combustion turbine units would be divided into three subcategories based on their annual capacity factor – low load, intermediate load, and base load. Our RICE units are not affected by ~~the D.C. Circuit Court of Appeals in April 2021. Based on an updated EPA regulatory timeline, we expect a new~~this rule ~~to be proposed in March 2023.~~since each unit is below 25 MWs. WEC Energy Group continues to move forward on the ESG Progress Plan, which is heavily focused on reducing GHG emissions.

The EPA released proposed regulations for the Mandatory Greenhouse Gas Reporting Rule, 40 Code of Federal Regulations Part 98, in June 2022. In May 2023, the EPA released a supplementary proposal, which includes updates of the global warming potentials to determine CO2 equivalency for threshold reporting and the addition of a new section regarding energy consumption. The proposed revisions could impact the reporting required for our electric generation facilities, local natural gas distribution companies, and underground natural gas storage facilities. In July 2023, the EPA also issued a pre-publication version of its proposal to amend reporting requirements for petroleum and natural gas systems, with an anticipated final rule to be issued in early 2024. We are currently evaluating the potential impact, if any, of the proposed rule.

The ESG Progress Plan includes the retirement of older, fossil-fueled generation, to be replaced with zero-carbon-emitting renewables and clean natural gas-fueled generation. We have already retired approximately 1,500 MWMWs of ~~coal-fired~~fossil-fueled generation since the beginning of 2018. Through its ESG Progress Plan, WEC Energy Group expects to retire approximately ~~1,600 MW~~1,500 MWs of additional fossil-fueled generation by the end of 2026, which includes the planned retirements in 2024-2025 of OCPP Units 5-8. See Note ~~20, Regulatory Environment,~~7, Property, Plant, and Equipment, for more information on the timing of the retirements. In May 2021, WEC Energy Group announced goals to achieve reductions in carbon emissions from its electric generation fleet by 60% by the end of 2025 and by 80% by the end of 2030, both from a 2005 baseline. WEC Energy Group expects to achieve these goals by making operating refinements, retiring less efficient generating units, and executing its capital plan. Over the longer term, the target for WEC Energy Group's generation fleet is net-zero CO2 emissions by 2050.

WEC Energy Group also continues to reduce methane emissions by improving its natural gas distribution systems, and has set a target across its natural gas distribution operations to achieve net-zero methane emissions by the end of 2030. WEC Energy Group


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plans to achieve its net-zero goal through an effort that includes both continuous operational improvements and equipment upgrades, as well as the use of RNG throughout its utility systems.


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Water Quality

Clean Water Act Cooling Water Intake Structure Rule

~~In August 2014, the~~The EPA issued a final regulation under Section 316(b) of the ~~Clean Water Act~~CWA that became effective in October 2014 and 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 ~~leased~~ ERGS units, which were permitted and received a final BTA determination under the rules governing new facilities. ~~In 2016,~~

Pursuant to a WDNR rule, which became effective in June 2020, the ~~WDNR initiated a state rulemaking process to incorporate the~~requirements of federal Section 316(b) ~~requirements~~of the CWA were incorporated into the Wisconsin Administrative Code. ~~This new state~~The WDNR applies this rule ~~NR 111, became effective in June 2020, and the WDNR will apply it~~ when establishing BTA requirements for cooling water intake structures at existing facilities. These BTA requirements are incorporated into WPDES permits for our facilities.

We have received a final BTA determination for Valley power plant. We have received interim BTA determinations for PWGS and OCPP Units 5-8. We believe that existing technology at the PWGS satisfies the BTA requirements; however, a final determination will not be made until the WPDES permit is renewed for this facility, which is expected to be by the third quarter of 2022. We also believe that existing technology installed at the OCPP facility meets the BTA requirements; however, depending on the timing of the permit reissuance, all 4four generating units at the OCPP may be retired prior to the WDNR making a final BTA decision, anticipated in 2025.

We are engaged in discussions with the WDNR regarding the current status of the BTA determination at PWGS. There is uncertainty about whether existing technology meets all of the WDNR's BTA requirements. We will not be in a position to determine what, if any, modifications may be needed at PWGS until the WDNR issues the WPDES permit renewal for PWGS, expected during the third quarter of 2023.

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

Steam Electric Effluent Limitation Guidelines

The EPA's ~~final 2015~~ ELG rule, ~~took effect in~~effective January 2016 and ~~was~~ modified in 2020, ~~to revise~~revised the treatment technology requirements related to BATW and wet FGD wastewaters at existing ~~facilities. This rule~~coal-fueled facilities and created new requirements for several types of power plant wastewaters. The 2two new requirements that affect us relate to discharge limits for BATW and wet FGD wastewater. ~~Our~~Although our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this ~~rule. Modifications~~rule, certain facility modifications are necessary to meet the ELG rule requirements. Through 2023, we expect that compliance costs associated with the ELG rule will require $97 million in capital investment. An $8 million BATW modification to OC 7 and OC 8 ~~were~~was completed and placed in-service in ~~mid-2021. Wastewater treatment system modifications also will be required for wet FGD discharges~~mid-2021, and ~~site wastewater from the ERGS units. Based on engineering cost estimates, we expect that compliance with the ELG rule will require $90 million~~ in ~~capital investment. In~~ December 2021, the PSCW ~~Division of Energy Regulation and Analysis~~ issued a Certificate of Authority approving the $89 million ERGS FGD wastewater treatment system modification. The BATW modifications dodid not require PSCW approval prior to construction. All of these ELG required projects are either in-service or are on track for completion by the WPDES permit deadline in December 2023.

In ~~July 2021,~~March 2023, the EPA ~~announced~~issued the proposed "supplemental ELG rule." The rule would replace the existing 2020 ELG rule and, as proposed, would establish stricter limitations on: 1) BATW; 2) FGD wastewater; 3) CCR leachate; and 4) legacy wastewaters. The most significant proposed ELG rule change is a ZLD requirement for FGD wastewater. Under the proposed rule, this new ZLD requirement must be met by a date determined by the WDNR that ~~it intends~~is as soon as possible beginning 60 days following publication of the final rule, but no later than December 31, 2029.

The proposed rule would also create a subcategory for "early adopters" that have already installed a compliant biological treatment system by the date of the proposed rule. Early adopters would not be required to ~~initiate rulemaking~~install further FGD wastewater treatment, provided the facility owner also agrees to ~~revise~~permanently cease combustion of coal by December 31, 2032. Although we are currently completing an $89 million biological treatment system at ERGS, which we expect to be complete later this year, the expected timing of the project's completion would not comply with the deadline imposed by the EPA to qualify for early adopter status. In addition, we do not believe that, upon its completion, the biological treatment system would be compliant with the additional ZLD FGD wastewater treatment requirements as proposed. In May 2023, we submitted written comments to the EPA.


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If the supplemental ELG ~~Rule~~rule is finalized as ~~modified~~proposed, we anticipate that our coal-fueled facilities will meet the BATW rule provisions. BATW projects were completed at the OCPP Units 7 and 8 in ~~2020.~~ June 2021. ERGS Units 1 and 2 and OCPP Units 5 and 6 were both built with ELG-compliant dry BATW systems.

The EPA ~~has stated that the ELG Rule will continue~~also proposed requirements for legacy wastewaters and landfill leachate. We are reviewing those proposed requirements to ~~be implemented~~determine potential costs and ~~enforced while the agency pursues this rulemaking process. The EPA plans to propose a revised rule in the fall of 2022.~~actions required for our facilities.

Waters of the United States

In ~~December 2021,~~January 2023, the EPA and the ~~United States~~ Army Corps ~~of Engineers~~ together released a ~~proposed~~final rule ~~to repeal~~effective in March 2023, that based the ~~April 2020 Navigable Waters Protection Rule that defined WOTUS. The purpose~~definition of ~~this proposed rule will be to restore regulations defining~~ WOTUS ~~that were in place prior to 2015 and to update certain provisions to be consistent with relevant Supreme Court decisions.~~on its pre-2015 definition. 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.

In ~~January 2022,~~May 2023, the Supreme Court ~~granted certiorari~~issued a decision significantly narrowing federal jurisdiction over wetlands. In Sackett v. Environmental Protection Agency, the court ruled that the federal government's jurisdiction over WOTUS extends to "traditional navigable waters" and wetlands or other waters that have a "continuous surface connection" with a traditional navigable water.

Following the Supreme Court decision, the agencies announced they would interpret the definition of WOTUS consistent with the Sackett decision. The agencies are also developing a new rule to amend the definition of WOTUS that was published in the Federal Register in January 2023, to be consistent with the Sackett decision. The agencies have indicated that they intend to issue a ~~case to evaluate~~new final rule by September 2023.

We anticipate the ~~proper test for determining whether wetlands are WOTUS.~~Sackett decision will cause a decrease in the number of projects that require Army Corps federal wetland permits. The Sackett decision may also affect the administration of some state programs. At this point, our projects requiring federal permits are moving ahead, but we are monitoring these recent developments to better understand potential future impacts. ~~This case, once decided, should provide clarity regarding the definition of WOTUS. We will continue to monitor this litigation and any subsequent agency action.~~


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Land Quality

Manufactured Gas Plant Remediation

We have identified sites at which we or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. We are responsible for the environmental remediation of these sites. We are also working with the state of Wisconsin in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure.

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

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


(in millions)	(in millions)	June 30, 2022		December 31, 2021		(in millions)	June 30, 2023		December 31, 2022
Regulatory assets	Regulatory assets	$	15.9	$	16.8	Regulatory assets	$	13.6	$	14.6
Reserves for future environmental remediation (1)	Reserves for future environmental remediation (1)	10.6		10.7		Reserves for future environmental remediation (1)	10.3		10.3

(1)Recorded within other long-term liabilities on our balance sheets.

Coal Combustion Residuals Rule

The EPA issued a pre-publication proposed rule for CCR in May 2023, that would apply to all landfills, historic fill sites, and projects where CCR was placed. As proposed, the rule would regulate previously exempt closed landfills and would include sites we own as well as several third party owned properties.


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We are actively engaged with the Utility Solid Waste Activities Group and the Edison Electric Institute in evaluating and commenting on this rule. The proposed rule could have a material adverse impact on our coal ash landfills and require additional remediation that has not been required under the current state programs.

Enforcement and Litigation Matters

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

NOTE ~~19—~~21—SUPPLEMENTAL CASH FLOW INFORMATION

Six Months Ended June 30
(in millions) 2022 2021
Cash paid for interest, net of amount capitalized $ 225.3 $ 234.0
Cash paid for income taxes, net 43.2 40.3
Significant non-cash investing and financing transactions:
Accounts payable related to construction costs 125.8 50.0
Increase in receivable related to insurance proceeds — 39.6
Liabilities accrued for software licensing agreement 3.1 —

Non-Cash Transactions


	Six Months Ended June 30
(in millions)	2023		2022
Cash paid for interest, net of amount capitalized	$	233.5	$	225.3
Cash paid for income taxes, net	65.0		43.2
Significant non-cash investing and financing transactions:
Accounts payable related to construction costs	61.0		125.8


Liabilities accrued for software licensing agreement	—		3.1

Restricted Cash

The statements of cash flows include our activity related to cash, cash equivalents, and restricted cash. Our restricted cash primarily consists of cash on deposit in financial institutions that is restricted to satisfy the requirements of certain debt agreements at WEPCo Environmental Trust. See Note 17, Variable Interest Entities, for more information.

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)	(in millions)	June 30, 2022		December 31, 2021		(in millions)	June 30, 2023		December 31, 2022
Cash and cash equivalents	Cash and cash equivalents	$	2.0	$	—	Cash and cash equivalents	$	28.7	$	6.1
Restricted cash included in other current assets	Restricted cash included in other current assets	3.1		2.4		Restricted cash included in other current assets	1.5		3.0
Restricted cash included in other long term assets		0.6		0.6
Restricted cash included in other long-term assets						Restricted cash included in other long-term assets	0.6		38.6
Cash, cash equivalents, and restricted cash	Cash, cash equivalents, and restricted cash	$	5.7	$	3.0	Cash, cash equivalents, and restricted cash	$	30.8	$	47.7


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Our restricted cash consisted of the following:

•Cash on deposit in a financial institution that is restricted to satisfy the requirements of a debt agreement at WEPCo Environmental Trust. See Note 19, Variable Interest Entities, for more information.

~~Table of Contents~~•Cash used during January 2023 to purchase a natural gas-fired cogeneration facility located in Whitewater, Wisconsin. This cash was included in other long-term assets at December 31, 2022. See Note 2, Acquisitions, for more information.

NOTE ~~20—~~22—REGULATORY ENVIRONMENT

~~2023 and~~ 2024 ~~Rates~~Limited Rate Case Re-Opener

In ~~April~~accordance with our rate order approved by the PSCW in December 2022, we filed a request with the PSCW ~~to increase our retail~~on May 15, 2023 for a limited electric and natural gas ~~and steam rates, effective January 1, 2023. The requested increase in~~rate case re-opener. Our limited electric ~~rates was driven by capital investments in new wind, solar, and battery storage; capital investments in natural gas generation; reliability investments, including grid hardening~~rate case re-opener includes updated revenue requirements for the generation projects to bury power lines and strengthen our distribution system against severe weather; and changes in wholesale business with other utilities. Many of these investments have already been approved by the PSCW. The requested increase in natural gas rates primarily related to capital investmentsthat were previously approved by the PSCW ~~including LNG storage for our natural gas distribution system.~~

~~In July 2022, we updated our rate request to reflect recent developments that impacted our original proposal for rate increases in 2023. These recent developments included:~~

•~~Delays in the in-service dates of Darien~~ and ~~the battery portion of Paris due to supply chain disruptions.~~

•Our decision to extend the operating life of the OCPP due to tight energy supply conditions in MISO and the delay in the renewable energy projects discussed above. The expected retirement of the OCPP Units 5 and 6 was delayed one year, until May 2024, and the retirement of units 7 and 8 was delayed approximately 18 months, until late 2025.

•~~Increases in the cost of Badger Hollow II.~~

•~~The effect of anticipated increases in interest rates on borrowing costs.~~

•~~An industry-wide update to S&P's methodology for assessing the impact of PPAs on utility's credit ratings.~~

~~The updated rate request proposal includes an aggregate increase of approximately $30 million from the original proposal and is reflected in the following table:~~

Proposed 2023 rate increase
Electric $ 285.6 million / 9.2%
Gas $ 55.4 million / 11.7%
Steam $ 3.6 million / 16.5%
Proposed ROE (1)
10.0%
Proposed common equity component average on a financial basis (1)
53.0%

~~(1)~~ ~~The proposed ROE is consistent with our currently authorized ROE. Our common equity component average is currently 52.5%.~~

We are proposing to continue using an earnings sharing mechanism. Under the proposed earnings sharing mechanism, if we earn above our authorized ROE: (i) we would retain 100.0% of earnings for the first 25 basis points above the authorized ROE; (ii) 50.0% of the next 50 basis points would be required to be refunded to ratepayers; and (iii) 100.0% of any remaining excess earnings would be required to be refunded to ratepayers.

~~We are seeking a limited rate case re-opener for 2024 to address additional revenue requirements associated with generation projects that~~ are expected to be placed into service in 2023 and ~~2024~~2024. It also includes the projected savings from the retirement of the OCPP units 5 and 6, which are expected to be retired in May 2024. Our limited natural gas rate case re-opener reflects the additional revenue requirements associated with our previously approved LNG project that is expected to be placed into service in ~~2023.~~

~~We expect a decision from the PSCW in the fourth quarter of 2022, with any rate adjustments expected to be effective January 1,~~ 2023.


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The requested increases in 2024 base rates are as follows:


Requested 2024 base rate increases
Electric	$	45.0	million	/	1.3%
Gas	$	23.9	million	/	4.5%

Our return on equity and common equity component average will not be addressed in the limited rate case re-opener. A PSCW decision is expected in the fourth quarter of 2023, with new rates expected to be effective January 1, 2024.

NOTE ~~21—~~23—NEW ACCOUNTING PRONOUNCEMENTS

~~0Reference~~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~~and in January 2021, the FASB issued ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope. These pronouncements provide temporary optional expedients and exceptions for applying GAAP principles to ~~contracts,~~contract modifications and hedging relationships to ease the financial reporting burdens of the market transition from LIBOR and other ~~transactions affected by~~interbank offered rates to alternative 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 arerates. These pronouncements were effective ~~for all entities as of~~upon issuance on March 12, 2020 through December 31, 2022. ~~We are currently evaluating the impact this guidance may have on our financial statements and related disclosures.~~

~~Government Assistance~~

In ~~November 2021,~~December 2022, the FASB issued ASU No. ~~2021-10, Government Assistance~~2022-06, Reference Rate Reform (Topic 832). The amendments in this update increase the transparency surrounding government assistance by requiring disclosure of: (i) the types of assistance received; (ii) an entity’s accounting for the assistance; and (iii) the effect848): Deferral of the ~~assistance on~~Sunset Date of Topic 848, to extend the ~~entity’s financial statements. The update is effective for annual periods beginning after December 15, 2021. We plan to adopt this pronouncement for our fiscal year ending on~~temporary accounting rules under Topic 848 from December 31, 2022 ~~and we are currently evaluating~~to December 31, 2024, after which entities will no longer be permitted to apply the ~~impact~~relief in Topic 848. An entity may elect to apply the amendments prospectively from March 12, 2020 through December 31, 2024 by accounting topic. We do not anticipate this guidance ~~may have~~having a significant impact on our financial statements and related disclosures.


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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

CORPORATE DEVELOPMENTS

The following discussion should be read in conjunction with the accompanying unaudited financial statements and related notes and our ~~2021~~2022 Annual Report on Form 10-K.

Introduction

We are a wholly owned subsidiary of WEC Energy Group, and derive revenues from the distribution and sale of electricity and natural gas to retail customers in Wisconsin. We also provide wholesale electric service to numerous utilities and cooperatives for resale. We conduct our business primarily through our utility reportable segment. See Note ~~16,~~18, Segment Information, for more information on our reportable business segments.

Corporate Strategy

Our goal is to continue to build and sustain long-term value for our customers and WEC Energy Group's shareholders by focusing on the fundamentals of our business: environmental stewardship; reliability; operating efficiency; financial discipline; exceptional customer care; and safety. WEC Energy Group's capital investment plan for efficiency, sustainability and growth, referred to as its ESG Progress Plan, provides a roadmap to achieve this goal. It is an aggressive plan to cut emissions, maintain superior reliability, deliver significant savings for customers, and grow WEC Energy Group's and our investment in the future of energy.

Throughout its strategic planning process, WEC Energy Group takes into account important developments, risks and opportunities, including new technologies, customer preferences and affordability, energy resiliency efforts, and sustainability. WEC Energy Group published the results of a priority sustainability issue assessment in 2020, identifying the issues that are most important to the company and its stakeholders over the short and long terms. This risk and priority assessment has formed WEC Energy Group's direction as a company.

Creating a Sustainable Future

WEC Energy Group's ESG Progress Plan includes the retirement of older, fossil-fueled generation, to be replaced with zero-carbon-emitting renewables and clean natural gas-fired generation at its electric utilities, including us. When taken together, the retirements and new investments should better balance supply with demand, while maintaining reliable, affordable energy for our customers. The retirements will contribute to meeting WEC Energy Group's and our goals to reduce CO2 emissions from electric generation.

~~In May 2021,~~ WEC Energy Group announced goals to achieve reductions in carbon emissions from its electric generation fleet by 60% by the end of 2025 and by 80% by the end of 2030, both from a 2005 baseline. WEC Energy Group expects to achieve these goals by making operating refinements, retiring less efficient generating units, and executing its capital plan. Over the longer term, the target for its generation fleet is net-zero CO2 emissions by 2050.

As part of the path toward these goals, we are exploring co-firing with natural gas at the ERGS coal-fired units. By the end of 2030, WEC Energy Group expects to use coal as a backup fuel only, and ~~WEC Energy Group~~ believes it will be in a position to eliminate coal as an energy source by the end of 2035.

WEC Energy Group already has retired more than ~~1,800~~1,900 MWs of ~~coal-fired~~fossil-fueled generation since the beginning of 2018, which included the 2019 retirement of the Presque Isle power plant as well as the 2018 retirement of the Pleasant Prairie power plant. Through the ESG Progress Plan, WEC Energy Group expects to retire approximately ~~1,600 MW~~1,500 MWs of additional fossil-fueled generation by the end of 2026, which includes the planned retirement in 2024-2025 of OCPP Units 5-8. ~~See Note 20, Regulatory Environment, for information on the delay of these planned retirements.~~


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In addition to retiring these older, fossil-fueled plants, WEC Energy Group expects to invest approximately ~~$3.5~~$5.4 billion from ~~2022-2026~~2023-2027 in regulated renewable energy in Wisconsin. WEC Energy Group's plan is to replace a portion of the retired capacity by building and owning zero-carbon-emitting renewable generation facilities that are anticipated to include the following new investments made by either us or WPS based on specific customer needs:

•~~1,400 MW~~1,900 MWs of utility-scale ~~solar (amount does not include Badger Hollow II, which is currently under construction);~~solar;

•~~800 MW~~700 MWs of battery storage; and

•~~100 MW~~600 MWs of wind.


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WEC Energy Group also plans on investing in a combination of clean, natural gas-fired generation, made by either us or WPS based on specific customer needs, ~~including:~~

•~~100 MW of RICE natural gas-fueled generation;~~

•including the planned purchase of ~~200 MW~~up to 100 MWs of additional capacity in West Riverside — a ~~combined-cycle~~combined cycle natural gas plant recently completed and operated by Alliant Energy in ~~Wisconsin; and~~

•~~the planned purchase of Whitewater, a natural gas-fired combined-cycle electric generating facility with a capacity of 236.5 MW.~~Wisconsin.

~~The new investments discussed above are in addition to the renewable projects currently underway.~~ For more details, see Liquidity and Capital Resources – Cash Requirements – Significant Capital Projects.

In addition, we have partnered with an unaffiliated utility to construct Badger Hollow II, a utility scale solar project that is expected to enter commercial operation in the first half of 2023. Once constructed, we will own 100 MW of the project.

In December 2018, we received approval from the PSCW for two renewable energy pilot programs. The Solar Now pilot is expected to add a total of 35 MWMWs of solar generation to our portfolio, allowing non-profit and government entities, as well as commercial and industrial customers, to site utility owned solar arrays on their property. Under this program, we have energized 2325 Solar Now projects and currently have another ~~three~~four under construction, together totaling more than ~~29 MW.~~30 MWs. The second program, the ~~Dedicated Renewable Energy Resource~~DRER pilot, would allow large commercial and industrial customers to access renewable resources that we would operate, ~~adding~~and could add up to ~~150 MW~~35 MWs of renewables to our ~~portfolio, and helping~~portfolio. The DRER pilot would help these larger customers to meet their sustainability and renewable energy goals. In July 2023, we received approval from the PSCW for the Renewable Pathway Pilot, the third renewable energy program. This program allows commercial and industrial customers to subscribe to a portion of a utility-scale, Wisconsin-based renewable energy generating facility. The Renewable Pathway Pilot will utilize generation from Paris and Darien and will have a participation cap of 125 MW.

In August 2021, the PSCW approved pilot programs for us to install and maintain EV charging equipment for customers at their homes or businesses. The programs provide direct benefits to customers by removing cost barriers associated with installing EV equipment. In October 2021, subject to the receipt of any necessary regulatory approvals, WEC Energy Group pledged to expand the EV charging network within its utilities' electric service territories. In doing so, WEC Energy Group joined a coalition of utility companies in a unified effort to make EV charging convenient and widely available throughout the Midwest. The coalition ~~WEC Energy Group joined~~ is planning to help build and grow EV charging corridors, enabling the general public to safely and efficiently charge their vehicles.

WEC Energy Group also continues to reduce methane emissions by improving its natural gas distribution system, and has set a target across its natural gas distribution operations to achieve net-zero methane emissions by the end of 2030. WEC Energy Group plans to achieve its net-zero goal through an effort that includes both continuous operational improvements and equipment upgrades, as well as the use of RNG throughout its natural gas utility systems. In 2022, we received approval from the PSCW for an RNG pilot associated with our natural gas distribution system.

~~As part~~We are planning for the start of ~~WEC Energy Group's effort to look for new opportunities in sustainable energy, it is testing the effects of blending hydrogen,~~ a ~~clean generating fuel, with natural gas at one of its RICE generating units~~pilot program in the ~~Upper Peninsula~~fourth-quarter of ~~Michigan. WEC Energy Group is partnering~~2023 with the Electric Power Research Institute and CMBlu Energy, a Germany-based designer and manufacturer, to test a new form of long-duration energy storage on the U.S. electric grid. The program will test battery system performance, including the ability to store and discharge energy for up to twice as long as the typical lithium-ion batteries in ~~this research that could help create another viable option for decarbonizing the economy. The project is being carried out in 2022, and the results will be shared across the industry.~~use today.

Reliability

We have made significant reliability-related investments in recent years, and in accordance with the ESG Progress Plan, expect to continue strengthening and modernizing our generation fleet, as well as our electric and natural gas distribution networks to further improve reliability.


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We received approval to construct an LNG facility to meet anticipated peak demand. Commercial operation of the LNG facility is targeted for the end of 2023.

For more details, see Liquidity and Capital Resources – Cash Requirements – Significant Capital Projects.

Operating Efficiency

We continually look for ways to optimize the operating efficiency of our company and will continue to do so under the ESG Progress Plan. For example, we are making progress on our AMI program, replacing aging meter-reading equipment on both our network and customer property. An integrated system of smart meters, communication networks, and data management programs enables two-way communication between us and our customers. This program reduces the manual effort for disconnects and reconnects and enhances outage management capabilities.

WEC Energy Group continues to focus on integrating the resources of its businesses and finding the best and most efficient processes.


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Financial Discipline

A strong adherence to financial discipline is essential to meeting our earnings projections and maintaining a strong balance sheet, stable cash flows, and quality credit ratings.

We follow an asset management strategy that focuses on investing in and acquiring assets consistent with our strategic plans, as well as disposing of assets, including property, plants, and equipment, that are no longer strategic to operations, are not performing as intended, or have an unacceptable risk profile. See Note 2, ~~Acquisition,~~Acquisitions, for more information on our ~~acquisition~~acquisitions of ~~Whitewater.~~Whitewater and West Riverside. See Note 3, Disposition, for information on a recent transaction.

Exceptional Customer Care

Our approach is driven by an intense focus on delivering exceptional customer care every day. We strive to provide the best value for our customers by demonstrating personal responsibility for results, leveraging our capabilities and expertise, and using creative solutions to meet or exceed our customers’ expectations.

A multiyear effort is driving a standardized, seamless approach to digital customer service across all of the WEC Energy Group companies. It has moved all utilities, including us, to a common platform for all customer-facing self-service options. Using common systems and processes reduces costs, provides greater flexibility and enhances the consistent delivery of exceptional service to customers.

Safety

Safety is one of our core values and a critical component of our culture. We are committed to keeping our employees and the public safe through a comprehensive corporate safety program that focuses on employee engagement and elimination of at-risk behaviors.

Under our "Target Zero" mission, we have an ultimate goal of zero incidents, accidents, and injuries. Management and union leadership work together to reinforce the Target Zero culture. We set annual goals for safety results as well as measurable leading indicators, in order to raise awareness of at-risk behaviors and situations and guide injury-prevention activities. All employees are encouraged to report unsafe conditions or incidents that could have led to an injury. Injuries and tasks with high levels of risk are assessed, and findings and best practices are shared across the WEC Energy Group companies.

Our corporate safety program provides a forum for addressing employee concerns, training employees and contractors on current safety standards, and recognizing those who demonstrate a safety focus.


~~06/30/2022 Form 10-Q~~			28			~~Wisconsin Electric Power Company~~

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RESULTS OF OPERATIONS

THREE MONTHS ENDED JUNE 30, ~~2022~~2023

Earnings

Our earnings for the second quarter of ~~2022~~2023 were ~~$77.8~~$111.6 million, compared with ~~$78.8~~$77.8 million for the same quarter in ~~2021.~~2022. See below for ~~additional~~ information on the ~~$1.0~~$33.8 million ~~decrease~~increase in earnings.

Non-GAAP Financial Measures

The discussion below addresses the contribution of our utility segment to net income attributed to common shareholder. The discussion includes financial information prepared in accordance with GAAP, as well as electric margins and natural gas margins, which are not measures of financial performance under GAAP. Electric margins (electric revenues less fuel and purchased power costs) and natural gas margins (natural gas revenues less cost of natural gas sold) are non-GAAP financial measures because they exclude other operation and maintenance expense, depreciation and amortization, and property and revenue taxes.


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in current rates. As a result, management uses electric and natural gas margins internally when assessing the operating performance of our utility segment as these measures exclude the majority of revenue fluctuations caused by changes in these expenses. Similarly, the presentation of electric and natural gas margins herein is intended to provide supplemental information for investors regarding our operating performance.

Our electric margins and natural gas margins may not be comparable to similar measures presented by other companies. Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance. Our utility segment operating income for the three months ended June 30, 2023 and 2022 was $244.1 million and $206.5 million, respectively. The discussion below includes a table that provides the calculation of electric margins and natural gas margins, along with a reconciliation to the most directly comparable GAAP measure, operating income.

Utility Segment Contribution to Net Income Attributed to Common Shareholder

The following table compares our utility segment's contribution to net income for the second quarter of 2023, with the same quarter in 2022, including favorable or better, "B", and unfavorable or worse, "W", variances.


	Three Months Ended June 30
(in millions)	2023		2022		B (W)
Electric revenues	$	828.9	$	846.1	$	(17.2)
Fuel and purchased power	261.5		323.2		61.7
Total electric margins	567.4		522.9		44.5

Natural gas revenues	71.4		97.4		(26.0)
Cost of natural gas sold	31.0		62.3		31.3
Total natural gas margins	40.4		35.1		5.3

Total electric and natural gas margins	607.8		558.0		49.8

Other operation and maintenance	206.0		205.3		(0.7)
Depreciation and amortization	129.3		119.7		(9.6)
Property and revenue taxes	28.4		26.5		(1.9)
Operating income	244.1		206.5		37.6

Other income, net	19.0		11.4		7.6
Interest expense	116.9		113.1		(3.8)
Income before income taxes	146.2		104.8		41.4

Income tax expense	34.3		26.7		(7.6)
Preferred stock dividends of subsidiary	0.3		0.3		—
Net income attributed to common shareholder	$	111.6	$	77.8	$	33.8

The following table shows a breakdown of other operation and maintenance:


	Three Months Ended June 30
(in millions)	2023		2022		B (W)
Operation and maintenance not included in line items below	$	57.5	$	91.3	$	33.8
Transmission (1)	87.9		69.0		(18.9)
We Power (2)	35.5		27.3		(8.2)
Regulatory amortizations and other pass through expenses (3)	25.3		17.7		(7.6)
Earnings sharing mechanism	(0.2)		—		0.2
Total other operation and maintenance	$	206.0	$	205.3	$	(0.7)

(1)Represents transmission expense that we are authorized to collect in rates. The PSCW has approved escrow accounting for ATC and MISO network transmission expenses. As a result, we defer as a regulatory asset or liability, the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During the second quarter of 2023 and 2022, $83.0 million and $86.0 million, respectively, of costs were billed to us by transmission providers.


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During the second quarter of 2022, we amortized $15.5 million of the regulatory liabilities associated with our transmission escrow to offset certain 2022 revenue deficiencies, as approved by the PSCW in order to forego filing for a 2022 base rate increase. This amortization drove the lower transmission expense during the second quarter of 2022.

(2)Represents costs associated with the We Power generation units, including operating and maintenance costs we recognized. During the second quarter of 2023 and 2022, $35.8 million and $26.1 million, respectively, of costs were billed to or incurred by us related to the We Power generation units, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.

(3)Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on net income. Effective January 1, 2023, the PSCW approved escrow accounting for pension and OPEB costs. As a result, we defer as a regulatory asset or liability, the difference between these actual costs and those included in rates until recovery or refund is authorized in a future rate proceeding.

The following tables provide information on delivered sales volumes by customer class and weather statistics:


	Three Months Ended June 30
	MWh (in thousands)
Electric Sales Volumes	2023	2022	B (W)
Customer Class
Residential	1,753.0	1,906.5	(153.5)
Small commercial and industrial	2,076.6	2,079.8	(3.2)
Large commercial and industrial	1,598.7	1,636.6	(37.9)
Other	20.7	23.2	(2.5)
Total retail	5,449.0	5,646.1	(197.1)
Wholesale	118.9	231.0	(112.1)
Resale	902.1	763.6	138.5
Total sales in MWh	6,470.0	6,640.7	(170.7)


	Three Months Ended June 30
	Therms (in millions)
Natural Gas Sales Volumes	2023	2022	B (W)
Customer Class
Residential	49.4	59.2	(9.8)
Commercial and industrial	30.3	30.1	0.2
Total retail	79.7	89.3	(9.6)
Transportation	49.1	72.8	(23.7)
Total sales in therms	128.8	162.1	(33.3)


	Three Months Ended June 30
	Degree Days
Weather (1)	2023	2022	B (W)
Heating (911 Normal)	758	840	(9.8)	%
Cooling (171 Normal)	158	259	(39.0)	%

(1)Normal degree days are based on a 20-year moving average of monthly temperatures from Mitchell International Airport in Milwaukee, Wisconsin.

Electric Revenues

Electric revenues decreased $17.2 million during the second quarter of 2023, compared with the same quarter in 2022. To the extent that changes in fuel and purchased power costs are passed through to customers, the changes are offset by comparable changes in revenues. See the discussion of electric utility margins below for more information related to the recovery of fuel and purchased power costs and the remaining drivers of the changes in electric revenues.


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Electric Utility Margins

Electric utility margins increased $44.5 million during the second quarter of 2023, compared with the same quarter in 2022. The significant factors impacting the higher electric utility margins were:

•A $57.3 million increase in margins related to the impact of our rate order approved by the PSCW, effective January 1, 2023. See Note 23, Regulatory Environment, in our 2022 Annual Report on Form 10-K for more information on the 2023 rate order.

•A $7.5 million quarter-over-quarter positive impact from collections of fuel and purchased power costs. Under the Wisconsin fuel rules, our margins are impacted by under- or over-collections of certain fuel and purchased power costs that are within a 2% price variance from the costs included in rates, and the remaining variance beyond the 2% price variance is generally deferred for future recovery or refund to customers.

•A $5.0 million decrease in expense during the second quarter of 2023, related to the expiration of a capacity contract driven by the acquisition of the Whitewater facility, effective January 1, 2023.

These increases in margins were partially offset by:

•A $17.5 million decrease in margins related to lower sales volumes, driven by the impact of cooler spring weather during the second quarter of 2023, compared with the same quarter in 2022. As measured by cooling degree days, the second quarter of 2023 was 39.0% cooler than the same quarter in 2022.

•A $5.6 million decrease in other revenues, primarily related to third-party use of our assets and a FERC order in January 2023 that eliminated reactive power compensation MISO was required to pay to generators, including us.

Natural Gas Revenues

Natural gas revenues decreased $26.0 million during the second quarter of 2023, compared with the same quarter in 2022. Because prudently incurred natural gas costs are passed through to our customers in current rates, the changes are offset by comparable changes in revenues. The average per-unit cost of natural gas decreased 47% during the second quarter of 2023, compared with the same quarter in 2022. The remaining drivers of changes in natural gas revenues are described in the discussion of natural gas utility margins below.

Natural Gas Utility Margins

Natural gas utility margins increased $5.3 million during the second quarter of 2023, compared with the same quarter in 2022. The most significant factor impacting the higher natural gas utility margins was a $7.4 million increase in margins related to the impact of our rate order approved by the PSCW, effective January 1, 2023. This increase in margins was partially offset by a $1.8 million decrease in margins from lower sales volumes, driven by warmer weather during the second quarter of 2023, compared with the same quarter in 2022. As measured by heating degree days, the second quarter of 2023 was 9.8% warmer than the same quarter in 2022. See Note 23, Regulatory Environment, in our 2022 Annual Report on Form 10-K for more information on the 2023 rate order.

Other Operating Expenses (includes other operation and maintenance, depreciation and amortization, and property and revenue taxes)

Other operating expenses at the utility segment increased $12.2 million during the second quarter of 2023, compared with the same quarter in 2022. The significant factors impacting the increase in other operating expenses were:

•An $18.9 million increase in transmission expense as approved in the PSCW's 2023 rate order, effective January 1, 2023. See the notes under the other operation and maintenance table above for more information. This amount is net of a deferral of $2.8 million approved by the PSCW in June 2023, retroactive to December 1, 2022, in response to a FERC order eliminating reactive power compensation to our utilities, as discussed in electric margins above.

•A $9.6 million increase in depreciation and amortization, driven by assets being placed into service as we continue to execute on our capital plan.


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•An $8.2 million increase in other operation and maintenance expense related to the We Power leases, as discussed in the notes under the other operation and maintenance table above.

•A $7.6 million increase in regulatory amortizations and other pass through expenses, as discussed in the notes under the other operation and maintenance table above.

These increases in other operating expenses were partially offset by:

•A $22.2 million pre-tax gain on the sale of land at our Pleasant Prairie power plant site during the second quarter of 2023. See Note 3, Disposition, for more information.

•A $9.3 million decrease in benefit costs, primarily driven by lower stock-based compensation and incentive costs, partially offset by an increase in deferred compensation costs.

Other Income, Net

Other income, net increased $7.6 million during the second quarter of 2023, compared with the same quarter in 2022, driven by higher AFUDC–Equity due to continued capital investment.

Interest Expense

Interest expense increased $3.8 million during the second quarter of 2023, compared with the same quarter in 2022, driven by the impact of a $500.0 million long-term debt issuance in September 2022 and higher short-term debt interest rates. These increases were partially offset by higher AFUDC–Debt due to continued capital investment. Lower interest expense on finance lease liabilities, primarily related to the We Power leases, as finance lease liabilities decrease each year as payments are made, also contributed to the offset in interest expense.

Income Tax Expense

Income tax expense increased $7.6 million during the second quarter of 2023, compared with the same quarter in 2022, driven by higher pre-tax income, partially offset by a $1.4 million increase in PTCs.

SIX MONTHS ENDED JUNE 30, 2023

Earnings

Our earnings for the six months ended June 30, 2023 were $233.3 million, compared to $216.3 million for the same period in 2022. See below for information on the $17.0 million increase in earnings.

Expected 2023 Annual Effective Tax Rate

We expect our 2023 annual effective tax rate to be between 22.0% and 23.0%. Our effective tax rate calculations are revised every quarter based on the best available year-end tax assumptions, adjusted in the following year after returns are filed. Tax accrual estimates are trued-up to the actual amounts claimed on the tax returns and further adjusted after examinations by taxing authorities, as needed.

Non-GAAP Financial Measures


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We believe that electric and natural gas margins provide a useful basis for evaluating utility operations since the majority of prudently incurred fuel and purchased power costs, as well as prudently incurred natural gas costs, are passed through to customers in current rates. As a result, management uses electric and natural gas margins internally when assessing the operating performance of our utility segment as these measures exclude the majority of revenue fluctuations caused by changes in these expenses. Similarly, the presentation of electric and natural gas margins herein is intended to provide supplemental information for investors regarding our operating performance.

Our electric margins and natural gas margins may not be comparable to similar measures presented by other companies. Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance. Our utility segment operating income for the ~~three~~six months ended June 30, 2023 and 2022 ~~and 2021~~ was ~~$206.5~~$501.5 million and ~~$200.0~~$495.6 million, respectively. The discussion below includes a table that provides the calculation of electric margins and natural gas margins, along with a reconciliation to the most directly comparable GAAP measure, operating income.


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Utility Segment Contribution to Net Income Attributed to Common Shareholder

The following table compares our utility segment's contribution to net income for the second quarter of 2022, with the same quarter in 2021, including favorable or better, "B", and unfavorable or worse, "W", variances.


		Three Months Ended June 30							Six Months Ended June 30
(in millions)	(in millions)	2022		2021		B (W)		(in millions)	2023		2022		B (W)
Electric revenues	Electric revenues	$	846.1	$	764.7	$	81.4	Electric revenues	$	1,676.6	$	1,681.6	$	(5.0)
Fuel and purchased power	Fuel and purchased power	323.2		243.3		(79.9)		Fuel and purchased power	548.3		603.0		54.7
Total electric margins	Total electric margins	522.9		521.4		1.5		Total electric margins	1,128.3		1,078.6		49.7

Natural gas revenues	Natural gas revenues	97.4		62.8		34.6		Natural gas revenues	315.6		333.9		(18.3)
Cost of natural gas sold	Cost of natural gas sold	62.3		33.1		(29.2)		Cost of natural gas sold	188.7		226.7		38.0
Total natural gas margins	Total natural gas margins	35.1		29.7		5.4		Total natural gas margins	126.9		107.2		19.7

Total electric and natural gas margins	Total electric and natural gas margins	558.0		551.1		6.9		Total electric and natural gas margins	1,255.2		1,185.8		69.4

Other operation and maintenance	Other operation and maintenance	205.3		213.1		7.8		Other operation and maintenance	438.3		397.9		(40.4)
Depreciation and amortization	Depreciation and amortization	119.7		113.3		(6.4)		Depreciation and amortization	257.1		238.8		(18.3)
Property and revenue taxes	Property and revenue taxes	26.5		24.7		(1.8)		Property and revenue taxes	58.3		53.5		(4.8)
Operating income	Operating income	206.5		200.0		6.5		Operating income	501.5		495.6		5.9

Other income, net	Other income, net	11.4		7.3		4.1		Other income, net	34.1		22.0		12.1
Interest expense	Interest expense	113.1		116.0		2.9		Interest expense	234.7		226.5		(8.2)
Income before income taxes	Income before income taxes	104.8		91.3		13.5		Income before income taxes	300.9		291.1		9.8

Income tax expense	Income tax expense	26.7		12.2		(14.5)		Income tax expense	67.0		74.2		7.2
Preferred stock dividends of subsidiary	Preferred stock dividends of subsidiary	0.3		0.3		—		Preferred stock dividends of subsidiary	0.6		0.6		—
Net income attributed to common shareholder	Net income attributed to common shareholder	$	77.8	$	78.8	$	(1.0)	Net income attributed to common shareholder	$	233.3	$	216.3	$	17.0

The following table shows a breakdown of other operation and maintenance:


		Three Months Ended June 30							Six Months Ended June 30
(in millions)	(in millions)	2022		2021		B (W)		(in millions)	2023		2022		B (W)
Operation and maintenance not included in line items below	Operation and maintenance not included in line items below	$	91.3	$	84.5	$	(6.8)	Operation and maintenance not included in line items below	$	138.8	$	170.2	$	31.4
Transmission (1)	Transmission (1)	69.0		84.5		15.5		Transmission (1)	178.5		137.9		(40.6)
We Power (2)	We Power (2)	27.3		29.4		2.1		We Power (2)	71.0		54.9		(16.1)
Regulatory amortizations and other pass through expenses (3)	Regulatory amortizations and other pass through expenses (3)	17.7		14.7		(3.0)		Regulatory amortizations and other pass through expenses (3)	50.4		34.9		(15.5)

Earnings sharing mechanism								Earnings sharing mechanism	(0.4)		—		0.4
Total other operation and maintenance	Total other operation and maintenance	$	205.3	$	213.1	$	7.8	Total other operation and maintenance	$	438.3	$	397.9	$	(40.4)

(1)Represents transmission expense that we are authorized to collect in rates. The PSCW has approved escrow accounting for ~~American Transmission Company LLC~~ATC and MISO network transmission expenses. As a result, we defer as a regulatory asset or liability, the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During the ~~second quarter of~~six months ended June 30, 2023 and 2022, ~~and 2021, $86.0~~$165.6 million and ~~$82.3~~$168.9 million, respectively, of costs were billed to us by transmission providers.


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During the ~~second quarter of~~six months ended June 30, 2022, we amortized ~~$15.5~~$31.0 million of the regulatory liabilities associated with our transmission escrow to offset certain 2022 revenue deficiencies, as approved by the PSCW in order to forego filing for a 2022 base rate increase. This amortization drove the ~~decrease in~~lower transmission expense during the ~~second quarter of 2022, compared with the same quarter in 2021. See Note 22, Regulatory Environment, in our 2021 Annual Report on Form 10-K for additional information on 2022 base rates.~~six months ended June 30, 2022.

(2)Represents costs associated with the We Power generation units, including operating and maintenance costs we recognized. During the ~~second quarter of~~six months ended June 30, 2023 and 2022, ~~and 2021, $26.1~~$62.4 million and ~~$25.7~~$50.9 million, respectively, of costs were billed to or incurred by us related to the We Power generation units, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.


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~~Table of Contents~~

The following tables provide information on delivered sales volumes by customer class and weather statistics:


		Three Months Ended June 30				Six Months Ended June 30
		MWh (in thousands)				MWh (in thousands)
Electric Sales Volumes	Electric Sales Volumes	2022	2021	B (W)	Electric Sales Volumes	2023	2022	B (W)
Customer Class	Customer Class				Customer Class
Residential	Residential	1,906.5	1,903.9	2.6	Residential	3,634.2	3,893.1	(258.9)
Small commercial and industrial	Small commercial and industrial	2,079.8	2,068.7	11.1	Small commercial and industrial	4,163.9	4,248.8	(84.9)
Large commercial and industrial	Large commercial and industrial	1,636.6	1,691.3	(54.7)	Large commercial and industrial	3,153.5	3,235.5	(82.0)
Other	Other	23.2	23.9	(0.7)	Other	50.9	55.1	(4.2)
Total retail	Total retail	5,646.1	5,687.8	(41.7)	Total retail	11,002.5	11,432.5	(430.0)
Wholesale	Wholesale	231.0	275.5	(44.5)	Wholesale	270.1	555.0	(284.9)
Resale	Resale	763.6	1,301.7	(538.1)	Resale	2,085.6	1,910.5	175.1
Total sales in MWh	Total sales in MWh	6,640.7	7,265.0	(624.3)	Total sales in MWh	13,358.2	13,898.0	(539.8)


		Three Months Ended June 30				Six Months Ended June 30
		Therms (in millions)				Therms (in millions)
Natural Gas Sales Volumes	Natural Gas Sales Volumes	2022	2021	B (W)	Natural Gas Sales Volumes	2023	2022	B (W)
Customer Class	Customer Class				Customer Class
Residential	Residential	59.2	45.7	13.5	Residential	218.5	249.0	(30.5)
Commercial and industrial	Commercial and industrial	30.1	23.6	6.5	Commercial and industrial	125.2	137.8	(12.6)
Total retail	Total retail	89.3	69.3	20.0	Total retail	343.7	386.8	(43.1)
Transportation	Transportation	72.8	66.0	6.8	Transportation	124.0	171.2	(47.2)
Total sales in therms	Total sales in therms	162.1	135.3	26.8	Total sales in therms	467.7	558.0	(90.3)


		Three Months Ended June 30					Six Months Ended June 30
		Degree Days					Degree Days
Weather (1)	Weather (1)	2022	2021	B (W)		Weather (1)	2023	2022	B (W)
Heating (923 Normal)		840	738	13.8	%
Heating (4,194 Normal)						Heating (4,194 Normal)	3,591	4,165	(13.8)	%
Cooling (171 Normal)	Cooling (171 Normal)	259	303	(14.5)	%	Cooling (171 Normal)	158	259	(39.0)	%

(1)Normal degree days are based on a 20-year moving average of monthly temperatures from Mitchell International Airport in Milwaukee, Wisconsin.

Electric Revenues

Electric revenues ~~increased $81.4~~decreased $5.0 million during the ~~second quarter of 2022,~~six months ended June 30, 2023, compared with the same ~~quarter~~period in ~~2021.~~2022. To the extent that changes in fuel and purchased power costs are passed through to customers, the changes are offset by comparable changes in revenues. See the discussion of electric utility margins below for more information related to the recovery of fuel and purchased power costs and the remaining drivers of the changes in electric revenues.

~~Electric Utility Margins~~

~~Electric utility margins increased $1.5 million during the second quarter of 2022, compared with the same quarter in 2021. The significant factors impacting the higher electric utility margins were:~~

•A $9.8 million increase in margins related to the impact of unprotected excess deferred taxes during the second quarter of 2021, which we agreed to return to customers in our PSCW-approved rate order. This increase in margins is offset in income taxes.

•~~A $3.3 million increase in other revenues, primarily related to third party use of our assets.~~

•A $2.0 million increase in securitization revenues received during the second quarter of 2022, compared with the same quarter in 2021, related to an environmental control charge collected from our retail electric distribution customers on behalf of WEPCo Environmental Trust. We began assessing this charge in June 2021, subsequent to the issuance of the ETBs by WEPCo


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~~Environmental Trust~~Electric Utility Margins

Electric utility margins increased $49.7 million during the six months ended June 30, 2023, compared with the same period in ~~May 2021,~~2022. The significant factors impacting the higher electric utility margins were:

•A $117.6 million increase in ~~accordance with~~margins related to the impact of our rate order approved by the PSCW, effective January 1, 2023.

•An $11.5 million decrease in expense during the six months ended June 30, 2023, related to the expiration of a ~~November 2020 PSCW financing order. See Note 17, Variable Interest Entities, for more information. These revenues are offset in depreciation and amortization as well as interest expense.~~capacity contract driven by the acquisition of the Whitewater facility, effective January 1, 2023.

These increases in margins were partially offset by:

•A ~~$10.1~~$36.2 million ~~quarter-over-quarter~~decrease in margins related to lower sales volumes, driven by the impact of unfavorable weather during the six months ended June 30, 2023, compared with the same period in 2022. As measured by cooling degree days, the six months ended June 30, 2023 were 39.0% cooler than the same period in 2022. As measured by heating degree days, the six months ended June 30, 2023 were 13.8% warmer than the same period in 2022.

•A $21.8 million period-over-period negative impact from ~~actual~~collections of fuel and purchased power ~~costs compared with costs collected in rates.~~costs. Under the Wisconsin fuel rules, our margins are impacted by under- or over-collections of certain fuel and purchased power costs that are within a 2% price variance from the costs included in rates, and the remaining variance beyond the 2% price variance is generally deferred for future recovery or refund to customers.

•Lower margins of ~~$3.2~~$8.3 million driven by the expiration of ~~certain~~a wholesale ~~contracts.~~contract in May 2022.

•A $7.0 million decrease in other revenues, primarily related to third-party use of our assets and a FERC order in January 2023 that eliminated reactive power compensation MISO was required to pay to generators, including us.

•A $3.8 million decrease in margins from our steam operations driven by lower sales volumes, including the impact of weather.

Natural Gas Revenues

Natural gas revenues ~~increased $34.6~~decreased $18.3 million during the ~~second quarter of 2022,~~six months ended June 30, 2023, compared with the same ~~quarter~~period in ~~2021.~~2022. Because prudently incurred natural gas costs are passed through to our customers in current rates, the changes are offset by comparable changes in revenues. ~~The average per-unit cost of natural gas increased 52% during the second quarter of 2022, compared with the same quarter in 2021.~~ The remaining drivers of changes in natural gas revenues are described in the discussion of natural gas utility margins below.

Natural Gas Utility Margins

Natural gas utility margins increased ~~$5.4~~$19.7 million during the ~~second quarter of 2022,~~six months ended June 30, 2023, compared with the same ~~quarter~~period in ~~2021.~~2022. The most significant factor impacting the higher natural gas utility margins was ~~higher~~a $28.9 million increase in margins related to the impact of our rate order approved by the PSCW, effective January 1, 2023. This increase in margins was partially offset by a $9.2 million decrease in margins from lower sales volumes, driven by ~~the continued economic recovery in Wisconsin from the COVID-19 pandemic, as well as colder~~warmer winter weather during the ~~second quarter of 2022,~~six months ended June 30, 2023, compared with the same period in ~~2021. As measured by heating degree days, the second quarter of 2022 was 13.8% colder than the same quarter in 2021.~~2022.

Other Operating Expenses (includes other operation and maintenance, depreciation and amortization, and property and revenue taxes)

Other operating expenses at the utility segment increased ~~$0.4~~$63.5 million during the ~~second quarter of 2022,~~six months ended June 30, 2023, compared with the same ~~quarter~~period in ~~2021.~~2022. The significant factors impacting the increase in other operating expenses were:

•A ~~$7.9~~$40.6 million increase in transmission expense as approved in the PSCW's 2023 rate order, effective January 1, 2023. See the notes under the other operation and maintenance table above for more information. This amount is net of a deferral of $2.8 million approved by the PSCW in June 2023, retroactive to December 1, 2022, in response to a FERC order eliminating reactive power compensation, as discussed in electric ~~and natural gas distribution expenses, primarily driven by higher storm restoration expense during the second quarter of 2022, and higher costs to maintain system reliability.~~margins above.


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•~~A $6.4~~An $18.3 million increase in depreciation and amortization, driven by assets being placed into service as we continue to execute on our capital ~~plan, as well as an increase related to the We Power leases. In addition, a portion of the increase is related to securitization amortization, which is offset in revenues.~~plan.

•A ~~$3.0~~$16.1 million increase ~~in regulatory amortizations and other pass through expenses, as discussed in the notes under the other operation and maintenance table above.~~

•~~A $1.8 million increase in property and revenue taxes, driven by higher gross receipt taxes.~~

~~These increases in other operating expenses were partially offset by:~~

•A $15.5 million decrease in transmission expense driven by the amortization of a certain portion of our regulatory liabilities associated with transmission escrow balances, as discussed in the notes under the other operation and maintenance table above.

•~~A $2.1 million decrease~~ in other operation and maintenance expense related to the We Power leases, as discussed in the notes under the other operation and maintenance table above.


~~06/30/2022 Form 10-Q~~•A $15.5 million increase in regulatory amortizations and other pass through expenses, as discussed in the notes under the other operation and maintenance table above.			32			~~Wisconsin Electric Power Company~~

These increases in other operating expenses were partially offset by:

~~Table~~

•A $22.2 million pre-tax gain on the sale of ~~Contents~~land at our Pleasant Prairie power plant site during the six months ended June 30, 2023. See Note 3, Disposition, for more information.

•A $6.8 million decrease in benefit costs, primarily driven by lower stock-based compensation and incentive costs, partially offset by an increase in deferred compensation costs.

Other Income, Net

Other income, net increased ~~$4.1~~$12.1 million during the ~~second quarter of 2022,~~six months ended June 30, 2023, compared with the same ~~quarter~~period in ~~2021,~~2022, driven by higher ~~net credits from the non-service components of our net periodic pension and OPEB costs. See Note 15, Employee Benefits, for more information on our benefit costs. Higher~~ AFUDC–Equity due to continued capital ~~investment also contributed to the increase in other income, net.~~investment.

Interest Expense

Interest expense ~~decreased $2.9~~increased $8.2 million during the ~~second quarter of 2022,~~six months ended June 30, 2023, compared with the same ~~quarter~~period in ~~2021, driven~~2022, primarily due to the impact of a $500.0 million long-term debt issuance in September 2022 and higher short-term debt interest rates. These increases were partially offset by ~~lower~~higher AFUDC–Debt due to continued capital investment. Lower interest expense on finance lease liabilities, primarily related to the We Power leases, as finance lease liabilities decrease each year as payments are ~~made. Also contributing~~made, also contributed to the ~~decrease,~~offset in ~~June 2021, we were able to refinance $300 million of debt obligation with lower rate debt.~~interest expense.

Income Tax Expense

Income tax expense increased $14.5 million during the second quarter of 2022, compared with the same quarter in 2021. The increase in income tax expense was due to an approximate $10 million negative impact related to lower quarter-over-quarter amortization of the unprotected excess deferred tax benefits from the Tax Legislation in connection with the rate order approved by the PSCW, effective January 1, 2020. The impact due to the benefit from the amortization of the unprotected excess deferred tax benefits from the Tax Legislation did not impact earnings as there was an offsetting impact in operating income. Also contributing to this increase in income tax expense was an increase in pre-tax income. See Note 11, Income Taxes, for additional information on unprotected tax benefits.

~~SIX MONTHS ENDED JUNE 30, 2022~~

~~Earnings~~

Our earnings for the six months ended June 30, 2022 were $216.3 million, compared to $205.8 million for the same period in 2021. See below for additional information on the $10.5 million increase in earnings.

~~Expected 2022 Annual Effective Tax Rate~~

We expect our 2022 annual effective tax rate to be between 25% and 26%. Our effective tax rate calculations are revised every quarter based on the best available year-end tax assumptions, adjusted in the following year after returns are filed. Tax accrual estimates are trued-up to the actual amounts claimed on the tax returns and further adjusted after examinations by taxing authorities, as needed.

~~Non-GAAP Financial Measures~~


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of operating performance. Our utility segment operating income for the six months ended June 30, 2022 and 2021 was $495.6 million and $455.6 million, respectively. The discussion below includes a table that provides the calculation of electric margins and natural gas margins, along with a reconciliation to the most directly comparable GAAP measure, operating income.

~~Utility Segment Contribution to Net Income Attributed to Common Shareholder~~

Six Months Ended June 30
(in millions) 2022 2021 B (W)
Electric revenues $ 1,681.6 $ 1,553.5 $ 128.1
Fuel and purchased power 603.0 499.0 (104.0)
Total electric margins 1,078.6 1,054.5 24.1
Natural gas revenues 333.9 279.2 54.7
Cost of natural gas sold 226.7 181.6 (45.1)
Total natural gas margins 107.2 97.6 9.6
Total electric and natural gas margins 1,185.8 1,152.1 33.7
Other operation and maintenance 397.9 422.4 24.5
Depreciation and amortization 238.8 224.0 (14.8)
Property and revenue taxes 53.5 50.1 (3.4)
Operating income 495.6 455.6 40.0
Other income, net 22.0 14.7 7.3
Interest expense 226.5 232.2 5.7
Income before income taxes 291.1 238.1 53.0
Income tax expense 74.2 31.7 (42.5)
Preferred stock dividends of subsidiary 0.6 0.6 —
Net income attributed to common shareholder $ 216.3 $ 205.8 $ 10.5

~~The following table shows a breakdown of other operation and maintenance:~~

Six Months Ended June 30
(in millions) 2022 2021 B (W)
Operation and maintenance not included in line items below $ 170.2 $ 161.6 $ (8.6)
Transmission (1)
137.9 168.9 31.0
We Power (2)
54.9 58.8 3.9
Regulatory amortizations and other pass through expenses (3)
34.9 33.1 (1.8)
Total other operation and maintenance $ 397.9 $ 422.4 $ 24.5

~~(1)~~Represents transmission expense that we are authorized to collect in rates. The PSCW has approved escrow accounting for American Transmission Company LLC and MISO network transmission expenses. As a result, we defer as a regulatory asset or liability, the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During the six months ended June 30, 2022 and 2021, $168.9 million and $169.2 million, respectively, of costs were billed to us by transmission providers.

During the six months ended June 30, 2022, we amortized $31.0 million of the regulatory liabilities associated with our transmission escrow to offset certain 2022 revenue deficiencies, as approved by the PSCW in order to forego filing for a 2022 base rate increase. This amortization drove the decrease in transmission expense during the six months ended June 30, 2022, compared with the same period in 2021.

~~(2)~~Represents costs associated with the We Power generation units, including operating and maintenance costs we recognized. During the six months ended June 30, 2022 and 2021, $50.9 million and $51.6 million, respectively, of costs were billed to or incurred by us related to the We Power generation units, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.

~~(3)Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on net income.~~


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~~The following tables provide information on delivered sales volumes by customer class and weather statistics:~~

Six Months Ended June 30
MWh (in thousands)
Electric Sales Volumes 2022 2021 B (W)
Customer Class
Residential 3,893.1 3,887.8 5.3
Small commercial and industrial 4,248.8 4,146.2 102.6
Large commercial and industrial 3,235.5 3,266.4 (30.9)
Other 55.1 59.5 (4.4)
Total retail 11,432.5 11,359.9 72.6
Wholesale 555.0 592.6 (37.6)
Resale 1,910.5 3,149.1 (1,238.6)
Total sales in MWh 13,898.0 15,101.6 (1,203.6)

Six Months Ended June 30
Therms (in millions)
Natural Gas Sales Volumes 2022 2021 B (W)
Customer Class
Residential 249.0 223.0 26.0
Commercial and industrial 137.8 119.0 18.8
Total retail 386.8 342.0 44.8
Transportation 171.2 161.9 9.3
Total sales in therms 558.0 503.9 54.1

Six Months Ended June 30
Degree Days
Weather (1)
2022 2021 B (W)
Heating (4,190 Normal) 4,165 3,858 8.0 %
Cooling (171 Normal) 259 303 (14.5) %

~~(1)Normal degree days are based on a 20-year moving average of monthly temperatures from Mitchell International Airport in Milwaukee, Wisconsin.~~

~~Electric Revenues~~

~~Electric revenues increased $128.1~~decreased $7.2 million during the six months ended June 30, ~~2022,~~2023, compared with the same period in ~~2021. To the extent that changes in fuel and purchased power costs are passed through to customers, the changes are offset~~2022, driven by comparable changes in revenues. See the discussion of electric utility margins below for more information related to the recovery of fuel and purchased power costs and the remaining drivers of the changes in electric revenues.

~~Electric Utility Margins~~

Electric utility margins increased $24.1 million during the six months ended June 30, 2022, compared with the same period in 2021. The significant factors impacting the higher electric utility margins were:

•~~A $33.1~~a $6.0 million increase in margins related to the impact of unprotected excess deferred taxes during the six months ended June 30, 2021, which we agreed to return to customers in our PSCW-approved rate order. This increase in margins is offset in income taxes.

•A $5.3 million increase in securitization revenues received during the six months ended June 30, 2022, compared with the same period in 2021, related to an environmental control charge collected from our retail electric distribution customers on behalf of WEPCo Environmental Trust. We began assessing this charge in June 2021, subsequent to the issuance of the ETBs by WEPCo Environmental Trust in May 2021, in accordance with a November 2020 PSCW financing order. These revenues are offset in depreciation and amortization as well as interest expense.


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~~These increases in margins were partially offset by:~~

•A $7.7 million period-over-period negative impact from actual fuel and purchased power costs compared with costs collected in rates. Under the Wisconsin fuel rules, our margins are impacted by under- or over-collections of certain fuel and purchased power costs that are within a 2% price variance from the costs included in rates, and the remaining variance beyond the 2% price variance is generally deferred for future recovery or refund to customers.

•~~Lower margins of $5.3 million driven by the expiration of certain wholesale contracts.~~

~~Natural Gas Revenues~~

Natural gas revenues increased $54.7 million during the six months ended June 30, 2022, compared with the same period in 2021. Because prudently incurred natural gas costs are passed through to our customers in current rates, the changes are offset by comparable changes in revenues. The average per-unit cost of natural gas increased 13% during the six months ended June 30, 2022, compared with the same period in 2021. The remaining drivers of changes in natural gas revenues are described in the discussion of natural gas utility margins below.

~~Natural Gas Utility Margins~~

Natural gas utility margins increased $9.6 million during the six months ended June 30, 2022, compared with the same period in 2021. The most significant factor impacting the higher natural gas utility margins was an increase from higher sales volumes, primarily driven by the continued economic recovery in Wisconsin from the COVID-19 pandemic, as well as colder weather during the six months ended June 30, 2022, compared with the same period in 2021. As measured by heating degree days, the six months ended June 30, 2022 were 8.0% colder than the same period in 2021.

~~Other Operating Expenses (includes other operation and maintenance, depreciation and amortization, and property and revenue taxes)~~

Other operating expenses at the utility segment decreased $6.3 million during the six months ended June 30, 2022, compared with the same period in 2021. The significant factors impacting the decrease in operating expenses were:

•A $31.0 million decrease in transmission expense driven by the amortization of a certain portion of our regulatory liabilities associated with transmission escrow balances, as discussed in the notes under the other operation and maintenance table above.

•~~A $3.9 million decrease in other operation and maintenance expense related to the We Power leases, as discussed in the notes under the other operation and maintenance table above.~~

~~These decreases in operating expenses were partially offset by:~~

•A $14.8 million increase in depreciation and amortization, driven by assets being placed into service as we continue to execute on our capital plan as well as an increase related to the We Power leases. In addition, a portion of the increase is related to securitization amortization, which is offset in revenues.

•A $10.3 million increase in electric and natural gas distribution expenses, primarily driven by higher storm restoration expense during the six months ended June 30, 2022, and higher costs to maintain system reliability.

•~~A $3.4 million increase in property and revenue taxes, driven by higher gross receipt taxes.~~

~~Other Income, Net~~

Other income, net increased $7.3 million during the six months ended June 30, 2022, compared with the same period in 2021, driven by higher net credits from the non-service components of our net periodic pension and OPEB costs. Higher AFUDC–Equity due to continued capital investment also contributed to the increase in other income, net.


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~~Interest Expense~~

Interest expense decreased $5.7 million during the six months ended June 30, 2022, compared with the same period in 2021, driven by lower interest expense on finance lease liabilities, primarily related to the We Power leases, as finance lease liabilities decrease each year as payments are made. Also contributing to the decrease, in June 2021, we were able to refinance $300 million of debt obligations with lower rate debt.

~~Income Tax Expense~~

Income tax expense increased $42.5 million during the six months ended June 30, 2022, compared with the same period in 2021. The increase was primarily due to an increase in pre-tax income and to an approximate $35 million negative impact related to lower period-over-period amortization of the unprotected excess deferred tax benefits from the Tax Legislation in connection with the rate order approved by the PSCW, effective January 1, 2020. The impact due to the benefit from the amortization of the unprotected excess deferred tax benefits from the Tax Legislation did not impact earnings as there was an offsetting impact in operating income.PTCs.

LIQUIDITY AND CAPITAL RESOURCES

Overview

We expect to maintain adequate liquidity to meet our cash requirements for the operation of our business and implementation of our corporate strategy through the internal generation of cash from operations and access to the capital markets.

Cash Flows

The following table summarizes our cash flows during the six months ended June 30:


(in millions)	(in millions)	2022		2021		Change in 2022 Over 2021		(in millions)	2023		2022		Change in 2023 Over 2022
Cash provided by (used in):	Cash provided by (used in):							Cash provided by (used in):
Operating activities	Operating activities	$	450.5	$	473.7	$	(23.2)	Operating activities	$	458.3	$	450.5	$	7.8
Investing activities	Investing activities	(384.5)		(373.5)		(11.0)		Investing activities	(600.2)		(384.5)		(215.7)
Financing activities	Financing activities	(63.3)		(100.5)		37.2		Financing activities	125.0		(63.3)		188.3


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Operating Activities

Net cash provided by operating activities ~~decreased $23.2~~increased $7.8 million during the six months ended June 30, ~~2022,~~2023, compared with the same period in ~~2021,~~2022, driven by:

•A ~~$96.3~~$150.7 million increase in cash from lower payments for fuel and purchased power at our generation plants, as well as lower natural gas costs to our customers during the six months ended June 30, 2023, compared with the same period in 2022, primarily driven by a decrease in the price of natural gas.

•A $114.7 million increase in cash from higher overall collections from customers during the six months ended June 30, 2023, compared with the same period in 2022. This increase was driven by the impact of our rate order approved by the PSCW, effective January 1, 2023. See Note 23, Regulatory Environment, in our 2022 Annual Report on Form 10-K for more information on our 2023 rate order.

These increases in net cash provided by operating activities were partially offset by:

•A $130.5 million decrease in cash driven by collateral paid to counterparties during the six months ended June 30, 2023, compared with collateral received from counterparties during the same period in 2022, as well as realized losses on derivative instruments recognized during the six months ended June 30, 2023, compared with realized gains recognized during the same period in 2022.

•An $89.9 million decrease in cash related to higher payments for other operation and maintenance expenses. During the six months ended June 30, ~~2022,~~2023, our payments were higher for ~~storm restoration~~charitable projects accrued for at the end of 2022 and operating and maintenance related to ~~maintain system reliability,~~the We Power and our other generation units, as well as due to the timing of payments for accounts payable.

•A ~~$92.7~~$21.8 million decrease in cash related to higher cash paid for income taxes, driven by higher taxable income during the six months ended June 30, 2023, compared with the same period in 2022.

•An $8.2 million decrease in cash from higher payments for ~~fuel~~interest, driven by the issuance of long-term debt in September 2022, and ~~purchased power at our plants~~higher short-term debt interest rates during the six months ended June 30, 2023, compared with the same period in 2022.

•A $5.9 million decrease in cash related to an increase in property and revenue taxes, driven by higher gross receipt taxes during the six months ended June 30, 2023, compared with the same period in 2022.

Investing Activities

Net cash used in investing activities increased $215.7 million during the six months ended June 30, 2023, compared with the same period in 2022, driven by:

•The acquisition of a 13.8% ownership interest in West Riverside in June 2023 for $95.3 million. See Note 2, Acquisitions for more information.

•A $48.5 million increase in cash paid for capital expenditures during the six months ended June 30, 2023, which is discussed in more detail below.

•Insurance proceeds of $41.0 million received during the six months ended June 30, 2022, ~~compared with~~for property damage, primarily related to the ~~same period~~Public Service Building water damage claim.

•The acquisition of Whitewater in ~~2021. Our plants incurred higher fuel costs~~January 2023 for $38.0 million. See Note 2, Acquisitions for more information.

These increases in net cash used in investing activities were partially offset by proceeds received of $24.2 million during the six months ended June 30, ~~2022, as a result of an increase in the price of natural gas.~~

~~These decreases in net cash provided by operating activities were partially offset by:~~

•A $113.1 million increase in cash from higher overall collections from customers as a result of an increase in sales volumes during the six months ended June 30, 2022, compared with the same period in 2021,2023, driven by the continued economic recovery in Wisconsin from the COVID-19 pandemic and colder weather. We also over-collected natural gas costs during the six months ended June 30, 2022, due to these costs being lower than what was anticipated in rates. In addition, we began collecting securitization revenues in June 2021 related to the issuancesale of ~~the ETBs by WEPCo Environmental Trust.~~land at our Pleasant Prairie power plant site. See Note ~~17, Variable Interest Entities,~~3, Disposition, for more ~~information on the issuance of WEPCo Environmental Trust's ETBs.~~information.


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•A $42.2 million increase in cash due to realized gains on derivative instruments as well as higher collateral received from counterparties during the six months ended June 30, 2022, both driven by higher natural gas prices.

•An $8.7 million increase in cash from lower payments for interest, driven by lower interest on finance lease liabilities as well as the refinancing of long-term debt obligations with lower interest rates.

~~Investing Activities~~

~~Net cash used in investing activities increased $11.0 million during the six months ended June 30, 2022, compared with the same period in 2021, driven by:~~

•~~A $31.7 million increase in cash paid for capital expenditures, which is discussed in more detail below.~~

•Proceeds received from affiliates of $10.7 million during the six months ended June 30, 2021, for assets transferred related to a customer billing system. There were no proceeds received from affiliates for assets transferred during the six months ended June 30, 2022.

These increases in net cash used in investing activities were partially offset by insurance proceeds of $41.0 million received during the six months ended June 30, 2022, for property damage, primarily related to the PSB water damage claim. See Note 6, Property, Plant, and Equipment, for more information.

Capital Expenditures

Capital expenditures for the six months ended June 30 were as follows:


(in millions)	(in millions)	2022		2021		Change in 2022 Over 2021		(in millions)	2023		2022		Change in 2023 Over 2022
Capital expenditures	Capital expenditures	$	419.3	$	387.6	$	31.7	Capital expenditures	$	467.8	$	419.3	$	48.5

The increase in cash paid for capital expenditures during the six months ended June 30, ~~2022,~~2023, compared with the same period in ~~2021,~~2022, was primarily driven by higher payments for capital expenditures related to Paris and the new natural gas-fired generation facility being constructed at the Weston power plant. These increases were partially offset by lower capital expenditures related to the ~~restoration~~construction of our ~~PSB~~LNG facility and upgrades to our electric and natural gas distribution ~~system. See Note 6, Property, Plant, and Equipment,~~systems, partially offset by decreased capital expenditures for ~~more information on the PSB.~~renewable energy projects.

See Capital Resources and Requirements – Capital Requirements – Significant Capital Projects for more information.

Financing Activities

Net cash ~~used in~~related to financing activities ~~decreased $37.2~~increased $188.3 million during the six months ended June 30, ~~2022,~~2023, compared with the same period in ~~2021,~~2022, driven by:

•A ~~$295.6 million increase in cash due to a decrease in retirements of long-term debt during the six months ended June 30, 2022, compared with the same period in 2021.~~

•~~A $250.0~~$425.0 million increase in cash related to higher equity contributions received from our parent during the six months ended June 30, ~~2022,~~2023, compared with the same period in ~~2021,~~2022, to balance our capital structure.

•A ~~$128.8~~$220.0 million increase in cash due to ~~$38.8 million of net borrowings of commercial paper during the six months ended June 30, 2022, compared with $90.0 million of net repayments of commercial paper during the same period in 2021.~~

~~These decreases in net cash used in financing activities were partially offset by:~~

•~~A $418.8 million decrease in cash due to the issuance of long-term debt during the six months ended June 30, 2021. We did not issue any long-term debt during the same period in 2022.~~


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•~~A $220.0 million decrease in cash due to higher~~lower dividends paid to our parent during the six months ended June 30, ~~2022,~~2023, compared with the same period in ~~2021,~~2022, to balance our capital structure.

These increases in cash were partially offset by a $456.5 million decrease in cash due to $417.7 million of net repayments of commercial paper during the six months ended June 30, 2023, compared with $38.8 million of net borrowings of commercial paper during the same period in 2022.

Other Significant Financing Activities

For more information on our other significant financing activities, see Note 8,10, Short-Term Debt and Lines of Credit.

Cash Requirements

We require funds to support and grow our business. Our significant cash requirements primarily consist of capital and investment expenditures, payments to retire and pay interest on long-term debt, the payment of common stock dividends to our parent, and the funding of our ongoing operations. See the discussion below and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Cash Requirements in our ~~2021~~2022 Annual Report on Form 10-K for additional information regarding our significant cash requirements.

Significant Capital Projects

We have several capital projects that will require significant capital expenditures over the next three years and beyond. All projected capital requirements are subject to periodic review and may vary significantly from estimates, depending on a number of factors. These factors include environmental requirements, regulatory restraints and requirements, changes in tax laws and regulations, acquisition and development opportunities, market volatility, economic trends, supply chain disruptions, ~~the COVID-19 pandemic,~~ inflation, and interest rates. Our estimated capital expenditures and acquisitions for the next three years are reflected below. These amounts include anticipated expenditures for environmental compliance and certain remediation issues. For a discussion of certain environmental matters affecting us, see Note ~~18,~~20, Commitments and Contingencies.


(in millions)	(in millions)				(in millions)
2022		$	1,204.2	(1)
2023	2023	1,360.2			2023	$	1,504.1	(1)
2024	2024	1,173.9			2024	1,478.2
2025					2025	1,274.6
Total	Total	$	3,738.3		Total	$	4,256.9


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(1)This includes actual capital expenditures ~~already~~ incurred ~~in 2022,~~through June 30, 2023, as well as estimated capital expenditures for the remainder of the year.

We continue to upgrade our electric and natural gas distribution systems to enhance reliability. These upgrades include addressing our aging infrastructure and system hardening and the AMI program. AMI is an integrated system of smart meters, communication networks, and data management systems that enable two-way communication between utilities and customers.

WEC Energy Group is committed to investing in solar, wind, battery storage, and clean natural gas-fired generation. Below are examples of projects that are proposed or currently ~~underway.~~underway:

•We have partnered with an unaffiliated utility to construct a utility-scale solar project, Badger Hollow II, that will be located in Iowa County, Wisconsin. Once constructed, we will own 100 MWMWs of the project. Our share of the cost of this project is estimated to be approximately ~~$151~~$172 million. Commercial operation of Badger Hollow II is targeted for ~~the first half of 2023.~~late 2023 or early 2024.

•We, along with WPS and an unaffiliated utility, received PSCW approval to acquire and construct Paris Solar-Battery Park, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Kenosha County, Wisconsin and once fully constructed, we will own 150 MWMWs of solar generation and 82 MWMWs of battery storage of this project. Our share of the cost of this project is estimated to be approximately ~~$325~~$452 million, with construction of the solar portion expected to be completed in ~~2023.~~2024.

•We, along with WPS received approval to accelerate capital investments in two wind parks. Our share of the investment is expected to be approximately $85 million to repower major components of Blue Sky Green Field Wind Park, which is expected to be completed by the end of 2022.

•~~In March 2021, we, along with WPS~~ and an unaffiliated utility, ~~filed an application with the~~received PSCW ~~for~~ approval to acquire and construct Darien, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Rock and Walworth counties, Wisconsin and once fully constructed, we will own 188 MWMWs of solar generation and


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56 MWMWs of battery storage of this project. ~~If approved, our~~Our share of the cost of this project is estimated to be approximately ~~$335~~$368 million, with construction of the solar portion expected to be completed in 2024.

•~~In April 2021, we,~~We, along with WPS and an unaffiliated utility, ~~filed an application with the~~received PSCW ~~for~~ approval to acquire ~~the~~ Koshkonong, ~~Solar-Battery Park,~~ a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Dane County, Wisconsin and once fully constructed, we will own 225 MWMWs of solar generation and 124 MWMWs of battery storage of this project. ~~If approved, our~~Our share of the cost of this project is estimated to be approximately $488 million, with construction of the solar portion expected to be completed in 2025.

•~~We,~~In July 2023, we, along with WPS, ~~received PSCW approval to construct~~completed construction on a natural gas-fired generation facility at WPS's existing Weston power plant site in northern Wisconsin. The new facility ~~will consist~~consists of seven RICE units. ~~Once constructed, we will~~We own 64 MWMWs of this project. Our ~~share~~construction work in progress balance for the Weston RICE units was $86.1 million as of ~~the cost of this project is estimated to be approximately $85 million, with construction expected to be completed in 2023.~~

•In November 2021, we, along with WPS, signed an asset purchase agreement to acquire Whitewater, a commercially operational 236.5 MW dual-fueled (natural gas and low sulfur fuel oil) combined-cycle electrical generation facility in Whitewater, Wisconsin. In December 2021, we, along with WPS, filed an application with the PSCW for approval to acquire Whitewater. If approved, our share of the cost of this facility is estimated to be $36.3 million for 50% of the capacity, with the transaction expected to close in earlyJune 30, 2023.

•In January ~~2022, WPS,~~2023, we, along with ~~an unaffiliated utility, filed an application with~~WPS, completed the ~~PSCW~~acquisition of Whitewater, a commercially operational 236.5 MW dual fueled (natural gas and low sulfur fuel oil) combined cycle electrical generation facility in Whitewater, Wisconsin. Our share of the cost of this facility was $38.0 million for ~~approval~~50% of the capacity.

•In June 2023, we closed on the purchase of 100 MWs of capacity related to ~~acquire a portion of West Riverside's nameplate capacity. WPS is also requesting approval to assign the option to purchase part of~~ West Riverside ~~to us. If approved, we or WPS would acquire 100 MW of capacity, in the first of two potential option exercises.~~for $95.3 million. West Riverside is a ~~combined-cycle~~combined cycle natural gas plant ~~recently~~ completed and operated by an unaffiliated utility in Rock County, Wisconsin. If approved, and WPS assigns the option to us, our share of the cost of this ownership interest would be approximately $91 million, with the transaction expected to close in the second quarter of 2023. In addition, WPS could exercise and request approval to assign to us a second option to acquire an additional 100 MWMWs of capacity. If approved, and WPS assigns the option to us, the cost of this ownership interest is expected to be approximately $100 million, with the transaction expected to close in 2024.

In March 2022, the DOC opened an investigation into whether new tariffs should be imposed on solar panels and cells imported from multiple southeast Asian countries. See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – United States Department of Commerce Complaint and Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Uyghur Forced Labor Prevention Act for information on the potential impacts to our solar projects as a result of the DOC investigation and CBP actions related to solar panels, respectively. The expected in-service dates and costs identified above already reflect some of these impacts.

We have received PSCW approval to construct ana LNG facility. The facility would provide us with approximately one billion cubic feet of natural gas supply to meet anticipated peak demand without requiring the construction of additional interstate pipeline capacity. The facility is expected to reduce the likelihood of constraints on our natural gas system during the highest demand days of winter. The project is estimated to cost approximately $185 million. Commercial operation of the LNG facility is targeted for the end of 2023.


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Long-Term Debt

There were no material changes in our outstanding long-term debt during the six months ended June 30, ~~2022.~~2023.

Common Stock Dividends

During the six months ended June 30, ~~2022,~~2023, we paid common stock dividends of ~~$340.0~~$120.0 million to the sole holder of our common stock, WEC Energy Group.

Other Significant Cash Requirements

See Note ~~18,~~20, Commitments and Contingencies, for information regarding our minimum future commitments related to purchase obligations for the procurement of fuel, power, and gas supply, as well as the related storage and transportation. There were no material changes to our other significant commitments outside the ordinary course of business during the six months ended June 30, ~~2022.~~2023.


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Off-Balance Sheet Arrangements

We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including letters of credit that primarily support our commodity contracts. We believe that these agreements do not have, and are not reasonably likely to have, a current or future material effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources. For additional information, see Note 8,10, Short-Term Debt and Lines of Credit, Note ~~14,~~16, Guarantees, and Note ~~17,~~19, Variable Interest Entities.

Sources of Cash

Liquidity

We anticipate meeting our short-term and long-term cash requirements to operate our business and implement our corporate strategy through internal generation of cash from operations, equity contributions from our parent, and access to the capital markets, which allows us to obtain external short-term borrowings, including commercial paper, and intermediate or long-term debt securities. Cash generated from operations is primarily driven by sales of electricity and natural gas to our utility customers, reduced by costs of operations. Our access to the capital markets is critical to our overall strategic plan and allows us to supplement cash flows from operations with external borrowings to manage seasonal variations, working capital needs, commodity price fluctuations, unplanned expenses, and unanticipated events.

We maintain a bank back-up credit facility, which provides liquidity support for our obligations with respect to commercial paper and for general corporate purposes. We review our bank back-up credit facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations.

The amount, type, and timing of any financings ~~in 2022,~~for the remainder of 2023, as well as in subsequent years, will be contingent on investment opportunities and our cash requirements and will depend upon prevailing market conditions, regulatory approvals, and other factors. We plan to maintain a capital structure consistent with that approved by the PSCW. For more information on our approved capital structure, see Item 1. Business – C. Regulation in our ~~2021~~2022 Annual Report on Form 10-K.

The issuance of our securities is subject to the approval of the PSCW. Additionally, with respect to the public offering of securities, we file registration statements with the SEC under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the PSCW, as well as the securities registered under the 1933 Act, are closely monitored and appropriate filings are made to ensure flexibility in the capital markets.

AtAlthough not the case as of June 30, ~~2022,~~2023, our current liabilities ~~exceeded~~sometimes exceed our current ~~assets by $200.5 million. We~~assets. If this occurs, we do not expect ~~this to~~that it would have any impact on our liquidity, as we currently believe that our cash and cash equivalents, our available capacity of ~~$85.2~~$456.0 million under our existing revolving credit facility, cash generated from ongoing operations, and access to the capital markets are adequate to meet our short-term and long-term cash requirements.


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See Note 8,10, Short-Term Debt and Lines of Credit, for more information about our credit facility and commercial paper.

Investments in Outside Trusts

We maintain investments in outside trusts to fund the obligation to provide pension and certain OPEB benefits to current and future retirees. These trusts had investments consisting of fixed income and equity securities that are subject to the volatility of the stock market and interest rates. For more information, see Investments in Outside Trusts in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Sources of Cash in our ~~2021~~2022 Annual Report on Form 10-K.

Debt Covenants

Certain of our short-term debt agreements contain financial covenants that we must satisfy, including a debt to capitalization ratio. At June 30, ~~2022,~~2023, we were in compliance with all such covenants. We expect to be in compliance with all such debt covenants for the foreseeable future. See Note ~~11,~~12, Short-Term Debt and Lines of Credit, Note 13, Long-Term Debt, and Note 10, Common Equity, in our ~~2021~~2022 Annual Report on Form 10-K, for more information regarding our debt covenants.


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Credit Rating Risk

Cash collateral postings and prepayments made with external parties, including postings related to exchange-traded contracts, and cash collateral posted by external parties were immaterial as of June 30, ~~2022.~~2023. From time to time, we may enter into commodity contracts that could require collateral or a termination payment in the event of a credit rating change to below BBB- at S&P Global Ratings, a division of S&P Global Inc., and/or Baa3 at Moody’s Investors Service, Inc. If we had a sub-investment grade credit rating at June 30, ~~2022,~~2023, we could have been required to post $100 million of additional collateral or other assurances pursuant to the terms of a PPA. We also have other commodity contracts that, in the event of a credit rating downgrade, could result in a reduction of our unsecured credit granted by counterparties.

In addition, access to capital markets at a reasonable cost is determined in large part by credit quality. Any credit ratings downgrade could impact our ability to access capital markets.

Subject to other factors affecting the credit markets as a whole, we believe our current ratings should provide a significant degree of flexibility in obtaining funds on competitive terms. However, these security ratings reflect the views of the rating agency only. An explanation of the significance of these ratings may be obtained from the rating agency. Such ratings are not a recommendation to buy, sell, or hold securities. Any rating can be revised upward or downward or withdrawn at any time by a rating agency.

FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES

The following is a discussion of certain factors that may affect our results of operations, liquidity, and capital resources. This discussion should be read together with the information in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources in our ~~2021~~2022 Annual Report on Form 10-K, which provides a more complete discussion of factors affecting us, including market risks and other significant risks, competitive markets, environmental matters, critical accounting policies and estimates, and other matters.

~~COVID-19 Pandemic~~

~~We have taken steps to mitigate the impact of the global COVID-19 pandemic. However, the extent to which the COVID-19 pandemic could continue to impact our results of operations~~Regulatory, Legislative, and liquidity is largely dependent upon the ability of our customers to resume or maintain normal operations. Adverse impacts to us and our subsidiaries from a prolonged COVID-19 pandemic environment could include a decrease in revenues, increased bad debt expense, increases in past due accounts receivable balances, and access to the capital markets at unfavorable terms or rates.

We will continue to monitor COVID-19 pandemic-related developments affecting our workforce, customers, and suppliers and will implement additional actions that we determine to be necessary in order to mitigate any additional impacts. We cannot predict the full extent of the impacts of COVID-19, which will depend on, among other things, its duration through new variants, the rate and the effectiveness of both vaccinations and treatments, future regulatory and governmental actions, and the ability to maintain normal business activity.Legal Matters

~~Regulatory, Legislative,~~Petitions Before PSCW Regarding Third-Party Financed Distributed Energy Resources

In May 2022, two petitions were filed with the PSCW requesting a declaratory ruling that the owner of a third-party financed DER is not a "public utility" as defined under Wisconsin law and, ~~Legal Matters~~therefore, is not subject to the PSCW’s jurisdiction under any statute or rule regulating public utilities. The parties that filed the petitions provide financing to their customers for installation of DERs (including solar panels and energy storage) on the customer’s property. A DER is connected to the host customer’s utility meter and is used for the customer’s energy needs. It may also be connected to the grid for distribution.


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In July 2022, the PSCW found that the specific facts and circumstances merited the opening of a docket for each petition to consider whether to grant all or part of the requested declaratory ruling.

In December 2022, the PSCW granted one petitioner’s request for a declaratory ruling, finding that the owner of the third-party financed DER at issue in the petitioner’s brief is not a public utility under Wisconsin law. The ruling was limited to the specific facts and circumstances of the lease presented in that petition. A petition by the WUA to reopen or rehear the case expired without action by the PSCW. The WUA has filed an appeal which is pending consideration by the circuit court. The second petition is also currently being considered. Although the finding in the first petition was limited to the specific facts and circumstances of the lease presented in that petition, similar findings or a broader policy position could adversely impact our business operations.

Uyghur Forced Labor Prevention Act

The CBP issued a WRO in June 2021, applicable to certain silica-based products originating from the Xinjiang Uyghur Autonomous Region of China (Xinjiang), such as polysilicon, included in the manufacturing of solar panels. In June 2022, the WRO was superseded by the implementation of the UFLPA, which was signed into law by President Biden in December 2021. The UFLPA establishes a rebuttable presumption that any imports wholly or partially manufactured in Xinjiang are prohibited from entering the United States. While our suppliers were able to provide the CBP sufficient documentation to meet WRO compliance requirements, and we expect the same will be true for UFLPA purposes, we cannot currently predict what, if any, long-term impact the UFLPA will have on the overall supply of solar panels into the United States and the related long-term impact to timing and cost of our solar projects included in WEC Energy Group's capital plan. However, we are seeing some delays in the release of solar panels by the CBP, which are having an impact on the timing and cost of certain of our solar projects.


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United States Department of Commerce ~~Complaint~~

In August 2021, a group of anonymous domestic solar manufacturers filed a petition (AD/CVD) with the DOC seeking to impose new tariffs on solar panels and cells imported from several countries, including Malaysia, Vietnam, and Thailand. The petitioners claimed that Chinese solar manufacturers are shifting products to these countries to avoid the tariffs required on products imported from China. In November 2021, the DOC rejected this petition. In denying the petition, the DOC cited the anonymous group’s refusal of the DOC’s request to provide more detail and identify its members due to concerns about retribution from the dominant Chinese solar industry.Complaints

In February 2022, a California based company filed a petition ~~(AD/CVD)~~(Antidumping and Countervailing Duties) with the DOC seeking to impose new tariffs on solar panels and cells imported from multiple countries, including Malaysia, Vietnam, Thailand, and Cambodia. ~~While~~The petitioners claimed that Chinese solar manufacturers are shifting products to these countries to avoid the ~~petition is similar to the one rejected by the DOC in November 2021, there are notable differences. The group added Cambodia to the petition~~tariffs required on products imported from China and ~~is requesting~~requested that the DOC conduct a country-wide inquiry into each of the four countries. ~~In March~~After investigation, on December 2, 2022, the DOC ~~decided to act~~announced its preliminary determination that certain companies are circumventing anti-dumping and countervailing duty orders on ~~the February petition~~solar cells and ~~investigate the claim.~~modules from China. A ~~DOC~~final decision is currently expected ~~by January~~in the third quarter of 2023. If the DOC determines that ~~the petition has merit,~~such circumvention is occurring it would be able to apply any final tariffs retroactively to November 4, 2021. If imposed, the new tariffs ~~are expected to~~could further disrupt the supply of solar modules to the United States, and could impact the cost and timing of our solar projects.

InTo address concerns raised about the adverse impact from the ongoing DOC complaint on the U.S. solar industry, in June 2022, the Biden Administration used its executive powers to issue a 24-month tariff moratorium on solar panels manufactured in Cambodia, Malaysia, Thailand, and Vietnam. ~~The moratorium comes as a direct response to concerns raised about~~In May 2023, the ~~adverse impact from~~Biden Administration vetoed legislation that would have repealed the ~~ongoing DOC complaint on the U.S. solar industry. As the DOC will continue its investigation discussed above, companies~~moratorium. Companies may still be subject to tariffs after the moratorium ends; however, U.S. companies will reportedly be exempt from any retroactive tariffs that previously could have applied. ~~The~~Additionally, the Biden Administration also ~~announced that it will invoke~~invoked the Defense Production Act to accelerate the production of solar panels in the U.S. The Biden Administration's actions did not address whether WROs applied to panels under previous complaints would be affected.

Infrastructure Investment and Jobs Act

In November 2021, President Biden signed into law the Infrastructure Investment and Jobs Act, which provides for approximately $1.2 trillion of federal spending over the next five years, including approximately $85 billion for investments in power, utilities, and renewables infrastructure across the United States. We expect funding from this Act will support the work we are doing to reduce GHG emissions, increase EV charging, and strengthen and protect the energy grid. Funding in the Act should also help to expand emerging technologies, like hydrogen and carbon management, as we continue the transition to a clean energy future. We believe the Infrastructure Investment and Jobs Act will accelerate investment in projects that will help us meet our net zero emission goals to the benefit of our customers, the communities we serve, and our company.

Inflation Reduction Act

In August 2022, President Biden signed into law the IRA, which provides for $258 billion in energy-related provisions over a 10-year period. The provisions of the IRA are intended to, among other things, lower gasoline and electricity prices, incentivize domestic


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clean energy investment, manufacturing, and production, and promote reductions in carbon emissions. We believe that we and our customers can benefit from the IRA’s provisions that extend tax benefits for renewable technologies, increase or restore higher rates for PTCs, add an option to claim PTCs for solar projects, expand qualified ITC facilities to include standalone energy storage, and its provision to allow companies to transfer tax credits generated from renewable projects. The IRA also implements a 15% corporate alternative minimum tax and a 1% excise tax on stock repurchases. Although significant regulatory guidance is expected on the tax provisions in the IRA, we currently believe the provisions on alternative minimum tax and stock repurchases will not have a material impact on us. Overall, we believe the IRA will help reduce our cost of investing in projects that will support our commitment to reduce emissions and provide customers affordable, reliable, and clean energy over the longer term.

Environmental Matters

See Note ~~18,~~20, Commitments and Contingencies, for a discussion of certain environmental matters affecting us, including rules and regulations relating to air quality, water quality, land quality, and climate change.

Market Risks and Other Significant Risks

We are exposed to market and other significant risks as a result of the nature of our business and the environment in which we operate. These risks include, but are not limited to, the inflation and supply chain disruptions described below. In addition, there is continuing uncertainty over the impact that the ongoing conflict between Russia and Ukraine will have on the global economy, supply chains, and fuel prices. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Market Risks and Other Significant Risks in our ~~2021~~2022 Annual Report on Form 10-K for a discussion of market and other significant risks applicable to us.


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Inflation and Supply Chain Disruptions

We continue to monitor the impact of inflation and supply chain disruptions. We monitor the costs of medical plans, fuel, transmission access, construction costs, regulatory and environmental compliance costs, and other costs in order to minimize inflationary effects in future years, to the extent possible, through pricing strategies, productivity improvements, and cost reductions. We monitor the global supply chain, and related disruptions, in order to ensure we are able to procure the necessary materials and other resources necessary to both maintain our energy services in a safe and reliable manner and to grow our infrastructure in accordance with WEC Energy Group's capital plan. For additional information concerning risks related to inflation and supply chain disruptions, see the ~~two~~three risk factors below that are disclosed in Part I of our ~~2021~~2022 Annual Report on Form 10-K.

•Item 1A. Risk Factors – Risks Related to the Operation of Our Business – Our operations and corporate strategy may be adversely affected by supply chain disruptions and inflation.

•Item 1A. Risk Factors – Risks Related to the Operation of Our Business – We are actively involved with multiple significant capital projects, which are subject to a number of risks and uncertainties that could adversely affect project costs and completion of construction projects.

•Item 1A. Risk Factors – Risks Related to Economic and Market Volatility – Fluctuating commodity prices could negatively impact our electric and natural gas utility operations.

For additional information concerning risk factors, including market risks, see the Cautionary Statement Regarding Forward-Looking Information at the beginning of this report.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no material changes related to market risk from the disclosures presented in our ~~2021~~2022 Annual Report on Form 10-K. In addition to the Form 10-K disclosures, see Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – ~~COVID-19 Pandemic and~~ Market Risks and Other Significant Risks in Item 2 of Part I of this report, as well as Note ~~12,~~14, Fair Value Measurements, Note ~~13,~~15, Derivative Instruments, and Note ~~14,~~16, Guarantees, in this report for information concerning our market risk exposures.


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ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based upon such evaluation, our principal executive officer and principal financial officer have concluded that, as of the end of such period, our disclosure controls and procedures are effective: (i) in recording, processing, summarizing, and reporting, on a timely basis, information required to be disclosed by us in the reports that we file or submit under the Exchange Act; and (ii) to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting (as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the second quarter of ~~2022~~2023 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The following should be read in conjunction with Item 3. Legal Proceedings in Part I of our ~~2021~~2022 Annual Report on Form 10-K. See Note ~~18,~~20, Commitments and Contingencies, and Note ~~20,~~22, Regulatory Environment, in this report for additional information on material legal proceedings and matters related to us.

In addition to those legal proceedings discussed in Note ~~18,~~20, Commitments and Contingencies, ~~and~~ Note ~~20,~~22, Regulatory Environment, and below, we are currently, and from time to time, subject to claims and suits arising in the ordinary course of business. Although the results of these additional legal proceedings cannot be predicted with certainty, management believes, after consultation with legal counsel, that the ultimate resolution of these proceedings will not have a material ~~effect~~impact on our financial statements.

Employee Retirement Savings Plan Matter

In May 2022, a putative class action, Munt, et al. v. WEC Energy Group, Inc., et al., was filed in the United States District Court for the Eastern District of Wisconsin - Milwaukee Division. The plaintiffs allege that WEC Energy Group and others breached their fiduciary duties with respect to the operation and oversight of WEC Energy Group's Employee Retirement Saving Plan (the “Plan”) in violation of the Employee Retirement Income Security Act of 1974, as amended. The class is alleged to be participants in the Plan from May 10, 2016 through the date of judgment. The complaint seeks injunctive relief, damages, interest, costs, and attorneys' fees. WEC Energy Group is vigorously defending against the allegations made in this lawsuit and intends to continue to do so.

ITEM 1A. RISK FACTORS

There were no material changes from the risk factors disclosed in Item 1A. Risk Factors in Part I of our ~~2021~~2022 Annual Report on Form 10-K.

ITEM 5. OTHER INFORMATION

During the three months ended June 30, 2023, none of our directors or officers (as defined in Rule 16a-1 under the Exchange Act) adopted or terminated any contract, instruction, or written plan for the purchase or sale of our securities that was intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) or any "non-Rule 10b5-1 trading arrangement" (as defined in Item 408 of Regulation S-K).


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ITEM 6. EXHIBITS



Number	Exhibit














31	Rule 13a-14(a) / 15d-14(a) Certifications

	31.1	Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	31.2	Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32	Section 1350 Certifications

	32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

	32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101	Interactive Data Files

	101.INS	Inline XBRL Instance Document – the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document

	101.SCH	Inline XBRL Taxonomy Extension Schema

	101.CAL	Inline XBRL Taxonomy Extension Calculation Linkbase

	101.DEF	Inline XBRL Taxonomy Extension Definition Linkbase

	101.LAB	Inline XBRL Taxonomy Extension Label Linkbase

	101.PRE	Inline XBRL Taxonomy Extension Presentation Linkbase

104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)


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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


		WISCONSIN ELECTRIC POWER COMPANY
		(Registrant)

		/s/ WILLIAM J. GUC
Date:	August ~~4, 2022~~3, 2023	William J. Guc
		Vice President, Controller, and Assistant Corporate Secretary

		(Duly Authorized Officer and Chief Accounting Officer)


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Proposed 2023 rate increase
Electric	$	285.6	million	/	9.2%
Gas	$	55.4	million	/	11.7%
Steam	$	3.6	million	/	16.5%
Proposed ROE (1)	10.0%
Proposed common equity component average on a financial basis (1)	53.0%