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, dividend payout ratios, effective tax rates, pension and OPEB plans, fuel costs, sources of electric energy supply, coal and natural gas deliveries, remediation costs, climate-related matters, our 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 2023 Annual Report on Form 10-K, and those identified below:
•Factors affecting utility and non-utility energy infrastructure operations such as catastrophic weather-related damage, environmental incidents, unplanned facility outages and repairs and maintenance, electric grid reliability, 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, the results of recent or upcoming rate orders, 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, as well as changes in the interpretation and/or enforcement of any laws or regulations by regulatory agencies;
•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 focus 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, tariffs, and other factors;
•The impact of public health crises, including epidemics and pandemics, on our business functions, financial condition, liquidity, and results of operations;
•Factors affecting the implementation of our 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, technology advances, the feasibility of competing generation projects, and our ability to execute our 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, including from sanctions, and impacts on supply chains and fuel prices, generally, from ongoing, expanding, or escalating regional conflicts, including those in Ukraine, Israel, and other parts of the Middle East;
•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, us, or any of our subsidiaries;
•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 cybersecurity 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;
•Restrictions imposed by various financing arrangements and regulatory requirements on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans or advances, that could prevent us from paying our common stock dividends, taxes, and other expenses, and meeting our debt obligations;
•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 financial performance of ATC and its corresponding contribution to our earnings;
•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;
•Risks related to our non-utility renewable energy facilities, including unfavorable weather, changes in the financial performance and/or creditworthiness of counterparties to the off-take agreements, changes in demand based on lower prices for alternative energy sources, the ability to replace expiring PPAs under acceptable terms, risks of rights related to property on which our projects are located but we do not own, the availability of reliable interconnection and electricity grids, and exposure to the rules and procedures of the power markets in which these facilities are located;
•The risk associated with the values of goodwill and other long-lived assets, including intangible assets, and equity method investments, and their possible impairment;
•Potential business strategies to acquire and dispose of assets or businesses, or portions thereof, which cannot be assured to be completed timely or within budgets, and legislative or regulatory restrictions or caps on non-utility acquisitions, investments or projects, including the State of Wisconsin's public utility holding company law;
•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.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
September 30, 2024
NOTE 1—GENERAL INFORMATION
WEC Energy Group serves approximately 1.7 million electric customers and 3.0 million natural gas customers, owns approximately 60% of ATC, and owns majority interests in multiple renewable generating facilities as part of its non-utility energy infrastructure segment.
As used in these notes, the term "financial statements" refers to the condensed consolidated financial statements. This includes the income statements, statements of comprehensive income, balance sheets, statements of cash flows, and statements of equity, unless otherwise noted. In this report, when we refer to "the Company," "us," "we," "our," or "ours," we are referring to WEC Energy Group and all of its subsidiaries.
On our financial statements, we consolidate our majority-owned subsidiaries, which we control, and VIEs, of which we are the primary beneficiary. We reflect noncontrolling interests for the portion of entities that we do not own as a component of consolidated equity separate from the equity attributable to our shareholders. The noncontrolling interests that we reported as equity on our balance sheets related to the minority interests held by third parties in the renewable generating facilities that are included in our non-utility energy infrastructure segment.
We use the equity method to account for investments in companies we do not control but over which we exercise significant influence regarding their operating and financial policies. As a result of our limited voting rights, we account for ATC and ATC Holdco as equity method investments. See Note 20, Investment in Transmission Affiliates, for more information.
We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2023. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three and nine months ended September 30, 2024, are not necessarily indicative of expected results for 2024 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—ACQUISITIONS
In accordance with Topic 805: Clarifying the Definition of a Business (ASU 2017-01), transactions are evaluated and are accounted for as acquisitions 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 asset acquisitions. The purchase price of certain acquisitions below includes intangibles recorded as long-term liabilities related to PPAs. See Note 19, Goodwill and Intangibles, for more information.
Acquisition of a Solar Generation Facility in Ohio
In October 2024, WECI signed an agreement to acquire a 90% ownership interest in Hardin III, a 250 MW solar generating facility under construction in Hardin County, Ohio for $407.3 million. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 15 years from the date of commercial operation. The transaction is subject to FERC approval and commercial operation is expected to begin during the first quarter of 2025, at which time the transaction is expected to close. Hardin III is expected to qualify for PTCs and will be included in the non-utility energy infrastructure segment.
Acquisitions of Electric Generation Facilities in Wisconsin
In May 2024, WE completed the acquisition of 100 MWs of West Riverside's nameplate capacity for $97.9 million. West Riverside is a commercially operational dual fueled combined cycle generation facility in Beloit, Wisconsin. Prior to the acquisition, WPS received
approval to transfer its ownership interest rights to WE. Including this acquisition, WE owns 200 MWs, or 27.5%, of West Riverside at a total cost of $193.2 million.
In April 2023, WPS, along with an unaffiliated utility, completed the acquisition of Red Barn, a commercially operational utility-scale wind-powered electric generating facility. The project is located in Grant County, Wisconsin and WPS owns 82 MWs of this project. WPS's share of the cost of this project was $143.8 million. Red Barn qualifies for PTCs.
In January 2023, WE and WPS completed the acquisition of Whitewater, a commercially operational 236.5 MW dual fueled (natural gas and low sulfur fuel oil) combined cycle electric generation facility in Whitewater, Wisconsin, for $76.0 million.
Acquisitions of Electric Generation Facilities in Illinois
In October 2022, WECI signed an agreement to acquire an 80% ownership interest in Maple Flats, a 250 MW solar generating facility under construction in Clay County, Illinois. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 15 years from the date of commercial operation. The transaction is subject to FERC approval and commercial operation is expected to begin during the fourth quarter of 2024, at which time the transaction is expected to close. Maple Flats is expected to qualify for PTCs and will be included in the non-utility energy infrastructure segment. In May 2024, WECI signed an agreement to acquire an additional 10% ownership interest in Maple Flats, bringing the total acquisition price to approximately $431 million.
In February 2023, upon achievement of commercial operation, WECI completed the acquisition of a 90% ownership interest in Sapphire Sky, a 250 MW wind generating facility in McLean County, Illinois, for a total investment of $442.6 million, which includes transaction costs and is net of cash acquired. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 12 years from the date of commercial operation. Sapphire Sky qualifies for PTCs and is included in the non-utility energy infrastructure segment.
Acquisitions of Solar Generation Facilities in Texas
In March 2024, WECI signed an agreement to acquire a 90% ownership interest in Delilah I, a 300 MW solar generating facility under construction in Lamar County, Texas, for approximately $459.0 million. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 15 years from the date of commercial operation. The transaction is subject to FERC approval and, as a result of storm damage sustained in May 2024, commercial operation is now expected to begin by the end of 2024, at which time the transaction is expected to close. Delilah I is expected to qualify for PTCs and will be included in the non-utility energy infrastructure segment.
In February 2023, WECI completed the acquisition of an 80% ownership interest in Samson I, a commercially operational 250 MW solar generating facility in Lamar County, Texas. Samson I was acquired for $257.3 million, which included payments related to contingent consideration, transaction costs, and was net of cash acquired. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 15 years from the date of commercial operation, May 2022. Samson I qualifies for PTCs and is included in the non-utility energy infrastructure segment. In January 2024, WECI acquired an additional 10% ownership interest in Samson I for $28.1 million.
NOTE 3—DISPOSITION
Wisconsin Segment
Sale of Certain Real Estate by Wisconsin Electric Power Company
In June 2023, we sold approximately 192 acres of real estate at WE's former Pleasant Prairie power plant site that was no longer being utilized in its 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.
For more information about our operating revenues, see Note 1(d), Operating Revenues, in our 2023 Annual Report on Form 10-K.
Disaggregation of Operating Revenues
The following tables present our operating revenues disaggregated by revenue source. We do not have any revenues associated with our electric transmission segment, which includes investments accounted for using the equity method. We disaggregate revenues into categories that depict how the nature, amount, timing, and uncertainty of revenues and cash flows are affected by economic factors. For our segments, revenues are further disaggregated by electric and natural gas operations and then by customer class. Each customer class within our electric and natural gas operations has different expectations of service, energy and demand requirements, and can be impacted differently by regulatory activities within their jurisdictions.
(1)Amounts eliminated represent lease revenues related to certain plants that We Power leases to WE to supply electricity to its customers. Lease payments are billed from We Power to WE and then recovered in WE's rates as authorized by the PSCW and the FERC. WE operates the plants and is authorized by the PSCW and Wisconsin state law to fully recover prudently incurred operating and maintenance costs in electric rates.
Revenues from Contracts with Customers
Electric Utility Operating Revenues
The following table disaggregates electric utility operating revenues into customer class:
Three Months Ended September 30
Nine Months Ended September 30
(in millions)
2024
2023
2024
2023
Residential
$
592.4
$
584.9
$
1,534.2
$
1,530.5
Small commercial and industrial
457.9
462.2
1,233.2
1,257.3
Large commercial and industrial
284.1
289.9
726.6
759.6
Other
7.2
7.2
22.3
22.4
Total retail revenues
1,341.6
1,344.2
3,516.3
3,569.8
Wholesale
27.0
31.9
80.3
96.5
Resale
46.0
75.3
128.9
147.8
Steam
2.2
2.6
16.5
18.2
Other utility revenues
5.4
3.8
14.0
7.8
Total electric utility operating revenues
$
1,422.2
$
1,457.8
$
3,756.0
$
3,840.1
Natural Gas Utility Operating Revenues
The following tables disaggregate natural gas utility operating revenues into customer class:
(1)Includes the revenues subject to the purchased gas recovery mechanisms of our utilities, which fluctuate by segment based on actual natural gas costs incurred at our utilities, compared with the recovery of natural gas costs that were anticipated in rates.
Other Natural Gas Operating Revenues
We have other natural gas operating revenues from Bluewater, which is in our non-utility energy infrastructure segment. Bluewater has entered into long-term service agreements for natural gas storage services with WE, WPS, and WG. All amounts associated with the service agreements with WE, WPS, and WG have been eliminated at the consolidated level.
Other Non-Utility Operating Revenues
Other non-utility operating revenues consist primarily of the following:
Three Months Ended September 30
Nine Months Ended September 30
(in millions)
2024
2023
2024
2023
Wind generation revenues
$
40.0
$
38.2
$
133.8
$
117.8
We Power revenues (1)
6.1
5.7
18.2
17.5
Appliance service revenues
5.1
4.9
15.0
14.8
Total other non-utility operating revenues
$
51.2
$
48.8
$
167.0
$
150.1
(1)As part of the construction of the We Power electric utility generating units, we capitalized interest during construction, which is included in property, plant, and equipment. As allowed by the PSCW, we collected these carrying costs from WE's utility customers during construction. The equity portion of these carrying costs was recorded as a contract liability, which is presented as deferred revenue, net on our balance sheets. We continually amortize the deferred carrying costs to revenues over the related lease term that We Power has with WE.
Other operating revenues consist primarily of the following:
Three Months Ended September 30
Nine Months Ended September 30
(in millions)
2024
2023
2024
2023
Late payment charges
$
10.4
$
12.4
$
39.1
$
45.8
Alternative revenues (1)
(1.7)
—
71.1
13.9
Other
0.5
1.0
3.3
3.6
Total other operating revenues
$
9.2
$
13.4
$
113.5
$
63.3
(1)Alternative revenues consist of amounts to be recovered or refunded to customers subject to decoupling mechanisms, wholesale true-ups, and conservation improvement rider true-ups. Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. For more information about our alternative revenues, see Note 1(d), Operating Revenues, in our 2023 Annual Report on Form 10-K.
NOTE 5—CREDIT LOSSES
Our exposure to credit losses is related to our accounts receivable and unbilled revenue balances, which are primarily generated from the sale of electricity and natural gas by our regulated utility operations. Credit losses associated with our utility operations are analyzed at the reportable segment level as we believe contract terms, political and economic risks, and the regulatory environment are similar at this level as our reportable segments are generally based on the geographic location of the underlying utility operations.
We have an accounts receivable and unbilled revenue balance associated with our non-utility energy infrastructure segment related to the sale of electricity from our majority-owned renewable generating facilities through agreements with several large high credit quality counterparties.
We evaluate the collectability of our accounts receivable and unbilled revenue balances considering a combination of factors. For some of our larger customers and also in circumstances where we become aware of a specific customer's inability to meet its financial obligations to us, we record a specific allowance for credit losses against amounts due in order to reduce the net recognized receivable to the amount we reasonably believe will be collected. For all other customers, we use the accounts receivable aging method to calculate an allowance for credit losses. Using this method, we classify accounts receivable into different aging buckets and calculate a reserve percentage for each aging bucket based upon historical loss rates. The calculated reserve percentages are updated on at least an annual basis, in order to ensure recent macroeconomic, political, and regulatory trends are captured in the calculation, to the extent possible. Risks identified that we do not believe are reflected in the calculated reserve percentages, are assessed on a quarterly basis to determine whether further adjustments are required.
We monitor our ongoing credit exposure through active review of counterparty accounts receivable balances against contract terms and due dates. Our activities include timely account reconciliation, dispute resolution and payment confirmation. To the extent possible, we work with customers with past due balances to negotiate payment plans, but will disconnect customers for non-payment as allowed by our regulators, if necessary, and employ collection agencies and legal counsel to pursue recovery of defaulted receivables. For our larger customers, detailed credit review procedures may be performed in advance of any sales being made. We sometimes require letters of credit, parental guarantees, prepayments or other forms of credit assurance from our larger customers to mitigate credit risk.
We have included tables below that show our gross third-party receivable balances and the related allowance for credit losses at September 30, 2024 and December 31, 2023, by reportable segment.
(in millions)
Wisconsin
Illinois
Other States
Total Utility Operations
Non-Utility Energy Infrastructure
Corporate and Other
WEC Energy Group Consolidated
September 30, 2024
Accounts receivable and unbilled revenues
$
937.8
$
326.8
$
32.9
$
1,297.5
$
26.7
$
6.3
$
1,330.5
Allowance for credit losses
63.9
86.9
4.2
155.0
—
—
155.0
Accounts receivable and unbilled revenues, net (1)
$
873.9
$
239.9
$
28.7
$
1,142.5
$
26.7
$
6.3
$
1,175.5
Total accounts receivable, net – past due greater than 90 days (1)
$
52.5
$
50.2
$
4.0
$
106.7
$
—
$
—
$
106.7
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)
93.6
%
100.0
%
—
%
93.1
%
—
%
—
%
93.1
%
(in millions)
Wisconsin
Illinois
Other States
Total Utility Operations
Non-Utility Energy Infrastructure
Corporate and Other
WEC Energy Group Consolidated
December 31, 2023
Accounts receivable and unbilled revenues
$
1,078.0
$
481.5
$
94.9
$
1,654.4
$
33.9
$
8.4
$
1,696.7
Allowance for credit losses
77.4
109.7
6.4
193.5
—
—
193.5
Accounts receivable and unbilled revenues, net (1)
$
1,000.6
$
371.8
$
88.5
$
1,460.9
$
33.9
$
8.4
$
1,503.2
Total accounts receivable, net – past due greater than 90 days (1)
$
51.7
$
45.0
$
2.1
$
98.8
$
—
$
—
$
98.8
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)
93.6
%
100.0
%
—
%
94.5
%
—
%
—
%
94.5
%
(1)Our exposure to credit losses for certain regulated utility customers is mitigated by regulatory mechanisms we have in place. Specifically, rates related to all of the customers in our Illinois segment, as well as the residential rates of WE, WPS, and WG in our Wisconsin segment, include riders or other mechanisms for cost recovery or refund of uncollectible expense based on the difference between the actual provision for credit losses and the amounts recovered in rates. As a result, at September 30, 2024, $670.1 million, or 57.0%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses.
A roll-forward of the allowance for credit losses by reportable segment is included below:
Three Months Ended September 30, 2024
(in millions)
Wisconsin
Illinois
Other States
WEC Energy Group Consolidated
Balance at July 1, 2024
$
68.7
$
93.2
$
5.0
$
166.9
Provision for credit losses
12.6
11.5
(0.3)
23.8
Provision for credit losses deferred for future recovery or refund
3.8
(11.0)
—
(7.2)
Write-offs charged against the allowance
(30.8)
(12.9)
(2.5)
(46.2)
Recoveries of amounts previously written off
9.6
6.1
2.0
17.7
Balance at September 30, 2024
$
63.9
$
86.9
$
4.2
$
155.0
Nine Months Ended September 30, 2024
(in millions)
Wisconsin
Illinois
Other States
WEC Energy Group Consolidated
Balance at January 1, 2024
$
77.4
$
109.7
$
6.4
$
193.5
Provision for credit losses
36.2
38.8
(1.6)
73.4
Provision for credit losses deferred for future recovery or refund
On a consolidated basis, there was a $38.5 million decrease in the allowance for credit losses at September 30, 2024, compared to January 1, 2024, largely 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. In Wisconsin, the winter moratorium begins on November 1 and ends on April 15, and in Illinois the winter moratorium begins on December 1 and ends on March 31. Also contributing to the decrease in the allowance for credit losses, we have seen lower required reserve percentages at many of our regulated utilities as a result of an improvement in loss rates. We also believe that the lower energy costs that customers were seeing, which were driven by warmer than normal weather conditions in the first half of 2024 and low average natural gas prices, contributed to a reduction in past due accounts receivable balances and a related decrease in the allowance for credit losses.
Three Months Ended September 30, 2023
(in millions)
Wisconsin
Illinois
Other States
WEC Energy Group Consolidated
Balance at July 1, 2023
$
76.4
$
97.0
$
5.3
$
178.7
Provision for credit losses
10.2
4.0
0.6
14.8
Provision for credit losses deferred for future recovery or refund
9.8
7.1
—
16.9
Write-offs charged against the allowance
(31.8)
(14.4)
(1.5)
(47.7)
Recoveries of amounts previously written off
7.4
6.3
0.4
14.1
Balance at September 30, 2023
$
72.0
$
100.0
$
4.8
$
176.8
Nine Months Ended September 30, 2023
(in millions)
Wisconsin
Illinois
Other States
WEC Energy Group Consolidated
Balance at January 1, 2023
$
82.0
$
111.0
$
6.3
$
199.3
Provision for credit losses
28.1
17.3
1.5
46.9
Provision for credit losses deferred for future recovery or refund
26.3
13.8
—
40.1
Write-offs charged against the allowance
(89.8)
(58.7)
(4.2)
(152.7)
Recoveries of amounts previously written off
25.4
16.6
1.2
43.2
Balance at September 30, 2023
$
72.0
$
100.0
$
4.8
$
176.8
On a consolidated basis, there was a $22.5 million decrease in the allowance for credit losses at September 30, 2023, compared to January 1, 2023, driven by customer write-offs related to the end of the winter moratorium. In addition, lower energy costs 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.
The following regulatory assets and liabilities were reflected on our balance sheets at September 30, 2024 and December 31, 2023. For more information on our regulatory assets and liabilities, see Note 6, Regulatory Assets and Liabilities, in our 2023 Annual Report on Form 10-K.
(in millions)
September 30, 2024
December 31, 2023
Regulatory assets
Plant retirement related items (1)
$
814.3
$
646.2
Pension and OPEB costs
721.1
731.7
Environmental remediation costs
565.8
596.8
Income tax related items
438.9
449.9
AROs
169.3
162.0
Uncollectible expense
123.4
127.7
System support resource
105.5
113.2
Decoupling (2)
100.5
27.3
Securitization
79.1
85.9
Bluewater
54.8
45.3
Derivatives
50.6
130.3
Energy efficiency programs
32.4
33.9
Other, net
149.9
124.5
Total regulatory assets
$
3,405.6
$
3,274.7
Balance sheet presentation
Other current assets
$
59.1
$
24.9
Regulatory assets
3,346.5
3,249.8
Total regulatory assets
$
3,405.6
$
3,274.7
(1) At September 30, 2024, plant retirement related items included $115.0 million of capitalized retirement costs related to the new EPA CCR Rule that was enacted in April 2024. See Note 23, Commitments and Contingencies, for more information.
(2) PGL, NSG, and MERC have decoupling mechanisms. These mechanisms differ by state and allow the utilities to recover the differences between actual and authorized margins for certain customer classes.
(in millions)
September 30, 2024
December 31, 2023
Regulatory liabilities
Income tax related items
$
1,838.0
$
1,901.8
Removal costs
1,429.5
1,329.9
Pension and OPEB benefits
301.2
299.2
Energy costs refundable through rate adjustments
126.0
72.4
Uncollectible expense
39.2
21.2
Paris (1)
31.8
—
Derivatives
29.1
19.2
Electric transmission costs
20.5
30.3
Energy efficiency programs
16.7
17.2
Other, net
89.6
54.0
Total regulatory liabilities
$
3,921.6
$
3,745.2
Balance sheet presentation
Other current liabilities
$
32.5
$
47.5
Regulatory liabilities
3,889.1
3,697.7
Total regulatory liabilities
$
3,921.6
$
3,745.2
(1) In accordance with our Wisconsin rate orders approved by the PSCW in December 2023, WE and WPS are deferring to a future rate proceeding the incremental revenue requirement impact associated with the change to the in-service date of Paris.
In May 2024, OCPP Units 5 and 6 were retired. Due to the retirement of these units and the determination that recovery was probable, their net book value of $76.8 million at September 30, 2024 was classified as a regulatory asset. In addition, a $43.8 million cost of removal reserve related to the units continued to be classified as a regulatory liability at September 30, 2024. Not included in these amounts was $9.0 million of deferred tax liabilities previously recorded for the retired units. Effective with its rate order issued by the PSCW in December 2022, WE received approval to collect a return of and on the entire net book value of OCPP Units 5 and 6 and, as a result, will continue to amortize the regulatory asset on a straight-line basis, using the composite depreciation rates approved by the PSCW before the units were retired. The amortization is included in depreciation and amortization on the income statement. WE also intends to request FERC approval to continue to collect the net book value of OCPP Units 5 and 6 using the approved composite depreciation rates, in addition to a return on the remaining net book value.
NOTE 7—PROPERTY, PLANT, AND EQUIPMENT
Wisconsin Segment Plant to be Retired
Oak Creek Power Plant Units 7-8
As a result of a PSCW approval in December 2022 for the acquisition and construction of Darien, the retirement of OCPP Units 7 and 8 became probable. Subsequently, we have received PSCW approval for Koshkonong and have acquired 200 MWs of capacity in West Riverside, and have acquired additional projects. See Note 2, Acquisitions, for more information on the West Riverside acquisitions. OCPP Units 7 and 8 are expected to be retired by late 2025. The total net book value of WE's ownership share of OCPP Units 7 and 8 was $666.7 million at September 30, 2024, 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 continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW.
Columbia Units 1 and 2
As a result of a MISO ruling received in June 2021, retirement of the jointly-owned Columbia Units 1 and 2 became probable. The total net book value of WPS's ownership share of Columbia Units 1 and 2 was $252.7 million at September 30, 2024, 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 WPS continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW.
Samson I Solar Energy Center LLC – Storm Damage
During several storms that occurred in 2023 and 2024, certain sections of our Samson I solar facility incurred damage. As of September 30, 2024, we recognized an impairment of $5.4 million related to storm damage, which was offset by a $5.4 million receivable for future insurance recoveries. Although we may experience differences between periods in the timing of cash flows, we do not currently expect a significant impact to our long-term cash flows from these storms.
NOTE 8—ASSET RETIREMENT OBLIGATIONS
Our utilities have recorded AROs primarily for the removal of natural gas distribution mains and service pipes (including asbestos and PCBs); asbestos abatement at certain generation and substation facilities, office buildings, and service centers; the removal and dismantlement of a biomass generation facility; the dismantling of wind and solar generation projects; the disposal of PCB-contaminated transformers; the closure of CCR landfills at certain generation facilities; and the removal of above ground and underground storage tanks. Regulatory assets and liabilities are established by our utilities to record the differences between ongoing expense recognition under the ARO accounting rules and the ratemaking practices for retirement costs authorized by the applicable regulators.
WECI has also recorded AROs for the dismantling of our non-utility renewable generation projects.
(1) AROs increased primarily as a result of AROs being recorded related to the new EPA CCR Rule that was enacted in April 2024. See Note 23, Commitments and Contingencies, for more information.
(2) AROs increased primarily as a result of AROs being recorded for the legal requirement to dismantle, at retirement, the Red Barn wind-powered generation project and the Sapphire Sky and Samson I non-utility renewable generation projects.
NOTE 9—COMMON EQUITY
Stock-Based Compensation
During the nine months ended September 30, 2024, the Compensation Committee of our Board of Directors awarded the following stock-based compensation to our directors, officers, and certain other key employees:
Award Type
Number of Awards
Stock options (1)
294,990
Restricted shares (2)
108,484
Performance units
205,051
(1)Stock options awarded had a weighted-average exercise price of $84.92 and a weighted-average grant date fair value of $16.19 per option.
(2)Restricted shares awarded had a weighted-average grant date fair value of $84.97 per share.
Restrictions
Our ability as a holding company to pay common stock dividends primarily depends on the availability of funds received from our utility subsidiaries, We Power, Bluewater, ATC Holding LLC (which holds our ownership interest in ATC), and WECI. Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans, or advances. Our utility subsidiaries, with the exception of UMERC and MGU, are prohibited from loaning funds to us, either directly or indirectly. See Note 11, Common Equity, in our 2023 Annual Report on Form 10-K for additional information on these and other restrictions.
We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future.
Common Stock
As of January 1, 2024, we began issuing new shares of common stock to fulfill our obligations under various stock-based employee benefit and compensation plans and to provide shares to participants in our dividend reinvestment and stock purchase plan. During 2023, we instructed our independent agents to purchase shares on the open market to fulfill obligations under these plans. As such, no new shares of common stock were issued during the three and nine months ended September 30, 2023.
On August 6, 2024, we entered into an EDA, under which we may offer and sell, from time to time, shares of our common stock having an aggregate sales price of up to $1.5 billion through an at-the-market offering program, which includes an equity forward sales component. We may offer and sell our common shares through the sales agents party to the EDA during the term of the agreement. The EDA will terminate upon the earliest of (i) the sale of all common stock subject to the EDA, (ii) termination of the EDA pursuant to its terms, or (iii) August 31, 2027. Actual sales of common stock under the EDA will depend on a variety of factors, including market conditions, the trading price of our common stock, capital needs, and our determination of the appropriate sources of funding. Any shares offered and sold will be done pursuant to our registration statement on Form S-3 filed with the SEC on
August 5, 2024 and the related prospectus supplement. As of September 30, 2024, we have not issued any shares of common stock under the EDA, and we have not entered into any forward sale agreements.
We had the following changes to our outstanding common stock during the three and nine months ended September 30, 2024:
Three Months Ended September 30, 2024
Nine Months Ended September 30, 2024
Common stock shares outstanding at beginning of period
316,079,401
315,434,531
Shares issued:
Stock-based compensation
137,936
300,602
401(k)
38,400
285,000
Stock investment plan
98,709
334,313
Common stock shares outstanding at end of period
316,354,446
316,354,446
On October 17, 2024, our Board of Directors declared a quarterly cash dividend of $0.835 per share, payable on December 1, 2024, to shareholders of record on November 14, 2024.
NOTE 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)
September 30, 2024
December 31, 2023
Commercial paper
Amount outstanding
$
592.4
$
2,017.2
Weighted-average interest rate on amounts outstanding
4.94
%
5.49
%
Operating expense loans
Amount outstanding (1)
$
4.6
$
3.7
(1)Coyote Ridge Wind, LLC, Tatanka Ridge, and Jayhawk have entered into operating expense loans. In accordance with their limited liability company operating agreements, they received loans from the holders of their noncontrolling interests in proportion to their ownership interests.
Our average amount of commercial paper borrowings based on daily outstanding balances during the nine months ended September 30, 2024 was $1,478.4 million with a weighted-average interest rate during the period of 5.48%.
The information in the table below relates to our revolving credit facilities used to support our commercial paper borrowing programs, including remaining available capacity under these facilities:
(in millions)
Maturity
September 30, 2024
WEC Energy Group
September 2026
$
1,500.0
WEC Energy Group
October 2024 (1)
200.0
WE
September 2026
500.0
WPS
September 2026
400.0
WG
September 2026
350.0
PGL
September 2026
350.0
Total short-term credit capacity
$
3,300.0
Less:
Letters of credit issued inside credit facilities
$
2.3
Commercial paper outstanding
592.4
Available capacity under existing agreements
$
2,705.3
(1)On October 18, 2024, WEC Energy Group extended the maturity to October 18, 2025.
In January and February 2024, pursuant to a tender offer, we purchased $122.1 million aggregate principal amount of the $500.0 million outstanding of our 2007 Junior Notes for $115.2 million with proceeds from issuing commercial paper. We recorded a $6.9 million gain related to the early settlement. Additionally, in May 2024, we repurchased $19.0 million aggregate principal amount of the $377.9 million outstanding of our 2007 Junior Notes for $18.7 million, plus accrued interest, with proceeds received from issuing commercial paper.
In March 2024, our $600.0 million of 0.80% Senior Notes, due March 15, 2024, matured, and outstanding principal and accrued interest were paid with proceeds received from issuing commercial paper.
Convertible Senior Notes
In the second quarter of 2024, we issued $862.5 million of 2027 Notes and $862.5 million of 2029 Notes. The 2027 Notes and 2029 Notes are senior unsecured obligations and bear interest at an annual rate of 4.375%, payable semiannually beginning on December 1, 2024. Proceeds from the offerings were used to repay short-term debt and for general corporate purposes.
The 2027 Notes will mature on June 1, 2027, and the 2029 Notes will mature on June 1, 2029, unless earlier converted or repurchased in accordance with their terms, or in the case of the 2029 Notes, redeemed by us. No sinking fund is provided for either series of the notes. Upon the occurrence of a fundamental change, as defined in the related indenture, holders may require us to repurchase for cash all or any portion of their 2027 or 2029 Notes. We may not redeem the 2027 Notes prior to their maturity date. We may redeem for cash all or part of the 2029 Notes, at our option, on or after June 1, 2027 and on or before the 41st scheduled trading day immediately preceding their maturity date, if the last reported sale price per share of our common stock has been at least 130% of the conversion price of the 2029 Notes then in effect for at least 20 trading days (whether or not consecutive) during any 30 consecutive trading day period. Any redemptions or fundamental change repurchases of the 2027 Notes or 2029 Notes will be at a price equal to 100% of the principal amount, plus accrued and unpaid interest.
Holders may convert all or any portion of their notes at their option at any time prior to the close of business on the business day immediately preceding March 1, 2027, in the case of the 2027 Notes, and March 1, 2029, in the case of the 2029 Notes, only under the following circumstances:
•During any calendar quarter commencing after the calendar quarter ending on September 30, 2024, (and only during such calendar quarter), if the last reported sale price of our common stock for at least 20 trading days (whether or not consecutive) during a period of 30 consecutive trading days ending on, and including, the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price of such series of notes on each applicable trading day;
•During the five consecutive business day period immediately after any ten consecutive trading day period (measurement period) in which the trading price per $1,000 principal amount of notes of such series for each trading day of the measurement period was less than 98% of the product of the last reported sale price of our common stock and the conversion rate of such series of notes on each such trading day;
•Upon the occurrence of specified corporate events, as defined in the related indenture;
•In the case of the 2029 Notes only, if we call any of the 2029 Notes for redemption, at any time prior to the close of business on the second scheduled trading day prior to the redemption date, but only with respect to the 2029 Notes called (or deemed called) for redemption.
Holders may convert all or any portion of their notes at any time, regardless of the foregoing circumstances, on or after March 1, 2027, in the case of the 2027 Notes, or March 1, 2029, in the case of the 2029 Notes, until the close of business on the second scheduled trading day immediately preceding the maturity date of such series of notes.
Upon conversion, we will pay cash up to the aggregate principal amount of the notes to be converted and pay or deliver cash, shares of our common stock, or a combination of cash and shares of our common stock, at our election, in respect of the remainder, if any, of our conversion obligation in excess of the aggregate principal amount of the notes being converted.
The initial conversion rate for both the 2027 Notes and 2029 Notes is 10.1243 shares of common stock per $1,000 principal amount, which is equivalent to an initial conversion price of approximately $98.77 per share of our common stock. The conversion rate is subject to adjustment upon the occurrence of certain specified events, as defined in the related indenture, but will not be adjusted for accrued and unpaid interest. In addition, upon the occurrence of a make-whole fundamental change, as defined in the related indenture, we will, in certain circumstances, increase the conversion rate by a number of additional shares of common stock for conversions in connection with the make-whole fundamental change.
As of September 30, 2024, none of the conditions allowing holders to convert their notes were met. In accordance with the guidance in ASC Subtopic 470-20, Debt – Debt with Conversion and Other Options, the 2027 Notes and 2029 Notes were accounted for in their entirety as a liability on our balance sheet. The following is a summary of our convertible debt instruments as of September 30, 2024:
(in millions)
Principal Amount
Unamortized Debt Issuance Costs
Net Carrying Amount
Fair Value Amount (1)
2027 Notes
$
862.5
$
(8.8)
$
853.7
$
936.3
2029 Notes
862.5
(9.3)
853.2
954.7
(1) The fair values are categorized in Level 2 of the fair value hierarchy. See Note 15, Fair Value Measurements, for more information on the levels of the fair value hierarchy.
The following table provides a summary of the interest expense recorded for each of the 2027 Notes and 2029 Notes:
(in millions)
Three Months Ended September 30, 2024
Nine Months Ended September 30, 2024
2027 Notes
Contractual interest expense
$
9.4
$
12.9
Amortization of debt issuance costs
0.8
1.1
Total interest expense – 2027 Notes
10.2
14.0
2029 Notes
Contractual interest expense
9.4
12.9
Amortization of debt issuance costs
0.5
0.7
Total interest expense – 2029 Notes
$
9.9
$
13.6
Potentially dilutive common shares issuable upon conversion of the 2027 Notes and 2029 Notes are determined using the if-converted method for calculating diluted earnings per share. As of September 30, 2024, there were no shares of our common stock related to the potential conversion of the 2027 Notes and 2029 Notes included in our diluted earnings per share calculation as the impact was anti-dilutive.
Wisconsin Electric Power Company
In May 2024, WE issued $350.0 million of 5.00% Debentures, due May 15, 2029, and used the net proceeds to repay short-term debt and for other general corporate purposes.
In September 2024, WE issued $300.0 million of 4.60% Debentures due October 1, 2034 and $300.0 million of 5.05% Debentures due October 1, 2054, and used the net proceeds to repay short-term debt and for other general corporate purposes.
Wisconsin Gas LLC
In October 2024, WG issued $100.0 million of 4.86% Debentures due November 1, 2029 and $100 million of 5.18% Debentures due November 1, 2034, and used the net proceeds to repay short-term debt.
Michigan Gas Utilities Corporation
In October 2024, MGU issued $10.0 million of 4.85% Senior Notes due November 1, 2029 and $15.0 million of 5.23% Senior Notes due November 1, 2034, and used the net proceeds to repay intercompany short-term debt to its parent, Integrys.
In October 2024, Bluewater issued $25.0 million of 5.41% Senior Notes due November 1, 2041, and used the net proceeds for general corporate purposes.
NOTE 12—LEASES
In June 2024, UMERC entered into an agreement to acquire and construct Renegade, a utility-scale solar-powered electric generating facility in Delta and Marquette counties, Michigan. Commercial operation of the project is targeted at the end of 2026. Related to its investment in Renegade, UMERC entered into several land leases that commenced in the second quarter of 2024.
In July 2024, WE and WPS partnered with an unaffiliated utility to acquire and construct Koshkonong, a utility-scale solar-powered electric generating facility located in Dane County, Wisconsin. Commercial operation of the project is targeted at the end of 2026. Related to their investment in Koshkonong, WE and WPS, along with their unaffiliated utility partner, entered into several land leases that commenced in the third quarter of 2024.
The land leases entered into related to the Renegade and Koshkonong generating facilities each have 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, these land leases are being amortized over the extended term of the leases. Once Renegade and Koshkonong achieve commercial operation, the lease liabilities will be remeasured to reflect the final total acres being leased. We expect to recover the lease payments through rates. Our total obligation under these land-related finance leases was $120.0 million at September 30, 2024, and was included in long-term debt on our balance sheet. Our finance lease right of use assets were $119.0 million as of September 30, 2024, and were included in property, plant, and equipment on our balance sheet. Our weighted-average discount rate for these land-related finance leases was 6.02%. We used an estimate of the fully collateralized incremental borrowing rate based upon information available for similarly rated companies in determining the present value of lease payments.
Future minimum lease payments and the corresponding present value of our net minimum lease payments under these land-related finance leases as of September 30, 2024, were as follows:
PGL and NSG price natural gas storage injections at the calendar year average of the costs of natural gas supply purchased. Withdrawals from storage are priced on the LIFO cost method. For interim periods, the difference between current projected replacement cost and the LIFO cost for quantities of natural gas temporarily withdrawn from storage is recorded as a temporary LIFO liquidation debit or credit. At September 30, 2024, all LIFO layers were replenished, and the LIFO liquidation balance was zero.
Substantially all other materials and supplies, natural gas in storage, and fossil fuel inventories are recorded using the weighted-average cost method of accounting.
NOTE 14—INCOME TAXES
The provision for income taxes differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes as a result of the following:
Three Months Ended September 30, 2024
Three Months Ended September 30, 2023
(in millions)
Amount
Effective Tax Rate
Amount
Effective Tax Rate
Statutory federal income tax
$
57.0
21.0
%
$
79.0
21.0
%
State income taxes net of federal tax benefit
16.9
6.2
%
23.2
6.2
%
PTCs, net
(33.7)
(12.4)
%
(30.2)
(8.0)
%
Federal excess deferred tax amortization
(5.8)
(2.1)
%
(8.5)
(2.3)
%
Other, net
(2.8)
(1.0)
%
(3.1)
(0.8)
%
Total income tax expense
$
31.6
11.7
%
$
60.4
16.1
%
Nine Months Ended September 30, 2024
Nine Months Ended September 30, 2023
(in millions)
Amount
Effective Tax Rate
Amount
Effective Tax Rate
Statutory federal income tax
$
259.2
21.0
%
$
272.2
21.0
%
State income taxes net of federal tax benefit
75.9
6.2
%
80.0
6.2
%
PTCs, net
(143.9)
(11.7)
%
(130.3)
(10.1)
%
Federal excess deferred tax amortization
(26.1)
(2.1)
%
(28.9)
(2.2)
%
Other, net
(4.2)
(0.3)
%
(10.0)
(0.8)
%
Total income tax expense
$
160.9
13.1
%
$
183.0
14.1
%
The effective tax rates for the three and nine months ended September 30, 2024 and 2023, differ from the United States statutory federal income tax rate of 21%, primarily due to PTCs generated from ownership interests in renewable generation facilities in our non-utility energy infrastructure and Wisconsin segments and the impact of the protected deferred tax benefits associated with the Tax Legislation, as discussed in more detail below. These items were partially offset by state income taxes.
The Tax Legislation required our regulated utilities to remeasure their deferred income taxes, and we began to amortize the resulting excess protected deferred income taxes beginning in 2018 in accordance with normalization requirements (see federal excess deferred tax amortization lines above). See Note 26, Regulatory Environment, in our 2023 Annual Report on Form 10-K for more information about the impact of the Tax Legislation.
The IRA contains a tax credit transferability provision that allows us to sell PTCs produced after December 31, 2022, to third parties. In September 2023 and May 2024, under this transferability provision, we entered into agreements to sell substantially all of the PTCs we generated in 2023 and substantially all of the PTCs expected to be generated in 2024 to third parties. We elect to account for tax credits transferred under the scope of ASC 740. We include the discount from the sale of tax credits as a component of income tax expense. We also include any expected proceeds from the sale of tax credits in the evaluation of the realizability of deferred tax assets related to PTCs. The sale of tax credits is presented in the operating activities section of the statements of cash flows consistent with the presentation of cash taxes paid.
In April 2023, the IRS issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting that taxpayers may use to determine whether expenses to repair, maintain, replace, or improve natural gas transmission and distribution property must be capitalized for tax purposes. We adopted the safe harbor method of accounting for certain of our utilities on our 2023 tax return, which increased our deferred tax liabilities. We are still evaluating how this new guidance can be adopted by our remaining utilities and plan to adopt the guidance for them on a future tax return.
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).
Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows:
Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods.
Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs.
Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.
When possible, we base the valuations of our assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. Certain derivatives, such as FTRs and TCRs, are categorized in Level 3 due to the significance of unobservable or internally-developed inputs. FTRs and TCRs are valued using auction prices from the applicable regional transmission organization.
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:
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 and TCRs, which are used at our electric utilities and certain of our non-utility wind parks to manage electric transmission congestion costs in the MISO Energy and Operating Reserves Markets and the Southwest Power Pool Integrated Marketplace, respectively.
We hold investments in the Integrys rabbi trust. These investments are used to fund participants' benefits under the Integrys deferred compensation plan and certain Integrys non-qualified pension plans. These investments are included in other long-term assets on our balance sheets. For the three months ended September 30, 2024, we recorded $2.7 million of net unrealized gains in earnings related to the investments held at the end of the period, compared with $1.7 million of net unrealized losses recorded during the same quarter in 2023. During the nine months ended September 30, 2024 and 2023, the net unrealized gains included in earnings related to the investments held at the end of the period were $7.9 million and $4.7 million, respectively.
The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy:
Three Months Ended September 30
Nine Months Ended September 30
(in millions)
2024
2023
2024
2023
Balance at the beginning of the period
$
20.8
$
16.8
$
7.2
$
7.8
Purchases
0.7
0.4
27.5
19.9
Net realized and unrealized gains (losses) included in earnings (1)
0.5
0.1
(0.5)
(0.4)
Settlements
(10.0)
(6.0)
(22.2)
(16.0)
Balance at the end of the period
$
12.0
$
11.3
$
12.0
$
11.3
Net unrealized gains included in earnings attributable to Level 3 derivatives held at the end of the reporting period (1)
$
0.2
$
0.1
$
0.1
$
0.1
(1)Amounts relate to FTRs and TCRs included in our non-utility energy infrastructure segment. These net realized and unrealized gains and losses are recorded in operating revenues on our income statements.
Fair Value of Financial Instruments
The following table shows the financial instruments included on our balance sheets that were not recorded at fair value:
September 30, 2024
December 31, 2023
(in millions)
Carrying Amount
Fair Value
Carrying Amount
Fair Value
Preferred stock of subsidiary
$
30.4
$
22.4
$
30.4
$
21.4
Long-term debt, including current portion (1)
18,445.2
17,986.4
16,631.1
15,564.3
(1)The carrying amount of long-term debt excludes finance lease obligations of $267.7 million and $145.9 million at September 30, 2024 and December 31, 2023, respectively.
The fair values of our long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy.
We use derivatives as part of our risk management program to manage the risks associated with the price volatility of interest rates, purchased power, generation, and natural gas costs for the benefit of our customers and shareholders. Our approach is non-speculative and designed to mitigate risk. Regulated hedging programs are approved by our state regulators.
We record derivative instruments on our balance sheets as an asset or liability measured at fair value unless they qualify for the normal purchases and sales exception and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities.
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 are included in the other current and other long-term line items on our balance sheets.The following table shows our derivative assets and derivative liabilities. None of the derivatives shown below were designated as hedging instruments.
September 30, 2024
December 31, 2023
(in millions)
Derivative Assets
Derivative Liabilities
Derivative Assets
Derivative Liabilities
Current
Natural gas contracts
$
17.5
$
41.3
$
10.4
$
78.1
FTRs and TCRs
12.0
—
7.2
—
Coal contracts
—
—
0.3
10.9
Total current
29.5
41.3
17.9
89.0
Long-term
Natural gas contracts
0.8
2.5
0.1
8.0
Coal contracts
—
—
—
9.4
Total long-term
0.8
2.5
0.1
17.4
Total
$
30.3
$
43.8
$
18.0
$
106.4
Realized gains and losses on derivatives used in our regulated utility operations are 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 utilities’ fuel and natural gas cost recovery mechanisms. Realized gains and losses on FTRs and TCRs used in our non-utility operations are recorded in operating revenues on the income statements. Our estimated notional sales volumes and realized gains and losses were as follows:
Three Months Ended September 30, 2024
Three Months Ended September 30, 2023
(in millions)
Volumes
Gains (Losses)
Volumes
Gains (Losses)
Natural gas contracts
38.6 Dth
$
(24.0)
37.8 Dth
$
(56.3)
FTRs and TCRs
7.9 MWh
4.0
8.1 MWh
21.9
Total
$
(20.0)
$
(34.4)
Nine Months Ended September 30, 2024
Nine Months Ended September 30, 2023
(in millions)
Volumes
Gains (Losses)
Volumes
Gains (Losses)
Natural gas contracts
154.5 Dth
$
(110.7)
144.2 Dth
$
(200.7)
FTRs and TCRs
23.1 MWh
7.6
22.9 MWh
26.4
Total
$
(103.1)
$
(174.3)
On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At September 30, 2024 and December 31, 2023, we had posted cash collateral of $52.6 million and $100.3 million, respectively. These amounts were recorded on our balance sheets in other current assets. At September 30, 2024, we had also received cash collateral of $0.5 million. This amount was recorded on our balance sheet in other current liabilities.
The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets:
September 30, 2024
December 31, 2023
(in millions)
Derivative Assets
Derivative Liabilities
Derivative Assets
Derivative Liabilities
Gross amount recognized on the balance sheet
$
30.3
$
43.8
$
18.0
$
106.4
Gross amount not offset on the balance sheet
(7.4)
(24.5)
(1)
(3.1)
(71.0)
(2)
Net amount
$
22.9
$
19.3
$
14.9
$
35.4
(1)Includes cash collateral posted of $17.1 million.
(2)Includes cash collateral posted of $67.9 million.
Cash Flow Hedges
We previously entered into forward interest rate swap agreements to mitigate the interest rate exposure associated with the issuance of long-term debt related to the acquisition of Integrys. These swap agreements were settled in 2015, and we continue to amortize amounts out of accumulated other comprehensive loss into interest expense over the periods in which the interest costs are recognized in earnings. The derivative gains related to these swap agreements reclassified from accumulated other comprehensive loss to interest expense during the three and nine months ended September 30, 2024 and 2023 were not significant. At September 30, 2024, the amount expected to be reclassified from accumulated other comprehensive loss to interest expense over the next twelve months was also not significant.
NOTE 17—GUARANTEES
The following table shows our outstanding guarantees:
Total Amounts Committed at September 30, 2024
Expiration
(in millions)
Less Than 1 Year
1 to 3 Years
Over 3 Years
Standby letters of credit (1)
$
136.3
$
19.7
$
—
$
116.6
Surety bonds (2)
34.0
33.9
0.1
—
Other guarantees (3)
11.7
—
—
11.7
Total guarantees
$
182.0
$
53.6
$
0.1
$
128.3
(1)At our request or the request of our subsidiaries, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to our subsidiaries. These amounts are not reflected on our balance sheets.
(2)Primarily for environmental remediation, workers compensation self-insurance programs, and obtaining various licenses, permits, and rights-of-way. These amounts are not reflected on our balance sheets.
(3)Related to workers compensation coverage for which a liability was recorded on our balance sheets.
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
Three Months Ended September 30
Nine Months Ended September 30
(in millions)
2024
2023
2024
2023
Service cost
$
6.1
$
6.0
$
18.2
$
18.0
Interest cost
29.2
30.5
87.5
91.7
Expected return on plan assets
(45.5)
(46.8)
(136.6)
(140.6)
Loss on plan settlement
0.7
—
0.7
—
Amortization of prior service cost (credit)
(0.1)
—
(0.1)
0.1
Amortization of net actuarial loss
14.9
8.1
44.6
24.8
Net periodic benefit cost (credit)
$
5.3
$
(2.2)
$
14.3
$
(6.0)
OPEB Benefits
Three Months Ended September 30
Nine Months Ended September 30
(in millions)
2024
2023
2024
2023
Service cost
$
2.7
$
2.4
$
8.1
$
7.3
Interest cost
5.6
5.4
17.0
16.2
Expected return on plan assets
(13.2)
(13.3)
(39.5)
(39.8)
Amortization of prior service credit
(3.3)
(3.7)
(10.1)
(11.1)
Amortization of net actuarial gain
(1.9)
(3.0)
(5.7)
(9.2)
Net periodic benefit credit
$
(10.1)
$
(12.2)
$
(30.2)
$
(36.6)
During the nine months ended September 30, 2024, we made contributions and payments of $10.0 million related to our pension plans and $1.0 million related to our OPEB plans. We expect to make contributions and payments of $3.3 million related to our pension plans and $1.1 million related to our OPEB plans during the remainder of 2024, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.
Effective January 1, 2023, the PSCW approved escrow accounting for pension and OPEB costs. As a result, as of September 30, 2024, we recorded a $20.3 million regulatory asset for pension costs and a $32.4 million regulatory asset for OPEB costs. The above tables do not reflect any adjustments for the creation of these regulatory assets.
NOTE 19—GOODWILL AND INTANGIBLES
Goodwill
Goodwill represents the excess of the cost of an acquisition over the fair value of the identifiable net assets acquired. The table below shows our goodwill balances by segment at September 30, 2024. We had no changes to the carrying amount of goodwill during the nine months ended September 30, 2024.
(in millions)
Wisconsin
Illinois
Other States
Non-Utility Energy Infrastructure
Total
Goodwill balance (1)
$
2,104.3
$
758.7
$
183.2
$
6.6
$
3,052.8
(1)We had no accumulated impairment losses related to our goodwill as of September 30, 2024.
During the third quarter of 2024, annual impairment tests were completed at all of our reporting units that carried a goodwill balance as of July 1, 2024. No impairments resulted from these tests.
At both September 30, 2024 and December 31, 2023, we had $29.3 million of indefinite-lived intangible assets, largely consisting of spectrum frequencies. The spectrum frequencies enable the utilities to transmit data and voice communications over a wavelength dedicated to us throughout our service territories. We also have $5.2 million of other indefinite-lived intangible assets, consisting of a MGU trade name from a previous acquisition. These indefinite-lived intangible assets are included in other long-term assets on our balance sheets.
Intangible Liabilities
The intangible liabilities below were all obtained through acquisitions by WECI.
September 30, 2024
December 31, 2023
(in millions)
Gross Carrying Amount
Accumulated Amortization
Net Carrying Amount
Gross Carrying Amount
Accumulated Amortization
Net Carrying Amount
PPAs (1)
$
653.9
$
(106.1)
$
547.8
$
653.9
$
(66.6)
$
587.3
Proxy revenue swap (2)
7.2
(4.0)
3.2
7.2
(3.5)
3.7
Interconnection agreements (3)
4.7
(1.1)
3.6
4.7
(0.9)
3.8
Total intangible liabilities
$
665.8
$
(111.2)
$
554.6
$
665.8
$
(71.0)
$
594.8
(1) Represents PPAs related to the acquisition of Blooming Grove, Tatanka Ridge, Jayhawk, Thunderhead Wind Energy LLC, Samson I, and Sapphire Sky expiring between 2030 and 2037. The weighted-average remaining useful life of the PPAs is 11 years.
(2) Represents an agreement with a counterparty to swap the market revenue of Upstream Wind Energy LLC's wind generation for fixed quarterly payments over 10 years, which expires in February 2029. The remaining useful life of the proxy revenue swap is four years.
(3) Represents interconnection agreements related to the acquisitions of Tatanka Ridge and Bishop Hill Energy III LLC, expiring in 2040 and 2041, respectively. These agreements relate to payments for connecting our facilities to the infrastructure of another utility to facilitate the movement of power onto the electric grid. The weighted-average remaining useful life of the interconnection agreements is 16 years.
Amortization related to these intangible liabilities for the three and nine months ended September 30, 2024, was $13.4 million and $40.2 million, respectively. Amortization for the three and nine months ended September 30, 2023, was $13.4 million and $37.2 million, respectively. Amortization for the next five years, including amounts recorded through September 30, 2024, is estimated to be:
For the Years Ending December 31
(in millions)
2024
2025
2026
2027
2028
Amortization to be recorded as an increase to operating revenues
$
53.4
$
53.4
$
53.4
$
53.4
$
53.4
Amortization to be recorded as a decrease to other operation and maintenance
We own approximately 60% of ATC, a for-profit, transmission-only company regulated by the FERC for cost of service and certain state regulatory commissions for routing and siting of transmission projects. We also own approximately 75% of ATC Holdco, a separate entity formed in December 2016 to invest in transmission-related projects outside of ATC's traditional footprint. The following tables provide a reconciliation of the changes in our investments in ATC and ATC Holdco:
Three Months Ended September 30, 2024
(in millions)
ATC
ATC Holdco
Total
Balance at beginning of period
$
2,029.7
$
26.1
$
2,055.8
Add: Earnings from equity method investment
46.1
0.6
46.7
Add: Capital contributions
15.2
—
15.2
Less: Distributions
37.0
—
37.0
Add: Other
0.1
—
0.1
Balance at end of period
$
2,054.1
$
26.7
$
2,080.8
Three Months Ended September 30, 2023
(in millions)
ATC
ATC Holdco
Total
Balance at beginning of period
$
1,931.8
$
24.1
$
1,955.9
Add: Earnings from equity method investment
44.2
0.5
44.7
Add: Capital contributions
18.2
—
18.2
Less: Distributions
35.0
—
35.0
Balance at end of period
$
1,959.2
$
24.6
$
1,983.8
Nine Months Ended September 30, 2024
(in millions)
ATC
ATC Holdco
Total
Balance at beginning of period
$
1,980.8
$
25.1
$
2,005.9
Add: Earnings from equity method investment
136.7
1.6
138.3
Add: Capital contributions
45.5
—
45.5
Less: Distributions
109.0
—
109.0
Add: Other
0.1
—
0.1
Balance at end of period
$
2,054.1
$
26.7
$
2,080.8
Nine Months Ended September 30, 2023
(in millions)
ATC
ATC Holdco
Total
Balance at beginning of period
$
1,884.6
$
24.6
$
1,909.2
Add: Earnings from equity method investment
130.2
1.9
132.1
Add: Capital contributions
51.5
—
51.5
Less: Distributions
107.1
1.9
109.0
Balance at end of period
$
1,959.2
$
24.6
$
1,983.8
We pay ATC for network transmission and other related services it provides. In addition, we provide a variety of operational, maintenance, and project management work for ATC, which is reimbursed by ATC. We are also required to initially fund the construction of transmission infrastructure upgrades needed for new generation projects. ATC owns these transmission assets and reimburses us for these costs when the new generation is placed in service.
The following table summarizes our significant related party transactions with ATC:
Three Months Ended September 30
Nine Months Ended September 30
(in millions)
2024
2023
2024
2023
Charges to ATC for services and construction
$
4.5
$
4.5
$
15.5
$
12.3
Charges from ATC for network transmission services
Our balance sheets included the following receivables and payables for services provided to or received from ATC:
(in millions)
September 30, 2024
December 31, 2023
Accounts receivable for services provided to ATC
$
2.1
$
1.6
Accounts payable for services received from ATC
50.0
49.9
Amounts due from ATC for transmission infrastructure upgrades (1)
45.8
46.1
(1)These transmission infrastructure upgrades were primarily related to the construction of WE's and WPS's renewable energy projects.
Summarized financial data for ATC is included in the tables below:
Three Months Ended September 30
Nine Months Ended September 30
(in millions)
2024
2023
2024
2023
Income statement data
Operating revenues
$
221.4
$
206.2
$
651.6
$
610.4
Operating expenses
110.1
102.8
324.1
303.4
Other expense, net
36.4
32.9
107.4
98.3
Net income
$
74.9
$
70.5
$
220.1
$
208.7
(in millions)
September 30, 2024
December 31, 2023
Balance sheet data
Current assets
$
130.0
$
115.2
Noncurrent assets
6,660.4
6,337.0
Total assets
$
6,790.4
$
6,452.2
Current liabilities
$
525.7
$
495.9
Long-term debt
2,933.9
2,736.0
Other noncurrent liabilities
573.5
585.2
Members' equity
2,757.3
2,635.1
Total liabilities and members' equity
$
6,790.4
$
6,452.2
NOTE 21—SEGMENT INFORMATION
We use net income attributed to common shareholders to measure segment profitability and to allocate resources to our businesses. At September 30, 2024, we reported six segments, which are described below.
•The Wisconsin segment includes the electric and natural gas utility operations of WE, WPS, WG, and UMERC.
•The Illinois segment includes the natural gas utility operations of PGL and NSG.
•The other states segment includes the natural gas utility operations of MERC and MGU and the non-utility operations of MERC.
•The electric transmission segment includes our approximate 60% ownership interest in ATC, a for-profit, transmission-only company regulated by the FERC for cost of service and certain state regulatory commissions for routing and siting of transmission projects, and our approximate 75% ownership interest in ATC Holdco, which was formed to invest in transmission-related projects outside of ATC's traditional footprint.
•The non-utility energy infrastructure segment includes:
◦We Power, which owns and leases generating facilities to WE,
◦Bluewater, which owns underground natural gas storage facilities in Michigan that provide approximately one-third of the current storage needs for our Wisconsin natural gas utilities, and
◦WECI, which holds majority interests in multiple renewable generating facilities.
See Note 2, Acquisitions, for more information on recent and anticipated future WECI acquisitions.
•The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, the Peoples Energy, LLC holding company, Wispark, Wisvest LLC, Wisconsin Energy Capital Corporation, and WBS.
All of our operations are located within the United States. The following tables show summarized financial information related to our reportable segments for the three and nine months ended September 30, 2024 and 2023:
Utility Operations
(in millions)
Wisconsin
Illinois
Other States
Total Utility Operations
Electric Transmission
Non-Utility Energy Infrastructure
Corporate and Other
Reconciling Eliminations
WEC Energy Group Consolidated
Three Months Ended September 30, 2024
External revenues
$
1,590.0
$
173.6
$
53.0
$
1,816.6
$
—
$
46.9
$
—
$
—
$
1,863.5
Intersegment revenues
—
—
—
—
—
116.2
—
(116.2)
—
Other operation and maintenance
403.5
126.5
22.6
552.6
—
19.1
(3.3)
(1.6)
566.8
Depreciation and amortization
232.4
63.9
12.0
308.3
—
49.2
5.6
(22.6)
340.5
Equity in earnings of transmission affiliates
—
—
—
—
46.7
—
—
—
46.7
Interest expense
160.3
22.3
4.1
186.7
4.8
23.4
79.0
(89.7)
204.2
Income tax expense (benefit)
63.3
(19.0)
(1.3)
43.0
10.2
(16.0)
(5.6)
—
31.6
Net income (loss)
238.1
(48.6)
(3.7)
185.8
31.7
83.2
(62.1)
—
238.6
Net income (loss) attributed to common shareholders
237.8
(48.6)
(3.7)
185.5
31.7
85.0
(62.1)
—
240.1
Utility Operations
(in millions)
Wisconsin
Illinois
Other States
Total Utility Operations
Electric Transmission
Non-Utility Energy Infrastructure
Corporate and Other
Reconciling Eliminations
WEC Energy Group Consolidated
Three Months Ended September 30, 2023
External revenues
$
1,622.0
$
243.3
$
47.6
$
1,912.9
$
—
$
44.5
$
—
$
—
$
1,957.4
Intersegment revenues
—
—
—
—
—
115.3
—
(115.3)
—
Other operation and maintenance
387.1
86.5
21.7
495.3
—
21.5
1.3
(1.5)
516.6
Depreciation and amortization
215.3
59.3
11.2
285.8
—
48.8
5.3
(19.6)
320.3
Equity in earnings of transmission affiliates
—
—
—
—
44.7
—
—
—
44.7
Interest expense
148.7
22.0
3.7
174.4
5.0
24.8
66.3
(88.0)
182.5
Income tax expense (benefit)
69.3
8.9
(2.0)
76.2
10.0
(6.7)
(19.1)
—
60.4
Net income (loss)
243.4
24.7
(6.0)
262.1
29.7
66.7
(42.9)
—
315.6
Net income (loss) attributed to common shareholders
Net income (loss) attributed to common shareholders
636.3
164.6
35.5
836.4
93.2
272.6
(128.5)
—
1,073.7
Utility Operations
(in millions)
Wisconsin
Illinois
Other States
Total Utility Operations
Electric Transmission
Non-Utility Energy Infrastructure
Corporate and Other
Reconciling Eliminations
WEC Energy Group Consolidated
Nine Months Ended September 30, 2023
External revenues
$
5,042.8
$
1,116.5
$
379.5
$
6,538.8
$
—
$
136.6
$
0.1
$
—
$
6,675.5
Intersegment revenues
—
—
—
—
—
358.4
—
(358.4)
—
Other operation and maintenance
1,119.7
305.5
68.2
1,493.4
—
59.6
0.6
(7.0)
1,546.6
Depreciation and amortization
632.9
176.3
32.2
841.4
—
139.9
15.6
(57.2)
939.7
Equity in earnings of transmission affiliates
—
—
—
—
132.1
—
—
—
132.1
Interest expense
449.4
65.0
12.0
526.4
14.6
69.8
183.9
(261.3)
533.4
Income tax expense (benefit)
188.8
61.8
10.5
261.1
29.4
(44.2)
(63.3)
—
183.0
Net income (loss)
686.8
167.9
30.9
885.6
88.1
240.9
(101.4)
—
1,113.2
Net income (loss) attributed to common shareholders
685.9
167.9
30.9
884.7
88.1
241.8
(101.4)
—
1,113.2
NOTE 22—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.
In November 2020, the PSCW issued a financing order approving the securitization of $100 million of undepreciated environmental control costs related to WE's retired Pleasant Prairie power plant, the carrying costs accrued on the $100 million during the securitization process, and the related financing fees. The financing order also authorized WE to form WEPCo Environmental Trust, a bankruptcy-remote special purpose entity, for the sole purpose of issuing ETBs to recover the costs approved in the financing order. WEPCo Environmental Trust is a wholly owned subsidiary of WE.
In May 2021, WEPCo Environmental Trust issued ETBs and used the proceeds to acquire environmental control property from WE. The environmental control property is recorded as a regulatory asset on our balance sheets and includes the right to impose, collect, and receive a non-bypassable environmental control charge from WE's retail electric distribution customers until the ETBs are paid in full and all financing costs have been recovered. The ETBs are secured by the environmental control property. Cash collections from the environmental control charge and funds on deposit in trust accounts are the sole sources of funds to satisfy the debt obligation. The bondholders do not have any recourse to WE or any of WE's affiliates.
WE acts as the servicer of the environmental control property on behalf of WEPCo Environmental Trust and is responsible for metering, calculating, billing, and collecting the environmental control charge. As necessary, WE is authorized to implement periodic adjustments of the environmental control charge. The adjustments are designed to ensure the timely payment of principal, interest, and other ongoing financing costs. WE remits all collections of the environmental control charge to WEPCo Environmental Trust's indenture trustee.
WEPCo Environmental Trust is a VIE primarily because its equity capitalization is insufficient to support its operations. As described above, WE has the power to direct the activities that most significantly impact WEPCo Environmental Trust's economic performance. Therefore, WE is considered the primary beneficiary of WEPCo Environmental Trust, and consolidation is required.
The following table summarizes the impact of WEPCo Environmental Trust on our balance sheets:
(in millions)
September 30, 2024
December 31, 2023
Assets
Other current assets (restricted cash)
$
3.3
$
0.8
Regulatory assets
79.1
85.9
Other long-term assets (restricted cash)
0.3
0.6
Liabilities
Current portion of long-term debt
9.1
9.0
Other current liabilities (accrued interest)
0.4
0.1
Long-term debt
80.9
85.3
Investment in Transmission Affiliates
We own approximately 60% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. We have determined that ATC is a VIE but consolidation is not required since we are not ATC's primary beneficiary. As a result of our limited voting rights, we do not have the power to direct the activities that most significantly impact ATC's economic performance. Therefore, we account for ATC as an equity method investment. At September 30, 2024 and December 31, 2023, our equity investment in ATC was $2,054.1 million and $1,980.8 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC.
We also own approximately 75% of ATC Holdco, a separate entity formed in December 2016 to invest in transmission-related projects outside of ATC's traditional footprint. We have determined that ATC Holdco is a VIE but consolidation is not required since we are not ATC Holdco's primary beneficiary. As a result of our limited voting rights, we do not have the power to direct the activities that most significantly impact ATC Holdco's economic performance. Therefore, we account for ATC Holdco as an equity method investment. At September 30, 2024 and December 31, 2023, our equity investment in ATC Holdco was $26.7 million and $25.1 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC Holdco.
See Note 20, Investment in Transmission Affiliates, for more information, including any significant assets and liabilities related to ATC and ATC Holdco recorded on our balance sheets.
NOTE 23—COMMITMENTS AND CONTINGENCIES
We and our subsidiaries have significant commitments and contingencies arising from our operations, including those related to unconditional purchase obligations, environmental matters, and enforcement and litigation matters.
Unconditional Purchase Obligations
Our electric utilities have obligations to distribute and sell electricity to their customers, and our natural gas utilities have obligations to distribute and sell natural gas to their customers. The utilities expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time.
The renewable generation facilities that are part of our non-utility energy infrastructure segment have obligations to distribute and sell electricity through long-term offtake agreements with their customers for all of the energy produced. In order to support these sales obligations, these companies enter into easements and other service agreements associated with the generating facilities.
Our minimum future commitments related to these purchase obligations as of September 30, 2024, including those of our subsidiaries, were approximately $9.8 billion.
Environmental Matters
Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as sulfur dioxide, NOx, fine particulates, mercury, and GHGs; water intake and discharges; management of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites.
Air Quality
Cross State Air Pollution Rule – Good Neighbor Rule
In March 2023, the EPA issued its final Good Neighbor Rule, which became effective in August 2023 and requires significant reductions in ozone-forming emissions of NOx from power plants and industrial facilities. After review of the final rule, we are well positioned to meet the requirements.
Our RICE units in the Upper Peninsula of Michigan and Wisconsin are not currently subject to the final rule as each unit is less than 25 MWs. To the extent we use RICE engines for natural gas distribution operations, those engines not part of an LDC are subject to the emission limits and operational requirements of the rule beginning in 2026. The EPA has exempted LDCs from the final rule.
In February 2024, the Supreme Court heard oral arguments regarding stay applications related to the EPA's Good Neighbor Rule. In June 2024, the Supreme Court granted a stay of the Good Neighbor Rule pending disposition of the applicants' petitions for review at the D.C. Circuit Court of Appeals. We will continue to monitor this case as arguments at the D.C. Circuit Court of Appeals move forward.
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. In May 2024, the EPA published a final rule in the Federal Register lowering the PM limit from 0.03 lb/MMBtu to 0.01 lb/MMBtu. After review of the final rule, we believe we are well positioned to meet its requirements.
After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, creating a more stringent standard than the 2008 NAAQS. The 2015 ozone standard lowered the 8-hour limit for ground-level ozone. In November 2022, the EPA's 2022 CASAC Ozone Review Panel issued a draft report supporting reconsideration of the 2015 standard. The EPA staff initially issued a draft Policy Assessment in March 2023 that also supported the reconsideration; however, in August 2023, the EPA announced that it was instead restarting its ozone standard evaluation. The EPA has indicated it plans to release its Integrated Review Plan in fall 2024. This new review is anticipated to take 3 to 5 years to complete.
In February 2022, revisions to the Wisconsin Administrative Code to adopt the 2015 standard were finalized. The amended regulations incorporated by reference the federal air pollution monitoring requirements related to the standard. The WDNR submitted the rule updates as a SIP revision to the EPA, which the EPA approved in February 2023.
The effective date for the initial nonattainment area designation was August 2018, and the attainment status is evaluated every 3 years thereafter until attainment is achieved. The Milwaukee, Sheboygan, and Chicago, IL-IN-WI nonattainment areas did not meet the marginal attainment deadline of August 2021, so in April 2022 the EPA proposed "moderate" nonattainment status for the 2015 standard. In October 2022, the EPA published its final reclassifications from "marginal" to "moderate" for these areas, effective November 7, 2022. Accordingly, the WDNR submitted a SIP revision to the EPA in December 2022 to address the moderate nonattainment status.
In October 2023, the EPA found that 11 states, including Wisconsin, failed to submit adequate SIP revisions to address nonattainment areas classified as "moderate" for the 2015 standard. This action triggered a May 2025 deadline for states to get their SIP approved or the EPA will issue a federal implementation plan. Additionally, offset sanctions will take effect 18 months from the May 2025 deadline if the state's SIP is not approved. The offset sanctions impact volatile organic compound and NOx emissions from new or modified sources in the nonattainment areas. The WDNR has indicated it intends to submit a SIP revision by the May 2025 deadline.
The most recent attainment evaluation date was in August 2024. The moderate attainment deadline was not met, so the EPA will propose the nonattainment areas in Wisconsin be redesignated as serious nonattainment based on 2021-2023 data. The EPA must reclassify the nonattainment areas by February 2025. We continue to evaluate the impacts the nonattainment redesignation will have on our operations.
Particulate Matter
All counties within our service territories are in attainment with current 2012 standards for fine PM2.5. Under the Biden Administration's policy review, the EPA concluded that the scientific evidence and information from a December 2020 review of the 2012 standards supported revising the level of the annual standard for the PM2.5 NAAQS to below the current level of 12 µg/m3, while retaining the 24-hour standard of 35 µg/m3. In February 2024, the EPA finalized a rule which lowered the primary (health-based) annual PM2.5 NAAQS to 9 µg/m3. The secondary (welfare-based) PM2.5 standard and 24-hour standards (both primary and secondary) remain unchanged. The EPA has until May 2026 to designate areas as attainment and nonattainment with the new standard. The WDNR will need to draft and submit a SIP for the EPA's approval. A designation of nonattainment status could impact future permitting activities for facilities in applicable locations, including the potential need for improved or new air pollution control equipment. With our planned transition from coal-fired plants to natural gas-fired plants and renewable generating facilities, we do not expect this new standard to have a material impact on our units.
Climate Change
In May 2023, the EPA proposed GHG performance standards for fossil-fired steam generating and natural gas combustion units and also proposed to repeal the Affordable Clean Energy rule, which had replaced the Clean Power Plan. The final rule, known as the Greenhouse Gas Power Plant Rule, was published in May 2024. Pursuant to the final rule, there are no applicable standards for coal plants until the end of 2031 and after 2031, the applicable standard is dependent upon the unit's retirement date. Coal-fired units that are planned to refuel to natural gas-fired units must convert to natural gas and no longer retain the capability to burn coal by the end of 2029. For new combined cycle natural gas plants above a 40% capacity factor, the rule is dependent upon the implementation of carbon capture by the end of 2031. For new simple cycle natural gas-fired combustion turbines, there are no applicable limits as long as the capacity factor is less than 20%. Our RICE units in Michigan and the new Weston RICE units are not
affected under the rule because the rule excludes RICE units that are less than 25 MWs. Numerous parties have challenged the Greenhouse Gas Power Plant Rule through litigation pending in the D.C. Circuit Court of Appeals.
In March 2024, the EPA announced it had removed regulations on existing natural gas combustion turbines from the rule. The EPA indicated that it intends to draft a new rule for existing natural gas-fired units and opened a non-regulatory docket for this new rulemaking. The EPA has stated it anticipates a proposed rule by the end of 2024.
In April 2024, the EPA issued its final Mandatory Greenhouse Gas Reporting Rule, 40 Code of Federal Regulations Part 98, which includes updates to the global warming potentials to determine CO2 equivalency for threshold reporting and the addition of a new section regarding energy consumption. The revisions will impact the reporting required for our electric generation facilities, LDCs, and underground natural gas storage facilities. In May 2024, the EPA also issued its final rule to amend reporting requirements for petroleum and natural gas systems. Under the final rule, new leak emission factors and reporting requirements for large release events will impact the reporting required for our LDCs and underground natural gas storage facilities.
Our ESG Progress Plan includes the retirement of older, fossil-fueled generation, to be replaced with zero-carbon-emitting renewables and clean natural gas-fueled generation. We have already retired nearly 2,500 MWs of fossil-fueled generation since the beginning of 2018, which includes the retirement of OCPP Units 5 and 6 in May 2024, the 2019 retirement of the Presque Isle power plant, and the 2018 retirements of the Pleasant Prairie power plant, the Pulliam power plant, and the jointly-owned Edgewater 4 generating unit. We expect to retire approximately 1,200 MWs of additional fossil-fueled generation by the end of 2031, which includes the planned retirements of OCPP Units 7 and 8, the planned retirement of the jointly-owned Columbia Units 1 and 2, and the planned retirement of Weston Unit 3. See Note 7, Property, Plant, and Equipment, for more information related to planned power plant retirements. In May 2021, we announced goals to achieve reductions in carbon emissions from our electric generation fleet by 60% by the end of 2025 and by 80% by the end of 2030, both from a 2005 baseline. We expect to achieve these goals by continuing to make operating refinements, retiring less efficient generating units, and executing our capital plan. Over the longer term, the target for our generation fleet is to be net carbon neutral by 2050.
We also continue to reduce methane emissions by improving our natural gas distribution systems, and have set a target across our natural gas distribution operations to achieve net-zero methane emissions by the end of 2030. We plan to achieve our net-zero goal through an effort that includes continuous operational improvements and equipment upgrades, as well as the use of RNG throughout our natural gas utility distribution systems. In addition, subject to regulatory approval, we may procure RTCs.
Water Quality
Clean Water Act Cooling Water Intake Structure Rule
Section 316(b) of the CWA became effective in October 2014 and requires the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the BTA for minimizing adverse environmental impacts. The rule applies to all of our existing generating facilities with cooling water intake structures, except for the ERGS units, which were permitted and received a final BTA determination under the rules governing new facilities.
Effective in June 2020, the requirements of federal Section 316(b) of the CWA were incorporated into the Wisconsin Administrative Code. The WDNR applies this rule when establishing BTA requirements for cooling water intake structures at existing facilities. These BTA requirements are incorporated into WPDES permits for WE and WPS facilities.
We have received final or interim BTA determinations for all generation facilities where Section 316(b) is applicable. The most recent BTA determination was for Weston Units 3 and 4. The WDNR reissued the Weston WPDES permit in June 2024 (effective July 1, 2024) that includes a determination that existing technology (wet cooling towers) installed at the units represents BTA for minimizing adverse environmental impacts in accordance with the requirements in the CWA. With respect to OCPP Units 7 and 8, we believe the WDNR will reach the same BTA determination decision when the WPDES permit for those units is reissued, which is expected in 2025.
Steam Electric Effluent Limitation Guidelines
The EPA's 2015 final ELG rule, which took effect in January 2016 (2015 ELG rule), was modified in 2020 (2020 ELG rule), and again in 2024 with the May 2024 publication of the Supplemental ELG Rule. These rules establish federal technology-based requirements for several types of power plant wastewaters. The three requirements that affect WE and WPS facilities relate to discharge limits for
BATW, FGD wastewater, and CRL (landfill leachate). Although our coal-fueled facilities were constructed with advanced wastewater treatment technologies that meet many of the discharge limits established by the 2015 rule, facility modifications were still necessary at OCPP, ERGS, and Weston to meet all of the 2015 ELG requirements and the additional ones established by the 2020 ELG rule. Through 2023, compliance costs associated with the 2015 and 2020 ELG rules required $105 million in capital investment.
The 2024 Supplemental ELG rule established zero discharge requirements for BATW, FGD, and CRL wastewaters at coal-fueled units with no planned retirement date. The Supplemental ELG Rule also kept one existing and created one new “permanent cessation of coal” subcategory. Those electing to cease coal combustion by either retiring or repowering a unit by December 31, 2028 or December 31, 2034 can limit ELG-related capital investments to what was required by either the 2015 or the 2020 ELG Rule, respectively. For units where cessation of coal is planned to occur no later than December 31, 2034, facility owners must complete all 2020 ELG rule required capital investments by December 31, 2025. All WE and WPS coal-fueled units fully meet the 2020 ELG rule requirements. Based on current electrical generation resource planning, we plan to file a Notice of Planned Participation by December 31, 2025 to opt into the "cessation of coal by December 31, 2034" subcategory for both the ERGS and Weston coal-fueled facilities.
The final Supplemental ELG Rule allows owners of coal-fueled units who opted into a cessation of coal subcategory to operate beyond the end of 2028 or 2034, required by either the 2015 or the 2020 ELG Rule, respectively, if needed for reliability concerns (i.e., energy emergencies, reliability must run agreements, etc.) as determined by the United States Department of Energy, a public utility commission, or independent system operator.
We are still evaluating the Supplemental ELG Rule CRL provisions to determine the applicability and potential compliance costs for inactive/closed landfills. Numerous parties have challenged the rule through litigation pending in the U.S. Court of Appeals for the 8th Circuit.
Land Quality
Manufactured Gas Plant Remediation
We have identified sites at which our utilities or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. Our natural gas utilities are responsible for the environmental remediation of these sites, some of which are in the EPA Superfund Alternative Approach Program. We are also working with various state jurisdictions in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure.
In addition, we are coordinating the investigation and cleanup of some of these sites subject to the jurisdiction of the EPA under what is called a "multisite" program. This program involves prioritizing the work to be done at the sites, preparation and approval of documents common to all of the sites, and use of a consistent approach in selecting remedies. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below.
The future costs for detailed site investigation, future remediation, and monitoring are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation. Historically, our regulators have allowed us to recover incurred costs, net of insurance recoveries and recoveries from potentially responsible parties, associated with the remediation of manufactured gas plant sites. Accordingly, we have established regulatory assets for costs associated with these sites.
We have established the following regulatory assets and reserves for manufactured gas plant sites:
(in millions)
September 30, 2024
December 31, 2023
Regulatory assets
$
565.8
$
596.8
Reserves for future environmental remediation
430.5
463.7
Coal Combustion Residuals Rule
The EPA finalized a rule for CCR in April 2024 that would apply to landfills, historic fill sites, and projects where CCR was placed at a power plant site. The rule will regulate previously exempt closed landfills.
We expect the final rule, which will become effective in November 2024, to have an impact on some of our coal ash landfills, requiring additional remediation that is not currently required under the state programs. The rule is being challenged through litigation pending in the D.C. Circuit Court of Appeals. We expect the cost of the additional remediation would be recovered through future rates. See Note 8, Asset Retirement Obligations, for more information on the estimated cost of the additional remediation.
Enforcement and Litigation Matters
We and our subsidiaries are involved in legal and administrative proceedings before various courts and agencies with respect to matters arising in the ordinary course of business. Although we are unable to predict the outcome of these matters, management believes that appropriate reserves have been established and that final settlement of these actions will not have a material impact on our financial condition or results of operations.
Consent Decrees
Wisconsin Public Service Corporation – Weston and Pulliam Power Plants
In November 2009, the EPA issued an NOV to WPS, which alleged violations of the CAA's New Source Review requirements relating to certain projects completed at the Weston and Pulliam power plants from 1994 to 2009. WPS entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Eastern District of Wisconsin in March 2013. With the retirement of Pulliam Units 7 and 8 in October 2018, WPS completed the mitigation projects required by the Consent Decree and received a completeness letter from the EPA in October 2018. We continue to work with the EPA on a closeout process for the Consent Decree.
Joint Ownership Power Plants – Columbia and Edgewater
In December 2009, the EPA issued an NOV to WPL, the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including MG&E, WE (former co-owner of an Edgewater unit), and WPS. The NOV alleged violations of the CAA's New Source Review requirements related to certain projects completed at those plants. WPS, along with WPL, MG&E, and WE, entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Western District of Wisconsin in June 2013. As a result of the continued implementation of the Consent Decree related to the jointly owned Columbia and Edgewater plants, the Edgewater 4 generating unit was retired in September 2018. WPL started the process to close out this Consent Decree.
NOTE 24—SUPPLEMENTAL CASH FLOW INFORMATION
Non-Cash Transactions
Nine Months Ended September 30
(in millions)
2024
2023
Cash paid for interest, net of amount capitalized
$
533.1
$
432.9
Cash paid (received) for income taxes, net (1)
(214.6)
15.8
Significant non-cash investing and financing transactions:
Accounts payable related to construction costs
163.4
236.5
Common stock issued for stock-based compensation plans
6.4
—
Increase in receivables related to insurance proceeds
5.3
6.2
(1) Cash received for income taxes in 2024 includes $217.1 million related to 2023 and 2024 PTCs that were sold to third parties.
The statements of cash flows include our activity related to cash, cash equivalents, and restricted cash. The following table reconciles the cash, cash equivalents, and restricted cash amounts reported within the balance sheets to the total of these amounts shown on the statements of cash flows:
(in millions)
September 30, 2024
December 31, 2023
Cash and cash equivalents
$
322.5
$
42.9
Restricted cash included in other current assets
11.2
70.1
Restricted cash included in other long-term assets
27.3
52.2
Cash, cash equivalents, and restricted cash
$
361.0
$
165.2
Our restricted cash consisted of the following:
•Cash held in the Integrys rabbi trust, which is used to fund participants' benefits under the Integrys deferred compensation plan and certain Integrys non-qualified pension plans.
•Cash on deposit in financial institutions that is restricted to satisfy the requirements of certain debt agreements at WEC Infrastructure Wind Holding I LLC, WEC Infrastructure Wind Holding II LLC, and WEPCo Environmental Trust.
•Cash related to WECI's ownership interests in certain renewable generation projects. These projects are required to deposit into an escrow account annually in order to fund future decommissioning.
NOTE 25—REGULATORY ENVIRONMENT
Wisconsin Electric Power Company, Wisconsin Public Service Corporation, and Wisconsin Gas LLC
2025 and 2026 Rate Case
On April 12, 2024, WE, WPS, and WG filed requests with the PSCW to increase their retail electric, natural gas, and steam rates, as applicable, effective January 1, 2025 and January 1, 2026. The requests reflected the following:
WE
WPS
WG
Proposed 2025 rate increase
Electric
$
240.7
million
/
6.9%
$
110.1
million
/
8.5%
N/A
Gas
$
57.5
million
/
10.0%
$
26.8
million
/
6.8%
$
67.7
million
/
8.2%
Steam
$
2.5
million
/
8.4%
N/A
N/A
Proposed 2026 rate increase (1)
Electric
$
177.9
million
/
4.6%
$
64.3
million
/
4.5%
N/A
Gas
$
31.0
million
/
4.6%
$
16.1
million
/
3.7%
$
30.6
million
/
3.3%
Proposed ROE
10.0%
10.0%
10.0%
Proposed common equity component average on a financial basis
53.5%
53.5%
53.5%
(1) The proposed 2026 rate increases are incremental to the currently authorized revenue plus the requested rate increases for 2025.
The primary drivers of the requested increases in electric rates are continued capital investments to transition our generation fleets from coal to renewables and natural gas-fueled generation, increased costs driven by higher inflation and interest rates, and the recovery of regulatory assets previously approved by the PSCW.
The requested increases in natural gas rates are driven by the companies' ongoing capital investments in reliability and safety projects, including LNG storage facilities, as well as the impacts from higher inflation and increased interest rates.
The utilities also proposed retaining their current earnings sharing mechanism. Under the current earnings sharing mechanism, if the utility earns above its authorized ROE: (i) the utility retains 100.0% of earnings for the first 15 basis points above the authorized ROE; (ii) 50.0% of the next 60 basis points is required to be refunded to ratepayers; and (iii) 100.0% of any remaining excess earnings is required to be refunded to ratepayers.
A decision is expected in the fourth quarter of 2024, with any rate adjustments expected to be effective January 1, 2025 and 2026.
The Peoples Gas Light and Coke Company and North Shore Gas Company
2023 Rate Order
In January 2023, PGL and NSG filed requests with the ICC to increase their natural gas base rates. The requested rate increases were primarily driven by capital investments made to strengthen the safety and reliability of each utility’s natural gas distribution system. PGL was also seeking to recover costs incurred to upgrade its natural gas storage field and operations facilities and to continue improving customer service. PGL did not request an extension of the QIP rider as PGL returned to the traditional rate making process to recover the costs of necessary infrastructure improvements.
On November 16, 2023, the ICC issued final written orders approving base rate increases for PGL and NSG. The written orders were subsequently amended for various technical corrections. The amended written orders approved the following base rate increases:
•A $304.6 million (43.5%) base rate increase for PGL’s natural gas customers. This amount includes the recovery of costs related to PGL’s SMP that were previously being recovered under its QIP rider. PGL's new rates were effective December 1, 2023.
•An $11.0 million (11.6%) base rate increase for NSG’s natural gas customers. The new rates at NSG were not effective until February 1, 2024 as changes were required to NSG's billing system as a result of the final rate order.
The ICC approved an authorized ROE of 9.38% for both PGL and NSG, and set the common equity component average at 50.79% and 52.58% for PGL and NSG, respectively.
As part of its decisions, the ICC, among other things, disallowed $236.2 million of capital costs related to the construction and improvement of PGL’s shops and facilities and $1.7 million of capital costs related to NSG's construction of a gas infrastructure project. In addition, the ICC ordered PGL to pause spending on its SMP until the ICC has a proceeding to determine the optimal method for replacing aging natural gas infrastructure and a prudent investment level. In accordance with the written order, the ICC initiated the proceeding on January 31, 2024.
In December 2023, PGL and NSG filed an application for rehearing with the ICC requesting reconsideration of various issues in the ICC's November 16, 2023 written orders. The ICC granted PGL and NSG a limited-scope rehearing focused exclusively on the authorized spending for the completion of SMP projects that started in 2023 and emergency repairs needed to ensure the safety and reliability of PGL's delivery system. On May 30, 2024, the ICC issued a written order on the rehearing. The order approved $28.5 million of additional spending for emergency work, representing a $1.6 million increase to PGL's annual revenue requirement.
As the ICC did not grant a rehearing on the disallowance of PGL's and NSG's capital costs, we recorded a $178.9 million non-cash impairment of our property, plant, and equipment during the fourth quarter of 2023. This amount included $177.2 million of previously incurred disallowed costs at PGL related to its shops and facilities, and the $1.7 million of capital costs disallowed at NSG. The remaining disallowance of capital costs at PGL related to expected future spend.
On June 7, 2024, PGL and NSG filed a petition with the Illinois Appellate Court for review of the November 16, 2023 and May 30, 2024 orders.
Uncollectible Expense Adjustment Rider
The rates of PGL and NSG include a UEA rider for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. The UEA rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency by the ICC. In May 2023, the ICC issued a written order on PGL's and NSG's 2018 UEA rider reconciliation. The order required a $15.4 million and $0.7 million refund to ratepayers at PGL and NSG, respectively. These amounts were refunded over a period of nine months, which began on September 1, 2023. In June 2023, the ICC denied PGL's and NSG's application requesting a rehearing of the ICC's May 2023 order. In July 2023, PGL and NSG petitioned the Illinois Appellate Court for review of the ICC orders. Their appeal is still pending.
As of September 30, 2024, there can be no assurance that all costs incurred under the UEA rider during the open reconciliation years, which include 2019 through 2023, will be deemed recoverable by the ICC. The combined annual costs of PGL and NSG included in the rider, which reflect uncollectible write-offs in excess of what is recovered in base rates, have ranged from $10 million to $40 million during these open reconciliation years. Disallowances by the ICC, if any, could be material and have a material adverse impact on our results of operations.
Qualifying Infrastructure Plant Rider
In July 2013, Illinois Public Act 98-0057, The Natural Gas Consumer, Safety & Reliability Act, became law. This law provides natural gas utilities with a cost recovery mechanism that allows collection, through a surcharge on customer bills, of prudently incurred costs to upgrade Illinois natural gas infrastructure. In January 2014, the ICC approved a QIP rider for PGL, which was in effect until December 1, 2023. As discussed above, PGL has returned to the traditional rate-making process for recovery of these costs, and they are now included in PGL's base rates.
Costs previously incurred under PGL's QIP rider are still subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. On August 14, 2024, the ICC issued a final order on PGL's 2016 annual reconciliation, which included a disallowance of $14.8 million of certain capital costs. PGL recorded a pre-tax charge to income of $25.3 million during the third quarter of 2024 related to the disallowance and the previously recognized return on these investments. The charge was recorded on the income statement as a $12.9 million reduction in revenues for the amounts previously collected from customers, a $12.1 million increase to operation and maintenance expense for the impairment of PGL's property, plant, and equipment, and a $0.3 million increase to interest expense related to the amounts due to customers. On October 25, 2024, PGL filed a petition with the Illinois Appellate Court for review of the ICC's August 14, 2024 order.
In March 2024, PGL filed its 2023 reconciliation with the ICC, which, along with the reconciliations from 2017 through 2022, is still pending. The aggregate capital costs included in the rider during the open reconciliation years, which include 2017 through 2023, are approximately $2,058 million. As of September 30, 2024, there can be no assurance that all of these costs, along with any previously recognized return on these investments, will be deemed recoverable by the ICC. Further disallowances by the ICC, if any, could be material and have a material adverse impact on our results of operations.
Minnesota Energy Resources Corporation
2023 Rate Order
In November 2022, MERC initiated a rate proceeding with the MPUC to increase its retail natural gas base rates. In December 2022, the MPUC approved MERC's request for interim rates totaling $37.0 million, subject to refund. The interim rates went into effect on January 1, 2023.
In November 2023, the MPUC issued a written order approving a settlement agreement MERC reached with certain intervenors. The settlement agreement reflects a natural gas base rate increase of $28.8 million (7.1%), along with a 9.65% ROE and a common equity component average of 53.0%. The natural gas rate increase was primarily driven by increased capital investments as well as inflationary pressure on operating costs. Under the terms of the settlement agreement, MERC will continue the use of its decoupling mechanism for residential customers, and it will be expanded to include certain small commercial and industrial customers. Final rates went into effect on March 1, 2024.
MERC’s customers were entitled to an $8.9 million refund due to the interim rate increase exceeding the final approved rate increase. These amounts were refunded to customers during the second quarter of 2024.
Michigan Gas Utilities Corporation
2024 Rate Order
In March 2024, MGU filed a request with the MPSC to increase its retail natural gas base rates. On September 26, 2024, the MPSC issued a final order approving a settlement agreement, which authorizes MGU to increase its natural gas base rates by $7.0 million (3.88%). The rate increase reflects a 9.86% ROE and a common equity component average of 50.0%. The rate increase is primarily driven by inflationary pressure on capital projects and operating and maintenance costs and the significant increase in interest rates
over the past few years. The order also authorizes MGU to defer any expenses incurred to implement the Pipeline and Hazardous Materials Safety Administration's proposed rulemaking titled "Gas Pipeline Leak Detection and Repair."
The new rates will be effective January 1, 2025.
Upper Michigan Energy Resources Corporation
2024 Rate Order
In May 2024, UMERC filed a request with the MPSC to increase its electric base rates for non-mine customers. On October 10, 2024, the MPSC issued a final order approving a settlement agreement, which authorizes UMERC to increase electric base rates for non-mine customers by $6.6 million (8.2%). The rate increase reflects a 9.86% ROE and a common equity component average of 50.0%. The rate increase is primarily driven by the construction of the now in-service RICE generation facilities located in the Upper Peninsula of Michigan and a reduction in sales volumes resulting from the implementation of limited retail choice since UMERC’s predecessor utilities last reset rates. A reduction of operation and maintenance costs partially offset these impacts.
The new rates will be effective January 1, 2025.
NOTE 26—NEW ACCOUNTING PRONOUNCEMENTS
Improvements to Income Tax Disclosures
In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The amendments require additional disclosures, primarily related to income taxes paid and the rate reconciliation table. The amendments require disclosures on specific categories in the rate reconciliation table, as well as additional information for reconciling items that meet a quantitative threshold. For income taxes paid, additional disclosures are required to disaggregate federal, state, and foreign income taxes paid, with additional disclosures for income taxes paid that meet a quantitative threshold. The amendments are effective for annual periods beginning after December 15, 2024, with early adoption permitted. We plan to adopt these amendments beginning with our fiscal year ending on December 31, 2025, and are currently evaluating the impact this guidance may have on our financial statements and related disclosures.
Improvements to Reportable Segment Disclosures
In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures. The amendments require additional disclosures about reportable segments on an annual and interim basis. The amendments require disclosure of significant segment expenses that are (1) regularly provided to the chief operating decision maker and (2) included in the reported measure of segment profit or loss. The amendments also require disclosure of an amount for other segment items and a description of its composition. The new standard also allows companies to disclose multiple measures of segment profit or loss if those measures are used to assess performance and allocate resources. The amendments are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted. We plan to adopt these amendments beginning with our fiscal year ending on December 31, 2024, and are currently evaluating the impact this guidance may have on our financial statements and related disclosures.
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 2023 Annual Report on Form 10-K.
Introduction
We are a diversified holding company with natural gas and electric utility operations (serving customers in Wisconsin, Illinois, Michigan, and Minnesota), an approximately 60% equity ownership interest in ATC (a for-profit electric transmission company regulated by FERC and certain state regulatory commissions), and non-utility energy infrastructure operations through We Power (which owns generation assets in Wisconsin that it leases to WE), Bluewater (which owns underground natural gas storage facilities in Michigan), and WECI, which holds ownership interests in several renewable generating facilities.
Corporate Strategy
Our goal is to continue to build and sustain long-term value for our shareholders and customers by focusing on the fundamentals of our business: environmental stewardship; reliability; operating efficiency; financial discipline; exceptional customer care; and safety. Our capital investment plan for efficiency, sustainability and growth, referred to as our ESG Progress Plan, provides a roadmap for us to achieve this goal. It is an aggressive plan to cut emissions, maintain superior reliability, deliver significant savings for customers, and grow our investment in the future of energy.
Throughout our strategic planning process, we take into account important developments, risks and opportunities, including new technologies, customer preferences and affordability, energy resiliency efforts, and sustainability.
Creating a Sustainable Future
Our 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. The retirements will contribute to meeting our goals to reduce CO2 emissions from our electric generation. When taken together, the retirements and new investments in renewables and clean natural gas generation should better balance our supply with our demand, while maintaining reliable, affordable energy for our customers.
We have announced goals to achieve reductions in carbon emissions from our electric generation fleet by 60% by the end of 2025 and by 80% by the end of 2030, both from a 2005 baseline. We expect to achieve these goals by continuing to make operating refinements, retiring less efficient generating units, and executing our capital plan. Over the longer term, the target for our generation fleet is to be net carbon neutral by 2050.
As part of our path toward these goals, we have started implementing co-firing with natural gas at the ERGS coal-fired units and plan to co-fire with natural gas at Weston Unit 4. By the end of 2030, we expect to use coal as a backup fuel only, and we believe we will be in a position to eliminate coal as an energy source by the end of 2032.
We have already retired nearly 2,500 MWs of fossil-fueled generation since the beginning of 2018, which includes the retirement of OCPP Units 5 and 6 in May 2024, the 2019 retirement of the Presque Isle power plant, and the 2018 retirements of the Pleasant Prairie power plant, the Pulliam power plant, and the jointly-owned Edgewater 4 generating unit. We expect to retire approximately 1,200 MWs of additional fossil-fueled generation by the end of 2031, which includes the planned retirement of OCPP Units 7 and 8, the planned retirement of the jointly-owned Columbia Units 1 and 2, and the planned retirement of Weston Unit 3. For more information on the retirement of OCPP Units 5 and 6, see Note 6, Regulatory Assets and Liabilities. See Note 7, Property, Plant, and Equipment, for more information related to planned power plant retirements.
In addition to retiring these older, fossil-fueled plants, we expect to invest approximately $9.1 billion from 2025-2029 in regulated renewable energy in Wisconsin. Our 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:
We also plan on investing in a combination of natural gas-fired generation, to be owned by WE, including:
•1,100 MWs of combustion turbines to be constructed at our OCPP site (we plan on constructing a new natural gas lateral pipeline to support this generation); with
•An additional 675 MWs of combustion turbines planned; and
•128 MWs of RICE natural gas-fueled generation to be constructed in Kenosha County; with
•An additional 114 MWs of RICE natural gas-fueled generation planned.
In May 2024, WE completed the acquisition of an additional 100 MWs of capacity in West Riverside, a combined cycle natural gas plant operated by an unaffiliated utility. See Note 2, Acquisitions, for more information.
For more details on the projects discussed above, see Liquidity and Capital Resources – Cash Requirements – Significant Capital Projects.
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 MWs of solar generation to WE's portfolio, allowing non-profit and governmental entities, as well as commercial and industrial customers, to site utility owned solar arrays on their property. Under this program, WE has energized 28 Solar Now projects and currently has another two under construction, together totaling more than 30 MWs. The second program, the DRER pilot, is designed to allow large commercial and industrial customers to access renewable resources that WE would operate. The DRER pilot is intended to help these larger customers meet their sustainability and renewable energy goals, and could add up to 35 MWs of renewables to WE's portfolio. In July 2023, the PSCW approved the Renewable Pathway Pilot, the third renewable energy program. This program allows WE and WPS commercial and industrial customers to subscribe to a portion of a utility-scale, Wisconsin-based renewable energy generating facility for up to 125 MWs at WE and 40 MWs at WPS. Under this program, WE has signed up five customers for a total of 44 MWs of generation capacity.
In August 2021, the PSCW approved pilot programs for WE and WPS 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, we pledged to expand the EV charging network within the service territories of our electric utilities. In doing so, we joined a coalition of utility companies in a unified effort to make EV charging convenient and widely available throughout the Midwest. The coalition we joined is planning to help build and grow EV charging corridors, enabling the general public to safely and efficiently charge their vehicles.
We also continue to reduce methane emissions by improving our natural gas distribution system. We set a target across our natural gas distribution operations to achieve net-zero methane emissions by the end of 2030. We plan to achieve our net-zero goal through an effort that includes continuous operational improvements and equipment upgrades, as well as the use of RNG throughout our natural gas utility systems. In 2022, we received approval from the PSCW for our RNG pilots and in 2023, we began transporting the output of local dairy farms onto our natural gas distribution systems in Wisconsin. The RNG supplied will directly replace higher-emission methane from natural gas that would have entered our pipes. We currently have contracts in place for 1.9 Bcf of RNG. In addition, subject to regulatory approval, we may procure RTCs.
In December 2023, we started a pilot program with Electric Power Research Institute and CMBlu Energy, a Germany-based designer and manufacturer of an organic solid flow battery, to test this new form of long-duration energy storage on the U.S. electric grid at our Valley power plant. 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 use today. We expect the pilot activities to continue into 2025.
Reliability
We have made significant reliability-related investments in recent years, and in accordance with our 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.
Below are a few examples of reliability projects that are proposed, currently underway, or recently completed.
•WE and WG have completed the construction of their respective LNG facilities. Each facility provides approximately one Bcf of natural gas supply to meet anticipated peak demand, without requiring the construction of additional interstate pipeline capacity. The WE LNG facility was commercially operational in November 2023 and the WG LNG facility was commercially operational in February 2024.
•In April 2024, WE filed a request with the PSCW to construct an LNG facility with a storage capacity of two Bcf, which would be located on the OCPP site. In addition, the construction of additional LNG facilities in Wisconsin has been proposed as part of the 2025-2029 capital plan and would provide another approximately four Bcf of natural gas supply. The LNG facilities are expected to reduce the likelihood of constraints on our natural gas distribution system during the highest demand days of winter.
•Through the SMP, PGL had been working to replace old iron pipes and facilities in Chicago’s natural gas delivery system with modern polyethylene pipes to reinforce the long-term safety and reliability of the system. In November 2023, the ICC ordered PGL to pause spending on the SMP until the ICC completes a proceeding to determine the optimal method for replacing aging natural gas infrastructure and a prudent investment level. The ICC initiated the proceeding on January 31, 2024, and the proceeding is expected to last 12 months. For more information, see Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Future Illinois Proceedings.
On January 3, 2024, the ICC granted PGL a limited-scope rehearing, which was limited to the authorized spending for the completion of SMP projects that started in 2023 and the authorized spending for emergency repairs needed to ensure the safety and reliability of PGL's delivery system. On May 30, 2024, the ICC issued a written order on the rehearing. The order approved $28.5 million of additional spending for emergency work, representing a $1.6 million increase to PGL's annual revenue requirement. See Note 25, Regulatory Environment, for more information.
•Our utilities continue to upgrade their electric and natural gas distribution systems to enhance reliability and system hardening.
We expect to spend approximately $4.5 billion from 2025 to 2029 on reliability related projects with continued investment over the next decade. 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 our utilities and our customers. This program reduces the manual effort for disconnects and reconnects and enhances outage management capabilities.
We continue to focus on integrating the resources of all our businesses and finding the best and most efficient processes.
Financial Discipline
A strong adherence to financial discipline is essential to meeting our earnings projections and maintaining a strong balance sheet, stable cash flows, a growing dividend, 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, equipment, and entire business units, that are no longer strategic to operations, are not performing as intended, or have an unacceptable risk profile.
Our planned investment focus from 2025 to 2029 is in our regulated utilities and our investment in ATC. We expect total capital expenditures for our regulated utility businesses to be approximately $24.4 billion from 2025 to 2029. In addition, we currently forecast that our share of ATC's projected capital expenditures over the next five years will be approximately $3.2 billion. Over the same period, we expect to invest approximately $0.4 billion in our non-utility energy infrastructure business on the acquisition of Hardin III. Specific projects included in the $28.0 billion ESG Progress Plan are discussed in more detail below under Liquidity and Capital Resources – Cash Requirements – Significant Capital Projects. Also, see Note 2, Acquisitions, for information on the acquisition of Hardin III and other recent and pending transactions.
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 our companies. We have moved all utilities 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 our 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.
RESULTS OF OPERATIONS
THREE MONTHS ENDED SEPTEMBER 30, 2024
Consolidated Earnings
The following table compares our consolidated results for the third quarter of 2024 with the third quarter of 2023, including favorable or better, "B", and unfavorable or worse, "W", variances:
Three Months Ended September 30
(in millions, except per share data)
2024
2023
B (W)
Wisconsin
$
237.8
$
243.1
$
(5.3)
Illinois
(48.6)
24.7
(73.3)
Other states
(3.7)
(6.0)
2.3
Electric transmission
31.7
29.7
2.0
Non-utility energy infrastructure
85.0
67.4
17.6
Corporate and other
(62.1)
(42.9)
(19.2)
Net income attributed to common shareholders
$
240.1
$
316.0
$
(75.9)
Diluted earnings per share
$
0.76
$
1.00
$
(0.24)
Earnings decreased $75.9 million during the third quarter of 2024, compared with the same quarter in 2023. The significant factors impacting the $75.9 million decrease in earnings were:
•A $73.3 million decrease in earnings at the Illinois segment, driven by lower margins related to the impacts of the PGL and NSG rate orders issued by the ICC, effective December 1, 2023 and February 1, 2024, respectively. SMP costs that were previously being recovered under PGL's QIP rider are now included in PGL's base rates. As base revenues are lower during the third quarter when natural gas usage is lower, this rate design change drove a decrease in third quarter 2024 earnings. See Note 25, Regulatory Environment, for more information on the rate orders. Higher operating expenses and a $25.3 million pre-tax charge to income related to the ICC's disallowance of certain capital costs in PGL's 2016 rider QIP reconciliation also contributed to the lower
earnings. See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Regulatory Recovery and Note 25, Regulatory Environment, for more information on the ICC disallowance.
•A $19.2 million increase in the net loss attributed to common shareholders at the corporate and other segment, driven by a negative impact from an increase in an interim income tax expense recorded to adjust consolidated income tax expense to the projected, annualized consolidated effective income tax rate. Higher interest expense also contributed to the increase in the net loss.
•A $5.3 million decrease in net income attributed to common shareholders at the Wisconsin segment, driven by higher depreciation and amortization expense and an increase in interest expense on both short-term and long-term debt. These decreases in earnings were partially offset by an increase in margins due to higher retail sales volumes and lower income tax expense due to an increase in PTCs.
These decreases in earnings were partially offset by a $17.6 million increase in net income attributed to common shareholders at the non-utility energy infrastructure segment, driven by an increase in PTCs from our non-utility renewable generating facilities and a positive impact from We Power due to continued capital investment.
Non-GAAP Financial Measures
The discussions below address the contribution of each of our utility segments to net income attributed to common shareholders. The discussions include financial information prepared in accordance with GAAP, as well as utility margin, which is not a measure of financial performance under GAAP. Utility margin (operating revenues less fuel and purchased power costs and cost of natural gas sold) is a non-GAAP financial measure because it excludes certain operation and maintenance expenses applicable to revenues, as well as depreciation and amortization and property and revenue taxes.
We believe that utility margin provides 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 utility margin internally when assessing the operating performance of our utility segments as these measures exclude the majority of revenue fluctuations caused by changes in these expenses. Similarly, the presentation of utility margin herein is intended to provide supplemental information for investors regarding our operating performance.
Our utility margin may not be comparable to similar measures presented by other companies. Furthermore, this measure is not intended to replace gross margin as determined in accordance with GAAP as an indicator of operating performance. Each of our three utility segment discussions below include a table that provides the calculation of both gross margin as determined in accordance with GAAP and utility margin, as well as a reconciliation between the two measures.
Wisconsin Segment Contribution to Net Income Attributed to Common Shareholders
The Wisconsin segment's contribution to net income attributed to common shareholders was $237.8 million during the third quarter of 2024, representing a $5.3 million, or 2.2%, decrease over the same quarter in 2023. The decrease was driven by higher depreciation and amortization expense and an increase in interest expense on both short-term and long-term debt. These decreases in earnings were partially offset by an increase in margins due to higher retail sales volumes and lower income tax expense due to an increase in PTCs.
Three Months Ended September 30
(in millions)
2024
2023
B (W)
Operating revenues
$
1,590.0
$
1,622.0
$
(32.0)
Operating expenses
Cost of sales (1)
495.3
549.1
53.8
Other operation and maintenance
403.5
387.1
(16.4)
Depreciation and amortization
232.4
215.3
(17.1)
Property and revenue taxes
32.8
44.4
11.6
Operating income
426.0
426.1
(0.1)
Other income, net
35.7
35.3
0.4
Interest expense
160.3
148.7
(11.6)
Income before income taxes
301.4
312.7
(11.3)
Income tax expense
63.3
69.3
6.0
Preferred stock dividends of subsidiary
0.3
0.3
—
Net income attributed to common shareholders
$
237.8
$
243.1
$
(5.3)
(1) Cost of sales includes fuel and purchased power and cost of natural gas sold.
The following table shows a breakdown of other operation and maintenance:
Three Months Ended September 30
(in millions)
2024
2023
B (W)
Operation and maintenance not included in line items below
$
183.6
$
167.7
$
(15.9)
Transmission (1)
135.8
135.3
(0.5)
Regulatory amortizations and other pass through expenses (2)
52.5
49.2
(3.3)
We Power (3)
32.5
35.8
3.3
Earnings sharing mechanisms
(0.9)
(0.9)
—
Total other operation and maintenance
$
403.5
$
387.1
$
(16.4)
(1)Represents transmission expense that our electric utilities are authorized to collect in rates. The PSCW has approved escrow accounting for ATC and MISO network transmission expenses for WE and WPS. As a result, WE and WPS defer as a regulatory asset or liability, the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During the third quarter of 2024 and 2023, $147.5 million and $136.4 million, respectively, of costs were billed to our electric utilities by transmission providers.
(2)Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on net income.
(3)Represents costs associated with the We Power generation units, including operating and maintenance costs recognized by WE. During the third quarter of 2024 and 2023, $27.8 million and $26.7 million, respectively, of costs were billed to or incurred by WE 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.
The following table summarizes our Wisconsin segment gross margin (GAAP) and reconciles gross margin (GAAP) to utility margin (non-GAAP). See Non-GAAP Financial Measures above for additional information regarding gross margin (GAAP) and utility margin (non-GAAP).
Three Months Ended September 30
(in millions)
2024
2023
B (W)
Electric revenues
$
1,425.1
$
1,460.8
$
(35.7)
Natural gas revenues
164.9
161.2
3.7
Operating revenues
1,590.0
1,622.0
(32.0)
Operating expenses
Fuel and purchased power
(433.9)
(487.6)
53.7
Cost of natural gas sold
(61.4)
(61.5)
0.1
Other operation and maintenance (1)
(283.0)
(286.5)
3.5
Depreciation and amortization
(232.4)
(215.3)
(17.1)
Property and revenue taxes
(32.8)
(44.4)
11.6
Gross margin (GAAP)
546.5
526.7
19.8
Other operation and maintenance (1)
283.0
286.5
(3.5)
Depreciation and amortization
232.4
215.3
17.1
Property and revenue taxes
32.8
44.4
(11.6)
Utility margin (non-GAAP)
$
1,094.7
$
1,072.9
$
21.8
(1) Operating and maintenance expenses deemed to be directly attributable to our revenue-producing activities include plant operating and maintenance expenses related to our generating units; costs associated with the We Power generating units; and transmission, distribution and customer service expenses. These expenses are included in the above table to calculate gross margin as defined under GAAP.
Gross margin (GAAP) at the Wisconsin segment increased $19.8 million during the third quarter of 2024, compared with the same quarter in 2023, and utility margin (non-GAAP) increased $21.8 million during the third quarter of 2024, compared with the same quarter in 2023. Both measures were driven by:
•A $12.4 million increase in margins related to higher electric and natural gas retail sales volumes, including the impact of warmer summer weather in WPS's service area during the third quarter of 2024, compared with the same quarter in 2023. As measured by cooling degree days, the third quarter of 2024 was 15.6% warmer than the same quarter in 2023 in the Green Bay area.
•A $4.7 million quarter-over-quarter positive impact from collections of fuel and purchased power costs. Under the Wisconsin fuel rules, the margins of our electric utilities 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 above or below the 2% is generally deferred for either future recovery from or refund to customers.
•A $2.2 million increase in margins driven by the impact of the Wisconsin limited rate case re-openers approved by the PSCW, effective January 1, 2024. See Note 26, Regulatory Environment, in our 2023 Annual Report on Form 10-K, for more information on the 2024 limited rate case re-openers.
Additionally, the smaller increase in gross margin (GAAP) as compared with the increase in utility margin (non-GAAP), was driven by the following items that are further described in Other Operating Expenses below:
•A $17.1 million increase in depreciation and amortization expense;
This increase was partially offset by:
•An $11.6 million decrease in property and revenue taxes; and
•A $3.3 million decrease in other operation and maintenance expense related to the We Power leases.
Other Operating Expenses (includes other operation and maintenance, depreciation and amortization, and property and revenue taxes)
Other operating expenses at the Wisconsin segment increased $21.9 million during the third quarter of 2024, compared with the same quarter in 2023. The significant factors impacting the increase in other operating expenses were:
•A $17.1 million increase in depreciation and amortization expense, driven by assets being placed into service as we continue to execute on our capital plan.
•An $11.3 million increase in benefit costs, primarily driven by higher stock-based compensation and deferred compensation expense.
•A $4.0 million increase in expenses associated with legal claims.
•A $3.3 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:
•An $11.6 million decrease in property and revenue taxes driven by a favorable adjustment related to a sales tax audit at WE.
•A $3.3 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.
Interest Expense
Interest expense at the Wisconsin segment increased $11.6 million during the third quarter of 2024, compared with the same quarter in 2023, driven by the impact of WE's $350.0 million long-term debt issuance in May 2024 and $600.0 million long-term debt issuance in September 2024. See Note 11, Long-Term Debt, for more information. Also contributing to the increase was higher average short-term debt balances and increased average short-term debt interest rates.
Income Tax Expense
Income tax expense at the Wisconsin segment decreased $6.0 million during the third quarter of 2024, compared with the same quarter in 2023, driven by an increase in PTCs and lower pre-tax income.
Illinois Segment Contribution to Net Income Attributed to Common Shareholders
The Illinois segment's net loss attributed to common shareholders was $48.6 million during the third quarter of 2024, representing a $73.3 million decrease in earnings over the same quarter in 2023. The lower earnings were driven by a decrease in margins related to the impacts of the PGL and NSG rate orders issued by the ICC, effective December 1, 2023 and February 1, 2024, respectively. SMP costs that were previously being recovered under PGL's QIP rider are now included in PGL's base rates. As base revenues are lower during the third quarter when natural gas usage is lower, this rate design change drove a decrease in third quarter 2024 earnings. See Note 25, Regulatory Environment, for more information on the rate orders. Higher operating expenses and a $25.3 million pre-tax charge to income related to the ICC's disallowance of certain capital costs in PGL's 2016 rider QIP reconciliation also contributed to the lower earnings. See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Regulatory Recovery and Note 25, Regulatory Environment, for more information on the ICC disallowance.
Since the majority of PGL and NSG customers use natural gas for heating, net income attributed to common shareholders at the Illinois segment is sensitive to weather and is generally higher during the winter months.
Three Months Ended September 30
(in millions)
2024
2023
B (W)
Operating revenues
$
173.6
$
243.3
$
(69.7)
Operating expenses
Cost of natural gas sold
17.8
36.7
18.9
Other operation and maintenance
126.5
86.5
(40.0)
Depreciation and amortization
63.9
59.3
(4.6)
Property and revenue taxes
12.2
6.7
(5.5)
Operating income (loss)
(46.8)
54.1
(100.9)
Other income, net
1.5
1.5
—
Interest expense
22.3
22.0
(0.3)
Income (loss) before income taxes
(67.6)
33.6
(101.2)
Income tax expense (benefit)
(19.0)
8.9
27.9
Net income (loss) attributed to common shareholders
$
(48.6)
$
24.7
$
(73.3)
The following table shows a breakdown of other operation and maintenance:
Three Months Ended September 30
(in millions)
2024
2023
B (W)
Operation and maintenance not included in the line items below
$
87.7
$
72.8
$
(14.9)
Riders (1)
26.2
13.7
(12.5)
Regulatory amortizations (1)
0.5
—
(0.5)
Impairment related to ICC disallowance (2)
12.1
—
(12.1)
Total other operation and maintenance
$
126.5
$
86.5
$
(40.0)
(1)These riders and regulatory amortizations are substantially offset in margins and therefore do not have a significant impact on net income.
(2)See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Regulatory Recovery and Note 25, Regulatory Environment, for more information on the ICC disallowance.
The following tables provide information on delivered sales volumes by customer class and weather statistics:
Three Months Ended September 30
Therms (in millions)
Natural Gas Sales Volumes
2024
2023
B (W)
Customer Class
Residential
42.9
47.4
(4.5)
Commercial and industrial
21.5
21.6
(0.1)
Total retail
64.4
69.0
(4.6)
Transportation
83.0
90.0
(7.0)
Total sales in therms
147.4
159.0
(11.6)
Three Months Ended September 30
Degree Days
Weather (1)
2024
2023
B (W)
Heating (58 Normal)
14
19
(26.3)
%
(1)Normal heating degree days are based on a 12-year moving average of monthly temperatures from Chicago's O'Hare Airport.
The following table summarizes our Illinois segment gross margin (GAAP) and reconciles gross margin (GAAP) to utility margin (non-GAAP). See Non-GAAP Financial Measures above for additional information regarding gross margin (GAAP) and utility margin (non-GAAP).
Three Months Ended September 30
(in millions)
2024
2023
B (W)
Operating revenues
$
173.6
$
243.3
$
(69.7)
Operating expenses
Cost of natural gas sold
(17.8)
(36.7)
18.9
Other operation and maintenance (1)
(59.0)
(53.1)
(5.9)
Depreciation and amortization
(63.9)
(59.3)
(4.6)
Property and revenue taxes
(12.2)
(6.7)
(5.5)
Gross margin (GAAP)
20.7
87.5
(66.8)
Other operation and maintenance (1)
59.0
53.1
5.9
Depreciation and amortization
63.9
59.3
4.6
Property and revenue taxes
12.2
6.7
5.5
Utility margin (non-GAAP)
$
155.8
$
206.6
$
(50.8)
(1) Operating and maintenance expenses deemed to be directly attributable to our revenue-producing activities include distribution and customer service expenses. These expenses are included in the above table to calculate gross margin as defined under GAAP.
Gross margin (GAAP) at the Illinois segment decreased $66.8 million during the third quarter of 2024, compared with the same quarter in 2023, and utility margin (non-GAAP) decreased $50.8 million during the third quarter of 2024, compared with the same quarter in 2023. Both measures were driven by:
•A $47.6 million decrease in margins related to the impacts of the PGL and NSG rate orders issued by the ICC, effective December 1, 2023 and February 1, 2024, respectively. PGL’s rate order includes the recovery of costs related to PGL’s SMP in base rates. Previously, these costs were being recovered under its QIP rider. As base revenues are lower during the third quarter when natural gas usage is lower, this rate design change drove a decrease in third quarter 2024 margins. See Note 25, Regulatory Environment, for more information on the rate orders.
•A $12.9 million decrease in revenues driven by an ICC order received in August 2024 related to PGL's 2016 Rider QIP reconciliation prudency review, which requires refunds to ratepayers for amounts previously collected related to the disallowance of certain capital costs. See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Regulatory Recovery and Note 25, Regulatory Environment, for more information on the ICC disallowance.
These decreases in gross margin (GAAP) and utility margin (non-GAAP) were partially offset by a $12.5 million increase in revenues associated with certain riders that are offset in other operation and maintenance and therefore do not have a significant impact on net income.
Additionally, the larger decrease in gross margin (GAAP) as compared to the decrease in utility margin (non-GAAP), was driven by the following items that are further described in Other Operating Expenses below:
•A $5.5 million increase in property and revenue taxes;
•A $4.6 million increase in depreciation and amortization;
•A $3.1 million increase in natural gas distribution and maintenance costs; and
•A $3.0 million increase in customer service expense.
Other Operating Expenses (includes other operation and maintenance, depreciation and amortization, and property and revenue taxes)
Other operating expenses at the Illinois segment increased $37.6 million, net of the $12.5 million impact of the riders referenced in the table above, during the third quarter of 2024, compared with the same quarter in 2023. The significant factors impacting the increase in other operating expenses were:
•A $12.1 million impairment driven by an ICC order received in August 2024 related to the 2016 annual prudency review of PGL's 2016 Rider QIP, which included a disallowance of certain capital costs. See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Regulatory Recovery and Note 25, Regulatory Environment, for more information on the ICC disallowance.
•A $5.5 million increase in property and revenue taxes, driven by an increase in the invested capital tax. This increase was related to an increase in regulatory amortizations as approved in the PGL and NSG rate orders issued by the ICC, effective December 1, 2023 and February 1, 2024, respectively.
•A $4.9 million increase in benefit costs, partially driven by higher costs related to stock-based compensation and deferred compensation.
•A $4.6 million increase in depreciation and amortization expense, driven by assets being placed into service as we continue to execute on our capital plan.
•A $3.1 million increase in natural gas distribution and maintenance costs, primarily related to maintaining the natural gas infrastructure.
•A $3.0 million increase in customer service expense primarily due to higher metering costs.
Interest Expense
Interest expense at the Illinois segment increased $0.3 million during the third quarter of 2024, compared with the same quarter in 2023, due primarily to the impact of PGL and NSG issuing long-term debt in November 2023. This increase was partially offset by lower average short-term debt balances.
Income Tax Expense (Benefit)
At the Illinois segment, $19.0 million of income tax benefit was recorded during the third quarter of 2024, compared with $8.9 million of income tax expense recorded during the same quarter in 2023. This change was driven by the recognition of a pre-tax loss in the third quarter of 2024, compared to pre-tax earnings in the third quarter of 2023.
Other States Segment Contribution to Net Income Attributed to Common Shareholders
The other states segment's net loss attributed to common shareholders was $3.7 million during the third quarter of 2024, representing a $2.3 million, or 38.3%, reduction in net loss over the same quarter in 2023. The reduction in net loss was driven by lower property and revenue taxes and an increase in margins related to higher sales volumes.
Since the majority of MERC and MGU customers use natural gas for heating, net income attributed to common shareholders at the other states segment is sensitive to weather and is generally higher during the winter months.
Three Months Ended September 30
(in millions)
2024
2023
B (W)
Operating revenues
$
53.0
$
47.6
$
5.4
Operating expenses
Cost of natural gas sold
16.9
13.1
(3.8)
Other operation and maintenance
22.6
21.7
(0.9)
Depreciation and amortization
12.0
11.2
(0.8)
Property and revenue taxes
2.6
6.3
3.7
Operating loss
(1.1)
(4.7)
3.6
Other income, net
0.2
0.4
(0.2)
Interest expense
4.1
3.7
(0.4)
Loss before income taxes
(5.0)
(8.0)
3.0
Income tax benefit
(1.3)
(2.0)
(0.7)
Net loss attributed to common shareholders
$
(3.7)
$
(6.0)
$
2.3
The following table shows a breakdown of other operation and maintenance:
Three Months Ended September 30
(in millions)
2024
2023
B (W)
Operation and maintenance not included in line item below
$
20.1
$
18.6
$
(1.5)
Regulatory amortizations and other pass through expenses (1)
2.5
3.1
0.6
Total other operation and maintenance
$
22.6
$
21.7
$
(0.9)
(1)Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on net income.
The following tables provide information on delivered sales volumes by customer class and weather statistics:
Three Months Ended September 30
Therms (in millions)
Natural Gas Sales Volumes
2024
2023
B (W)
Customer Class
Residential
16.0
15.2
0.8
Commercial and industrial
12.1
11.6
0.5
Total retail
28.1
26.8
1.3
Transportation
187.6
189.4
(1.8)
Total sales in therms
215.7
216.2
(0.5)
Three Months Ended September 30
Degree Days
Weather (1)
2024
2023
B (W)
MERC
Heating (198 Normal)
88
123
(28.5)
%
MGU
Heating (109 Normal)
48
93
(48.4)
%
(1)Normal heating degree days for MERC and MGU are based on a 20-year moving average and 15-year moving average, respectively, of monthly temperatures from various weather stations throughout their respective service territories.
The following table summarizes our other states segment gross margin (GAAP) and reconciles gross margin (GAAP) to utility margin (non-GAAP). See Non-GAAP Financial Measures above for additional information regarding gross margin (GAAP) and utility margin (non-GAAP).
Three Months Ended September 30
(in millions)
2024
2023
B (W)
Operating revenues
$
53.0
$
47.6
$
5.4
Operating expenses
Cost of natural gas sold
(16.9)
(13.1)
(3.8)
Other operation and maintenance (1)
(14.5)
(14.3)
(0.2)
Depreciation and amortization
(12.0)
(11.2)
(0.8)
Property and revenue taxes
(2.6)
(6.3)
3.7
Gross margin (GAAP)
7.0
2.7
4.3
Other operation and maintenance (1)
14.5
14.3
0.2
Depreciation and amortization
12.0
11.2
0.8
Property and revenue taxes
2.6
6.3
(3.7)
Utility margin (non-GAAP)
$
36.1
$
34.5
$
1.6
(1) Operating and maintenance expenses deemed to be directly attributable to our revenue-producing activities include distribution and customer service expenses. These expenses are included in the above table to calculate gross margin as defined under GAAP.
Gross margin (GAAP) increased $4.3 million during the third quarter of 2024, compared with the same quarter in 2023, and utility margin (non-GAAP) increased $1.6 million during the third quarter of 2024, compared with the same quarter in 2023. Both measures were driven by:
•A $3.1 million increase related to higher sales volumes, driven by higher retail sales.
•A $0.6 million increase related to MGU's rate increase approved by the MPSC that was effective January 1, 2024. See Note 26, Regulatory Environment, in our 2023 Annual Report on Form 10-K for more information.
Partially offsetting these increases in margins was a $1.8 million decrease related to the timing of MERC's interim rates and final rates, which were approved by the MPUC in November 2023. See Note 25, Regulatory Environment, for more information.
Additionally, the larger increase in gross margin (GAAP) as compared to the increase in utility margin (non-GAAP), was driven by the following items that are further described in Other Operating Expenses below:
•A $3.7 million decrease in property and revenue taxes; partially offset by
•A $0.8 million increase in depreciation and amortization expense.
Other Operating Expenses (includes other operation and maintenance, depreciation and amortization, and property and revenue taxes)
Other operating expenses at the other states segment decreased $2.0 million during the third quarter of 2024, compared with the same quarter in 2023. The significant factor impacting the decrease in operating expenses was a $3.7 million decrease in property and revenue taxes, driven by the resolution of a use tax audit at MGU. This decrease in other operating expenses was partially offset by:
•A $0.8 million increase in benefit costs, partially driven by higher costs related to stock-based compensation and deferred compensation.
•A $0.8 million increase in depreciation and amortization related to continued capital investment.
Interest expense at the other states segment increased $0.4 million during the third quarter of 2024, compared with the same quarter in 2023, driven by higher average short-term debt balances.
Income Tax Benefit
The income tax benefit at the other states segment decreased $0.7 million during the third quarter of 2024, compared with the same quarter in 2023, driven by lower pre-tax loss.
Electric Transmission Segment Contribution to Net Income Attributed to Common Shareholders
Three Months Ended September 30
(in millions)
2024
2023
B (W)
Equity in earnings of transmission affiliates
$
46.7
$
44.7
$
2.0
Interest expense
4.8
5.0
0.2
Income before income taxes
41.9
39.7
2.2
Income tax expense
10.2
10.0
(0.2)
Net income attributed to common shareholders
$
31.7
$
29.7
$
2.0
Equity in Earnings of Transmission Affiliates
Equity in earnings of transmission affiliates increased $2.0 million during the third quarter of 2024, compared with the same quarter in 2023. This increase was primarily due to continued capital investment by ATC.
Non-Utility Energy Infrastructure Segment Contribution to Net Income Attributed to Common Shareholders
Three Months Ended September 30
(in millions)
2024
2023
B (W)
Operating income
$
90.4
$
84.8
$
5.6
Other income, net
0.2
—
0.2
Interest expense
23.4
24.8
1.4
Income before income taxes
67.2
60.0
7.2
Income tax benefit
(16.0)
(6.7)
9.3
Net loss attributed to noncontrolling interests
1.8
0.7
1.1
Net income attributed to common shareholders
$
85.0
$
67.4
$
17.6
Operating Income
Operating income at the non-utility energy infrastructure segment increased $5.6 million during the third quarter of 2024, compared with the same quarter in 2023, which was primarily due to a $3.6 million positive impact from We Power due to continued capital investment.
In addition, WECI had a positive impact of $1.8 million driven by these items:
•A $9.2 million positive impact in 2024 related to the receipt of performance payments.
•A $1.8 million increase in PPA revenue resulting from increased generation driven by higher wind speeds.
These increases in operating income were partially offset by:
•A $5.3 million decrease in revenue related to transmission congestion that reduced energy market prices.
•A $3.3 million increase in operation and maintenance expenses due primarily to equipment failures at several of our renewable generation facilities.
•Recognition of $1.9 million in revenue related to Blooming Grove in 2023 for a capacity payment received from PJM Interconnection that was associated with a December 2022 cold weather event. The capacity payment was subject to a FERC complaint, so we recognized this as revenue in 2023 when FERC issued an order denying that complaint.
Interest Expense
Interest expense at the non-utility energy infrastructure segment decreased $1.4 million during the third quarter of 2024, compared with the same quarter in 2023, primarily due to a lower principal balance, as a result of the semi-annual principal payments on long-term debt.
Income Tax Benefit
The income tax benefit at the non-utility energy infrastructure segment increased $9.3 million during the third quarter of 2024, compared with the same quarter in 2023, due to an increase in PTCs that was related to the IRS approved PTC rate increase and higher production volumes, partially offset by higher pre-tax income.
Corporate and Other Segment Contribution to Net Income Attributed to Common Shareholders
Three Months Ended September 30
(in millions)
2024
2023
B (W)
Operating loss
$
(2.4)
$
(6.6)
$
4.2
Other income, net
13.7
10.9
2.8
Interest expense
79.0
66.3
(12.7)
Loss before income taxes
(67.7)
(62.0)
(5.7)
Income tax benefit
(5.6)
(19.1)
(13.5)
Net loss attributed to common shareholders
$
(62.1)
$
(42.9)
$
(19.2)
Operating Loss
The operating loss at the corporate and other segment decreased $4.2 million during the third quarter of 2024, compared with the same quarter in 2023. The lower operating loss was driven by a $4.2 million positive impact from WBS's allocation of its net credits from the non-service components of its net periodic pension and OPEB costs. These net credits are initially recorded in other income, net, but are allocated to our operating segments as an overhead cost, which is recorded through operating expenses. As a result, this positive impact is fully offset in the other income, net line item discussed below.
Other Income, Net
Other income, net at the corporate and other segment increased $2.8 million during the third quarter of 2024, compared with the same quarter in 2023. The significant factors impacting the increase in other income, net were:
•A $4.1 million increase due to $3.2 million of net gains from the investments held in the Integrys rabbi trust during the third quarter of 2024, compared with a $0.9 million net loss during the same quarter in 2023. The gains and losses from the investments held in the rabbi trust partially offset the changes in benefit costs related to deferred compensation, which are primarily included in other operation and maintenance expense in our utility segments. See Note 15, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust.
•A $1.9 million increase in interest income on cash balances.
These increases in other income, net were partially offset by a $4.2 million decrease driven by lower net credits from the non-service components of WBS's net periodic pension and OPEB costs. As discussed above, this negative impact was offset by lower operating
expenses as these credits are allocated to our operating segments as an overhead cost. See Note 18, Employee Benefits, for more information on our benefit costs.
Interest Expense
Interest expense at the corporate and other segment increased $12.7 million during the third quarter of 2024, compared with the same quarter in 2023, due to the impact of long-term debt issuances by WEC Energy Group in September 2023 and May 2024. Partially offsetting these increases in interest expense were lower average short-term debt balances, the impact of Integrys' long-term debt redemption in August 2023, WEC Energy Group's long-term debt maturity in September 2023, WEC Energy Group's tender offer for its 2007 Junior Notes in January and February 2024, and WEC Energy Group's repurchase of $19.0 million of its 2007 Junior Notes in May 2024. See Note 11, Long-Term Debt, for more information.
Income Tax Benefit
The income tax benefit at the corporate and other segment decreased $13.5 million during the third quarter of 2024, compared with the same quarter in 2023. This decrease was driven by a $16.9 million increase in the interim tax expense recorded to adjust consolidated income tax expense to the projected, annualized consolidated effective income tax rate during the third quarter of 2024, compared with the same quarter in 2023, partially offset by a higher pre-tax loss.
NINE MONTHS ENDED SEPTEMBER 30, 2024
Consolidated Earnings
The following table compares our consolidated results for the nine months ended September 30, 2024 with the nine months ended September 30, 2023, including favorable or better, "B", and unfavorable or worse, "W", variances:
Nine Months Ended September 30
(in millions, except per share data)
2024
2023
B (W)
Wisconsin
$
636.3
$
685.9
$
(49.6)
Illinois
164.6
167.9
(3.3)
Other states
35.5
30.9
4.6
Electric transmission
93.2
88.1
5.1
Non-utility energy infrastructure
272.6
241.8
30.8
Corporate and other
(128.5)
(101.4)
(27.1)
Net income attributed to common shareholders
$
1,073.7
$
1,113.2
$
(39.5)
Diluted Earnings Per Share
$
3.40
$
3.52
$
(0.12)
Earnings decreased $39.5 million during the nine months ended September 30, 2024, compared with the same period in 2023. The significant factors impacting the $39.5 million decrease in earnings were:
•A $49.6 million decrease in net income attributed to common shareholders at the Wisconsin segment, driven by higher operating expenses; an increase in interest expense on both short-term and long-term debt; and a decrease in margins due to lower sales volumes, driven by the impact of unfavorable weather. An increase in depreciation and amortization expense, lower gains on the sale of land, and higher distribution expenses all contributed to the increase in operating expenses. These decreases in earnings were partially offset by a positive period-over-period impact from collections of fuel and purchased power costs and the impact of the Wisconsin rate case re-openers approved by the PSCW, effective January 1, 2024. See Note 26, Regulatory Environment, in our 2023 Annual Report on Form 10-K for more information.
•A $27.1 million increase in the net loss attributed to common shareholders at the corporate and other segment, driven by higher interest expense and a negative impact from an increase in an interim income tax expense recorded to adjust consolidated income tax expense to the projected, annualized consolidated effective income tax rate. These negative impacts were partially offset by higher interest income and an increase in earnings from our equity method investments in technology and energy-focused investment funds.
These decreases in earnings were partially offset by a $30.8 million increase in net income attributed to common shareholders at the non-utility energy infrastructure segment, driven by an increase in PTCs from our non-utility renewable generating facilities in 2024, a positive impact from We Power due to continued capital investment, and higher operating income at WECI.
Expected 2024 Annual Effective Tax Rate
We expect our 2024 annual effective tax rate to be between 12.5% and 13.5%. 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
The discussions below address the contribution of each of our utility segments to net income attributed to common shareholders. The discussions include financial information prepared in accordance with GAAP, as well as utility margin, which is not a measure of financial performance under GAAP. Utility margin (operating revenues less fuel and purchased power costs and cost of natural gas sold) is a non-GAAP financial measure because it excludes certain operation and maintenance expenses applicable to revenues, as well as depreciation and amortization and property and revenue taxes.
We believe that utility margin provides 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 utility margin internally when assessing the operating performance of our utility segments as these measures exclude the majority of revenue fluctuations caused by changes in these expenses. Similarly, the presentation of utility margin herein is intended to provide supplemental information for investors regarding our operating performance.
Our utility margin may not be comparable to similar measures presented by other companies. Furthermore, this measure is not intended to replace gross margin as determined in accordance with GAAP as an indicator of operating performance. Each of our three utility segment discussions below include a table that provides the calculation of both gross margin as determined in accordance with GAAP and utility margin, as well as a reconciliation between the two measures.
Wisconsin Segment Contribution to Net Income Attributed to Common Shareholders
The Wisconsin segment's contribution to net income attributed to common shareholders was $636.3 million during the nine months ended September 30, 2024, representing a $49.6 million, or 7.2%, decrease over the same period in 2023. The decrease in earnings was driven by higher operating expenses; an increase in interest expense on both short-term and long-term debt; and a decrease in margins due to lower sales volumes, driven by the impact of unfavorable weather. An increase in depreciation and amortization expense, lower gains on the sale of land, and higher distribution expenses all contributed to the increase in operating expenses. These decreases in earnings were partially offset by a positive period-over-period impact from collections of fuel and purchased power costs and the impact of the Wisconsin rate case re-openers approved by the PSCW, effective January 1, 2024. See Note 26, Regulatory Environment, in our 2023 Annual Report on Form 10-K for more information.
Nine Months Ended September 30
(in millions)
2024
2023
B (W)
Operating revenues
$
4,737.0
$
5,042.8
$
(305.8)
Operating expenses
Cost of sales (1)
1,560.3
1,935.3
375.0
Other operation and maintenance
1,182.6
1,119.7
(62.9)
Depreciation and amortization
685.3
632.9
(52.4)
Property and revenue taxes
125.0
134.7
9.7
Operating income
1,183.8
1,220.2
(36.4)
Other income, net
101.4
104.8
(3.4)
Interest expense
475.4
449.4
(26.0)
Income before income taxes
809.8
875.6
(65.8)
Income tax expense
172.6
188.8
16.2
Preferred stock dividends of subsidiary
0.9
0.9
—
Net income attributed to common shareholders
$
636.3
$
685.9
$
(49.6)
(1) Cost of sales includes fuel and purchased power and cost of natural gas sold.
The following table shows a breakdown of other operation and maintenance:
Nine Months Ended September 30
(in millions)
2024
2023
B (W)
Operation and maintenance not included in line items below
$
518.5
$
457.0
$
(61.5)
Transmission (1)
407.3
405.0
(2.3)
Regulatory amortizations and other pass through expenses (2)
160.2
153.5
(6.7)
We Power (3)
99.2
106.8
7.6
Earnings sharing mechanisms
(2.6)
(2.6)
—
Total other operation and maintenance
$
1,182.6
$
1,119.7
$
(62.9)
(1)Represents transmission expense that our electric utilities are authorized to collect in rates. The PSCW has approved escrow accounting for ATC and MISO network transmission expenses for WE and WPS. As a result, WE and WPS defer as a regulatory asset or liability, the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During the nine months ended September 30, 2024 and 2023, $425.4 million and $391.5 million, respectively, of costs were billed to our electric utilities by transmission providers.
(2)Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on net income.
(3)Represents costs associated with the We Power generation units, including operating and maintenance costs recognized by WE. During the nine months ended September 30, 2024 and 2023, $86.7 million and $89.1 million, respectively, of costs were billed to or incurred by WE 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.
The following table summarizes our Wisconsin segment gross margin (GAAP) and reconciles gross margin (GAAP) to utility margin (non-GAAP). See Non-GAAP Financial Measures above for additional information regarding gross margin (GAAP) and utility margin (non-GAAP).
Nine Months Ended September 30
(in millions)
2024
2023
B (W)
Electric revenues
$
3,766.7
$
3,851.7
$
(85.0)
Natural gas revenues
970.3
1,191.1
(220.8)
Operating revenues
4,737.0
5,042.8
(305.8)
Operating expenses
Fuel and purchased power
(1,115.4)
(1,258.0)
142.6
Cost of natural gas sold
(444.9)
(677.3)
232.4
Other operation and maintenance (1)
(850.8)
(842.3)
(8.5)
Depreciation and amortization
(685.3)
(632.9)
(52.4)
Property and revenue taxes
(125.0)
(134.7)
9.7
Gross margin (GAAP)
1,515.6
1,497.6
18.0
Other operation and maintenance (1)
850.8
842.3
8.5
Depreciation and amortization
685.3
632.9
52.4
Property and revenue taxes
125.0
134.7
(9.7)
Utility margin (non-GAAP)
$
3,176.7
$
3,107.5
$
69.2
(1) Operating and maintenance expenses deemed to be directly attributable to our revenue-producing activities include plant operating and maintenance expenses related to our generating units; costs associated with the We Power generating units; and transmission, distribution and customer service expenses. These expenses are included in the above table to calculate gross margin as defined under GAAP.
Gross margin (GAAP) at the Wisconsin segment increased $18.0 million during the nine months ended September 30, 2024, compared with the same period in 2023, and utility margin (non-GAAP) increased $69.2 million during the nine months ended September 30, 2024, compared with the same period in 2023. Both measures were driven by:
•A $37.3 million period-over-period positive impact from collections of fuel and purchased power costs. Under the Wisconsin fuel rules, the margins of our electric utilities 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 above or below the 2% is generally deferred for either future recovery from or refund to customers.
•A $33.4 million increase in margins related to the impact of the Wisconsin limited rate case re-openers approved by the PSCW, effective January 1, 2024.
These increases in margins were partially offset by a $7.4 million decrease in margins related to lower sales volumes, driven by the impact of unfavorable weather during the nine months ended September 30, 2024, compared with the same period in 2023. As measured by heating degree days, the nine months ended September 30, 2024 were 7.3% and 11.2% warmer than the same period in 2023 in the Milwaukee area and Green Bay area, respectively. As measured by cooling degree days, the nine months ended September 30, 2024 were 3.8% warmer than the same period in 2023 in the Milwaukee area.
Additionally, the smaller increase in gross margin (GAAP) as compared with the increase in utility margin (non-GAAP), was driven by the following items that are further described in Other Operating Expenses below:
•A $52.4 million increase in depreciation and amortization expense; and
•A $15.6 million increase in electric and natural gas distribution expenses.
These increases were partially offset by:
•A $9.7 million decrease in property and revenue taxes; and
•A $7.6 million decrease in other operation and maintenance expense related to the We Power leases.
Other Operating Expenses (includes other operation and maintenance, depreciation and amortization, and property and revenue taxes)
Other operating expenses at the Wisconsin segment increased $105.6 million during the nine months ended September 30, 2024, compared with the same period in 2023. The significant factors impacting the increase in other operating expenses were:
•A $52.4 million increase in depreciation and amortization expense, driven by assets being placed into service as we continue to execute on our capital plan.
•A $22.1 million decrease in pre-tax gains on the sales of land, primarily related to the land sale at the site of our former Pleasant Prairie power plant in 2023. See Note 3, Disposition, for more information.
•A $15.6 million increase in electric and natural gas distribution expenses, primarily driven by storm restoration and higher costs to maintain the distribution systems during the nine months ended September 30, 2024, compared with the same period in 2023.
•A $13.2 million increase in benefit costs, primarily driven by higher stock-based compensation and deferred compensation expense.
•A $7.7 million increase in expenses associated with legal claims.
•A $6.7 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 $9.7 million decrease in property and revenue taxes driven by a favorable adjustment related to a sales tax audit at WE.
•A $7.6 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.
Other Income, Net
Other income, net at the Wisconsin segment decreased $3.4 million during the nine months ended September 30, 2024, compared with the same period in 2023, due in part to lower AFUDC-Equity driven by the WE and WG LNG facilities going into service in November 2023 and February 2024, respectively. Our continued capital investment in the Wisconsin segment partially offset the impact from the completion of these facilities.
Interest Expense
Interest expense at the Wisconsin segment increased $26.0 million during the nine months ended September 30, 2024, compared with the same period in 2023, driven by higher average short-term debt balances, higher average short-term debt interest rates, and the impact of WE's $350.0 million long-term debt issuance in May 2024 and $600.0 million long-term debt issuance in September 2024. See Note 11, Long-Term Debt, for more information.
Income Tax Expense
Income tax expense at the Wisconsin segment decreased $16.2 million during the nine months ended September 30, 2024, compared with the same period in 2023, primarily due to lower pre-tax income and higher PTCs.
Illinois Segment Contribution to Net Income Attributed to Common Shareholders
The Illinois segment's contribution to net income attributed to common shareholders was $164.6 million during the nine months ended September 30, 2024, representing a $3.3 million, or 2.0%, decrease over the same period in 2023. The decrease was driven by higher operating expenses, a $25.3 million pre-tax charge to income related to the ICC's disallowance of certain capital costs in PGL's 2016 rider QIP reconciliation, and an increase in interest expense. These decreases in earnings were partially offset by higher margins due to the impacts of the PGL and NSG rate orders issued by the ICC, effective December 1, 2023 and February 1, 2024, respectively. SMP costs that were previously being recovered under PGL's QIP rider are now included in PGL's base rates. As base revenues are concentrated in the winter months (first and fourth quarters) when natural gas usage is highest, this rate design change drove a large increase in the first quarter 2024 margins.
Nine Months Ended September 30
(in millions)
2024
2023
B (W)
Operating revenues
$
1,116.4
$
1,116.5
$
(0.1)
Operating expenses
Cost of natural gas sold
254.3
316.5
62.2
Other operation and maintenance
336.1
305.5
(30.6)
Depreciation and amortization
191.1
176.3
(14.8)
Property and revenue taxes
41.9
27.8
(14.1)
Operating income
293.0
290.4
2.6
Other income, net
5.7
4.3
1.4
Interest expense
70.8
65.0
(5.8)
Income before income taxes
227.9
229.7
(1.8)
Income tax expense
63.3
61.8
(1.5)
Net income attributed to common shareholders
$
164.6
$
167.9
$
(3.3)
The following table shows a breakdown of other operation and maintenance:
Nine Months Ended September 30
(in millions)
2024
2023
B (W)
Operation and maintenance not included in the line items below
$
231.1
$
231.3
$
0.2
Riders (1)
90.9
74.4
(16.5)
Regulatory amortizations (1)
2.0
(0.2)
(2.2)
Impairment related to ICC disallowance (2)
12.1
—
(12.1)
Total other operation and maintenance
$
336.1
$
305.5
$
(30.6)
(1)These riders and regulatory amortizations are substantially offset in margins and therefore do not have a significant impact on net income.
(2)See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Regulatory Recovery and Note 25, Regulatory Environment, for more information on the ICC disallowance.
The following tables provide information on delivered sales volumes by customer class and weather statistics:
(1)Normal heating degree days are based on a 12-year moving average of monthly temperatures from Chicago's O'Hare Airport.
Gross Margin GAAP and Utility Margin Non-GAAP
The following table summarizes our Illinois segment gross margin (GAAP) and reconciles gross margin (GAAP) to utility margin (non-GAAP). See Non-GAAP Financial Measures above for additional information regarding gross margin (GAAP) and utility margin (non-GAAP).
Nine Months Ended September 30
(in millions)
2024
2023
B (W)
Operating revenues
$
1,116.4
$
1,116.5
$
(0.1)
Operating expenses
Cost of natural gas sold
(254.3)
(316.5)
62.2
Other operation and maintenance (1)
(167.4)
(152.9)
(14.5)
Depreciation and amortization
(191.1)
(176.3)
(14.8)
Property and revenue taxes
(41.9)
(27.8)
(14.1)
Gross margin (GAAP)
461.7
443.0
18.7
Other operation and maintenance (1)
167.4
152.9
14.5
Depreciation and amortization
191.1
176.3
14.8
Property and revenue taxes
41.9
27.8
14.1
Utility margin (non-GAAP)
$
862.1
$
800.0
$
62.1
(1) Operating and maintenance expenses deemed to be directly attributable to our revenue-producing activities include distribution and customer service expenses. These expenses are included in the above table to calculate gross margin as defined under GAAP.
Gross margin (GAAP) at the Illinois segment increased $18.7 million during the nine months ended September 30, 2024, compared with the same period in 2023, and utility margin (non-GAAP) increased $62.1 million during the nine months ended September 30, 2024, compared with the same period in 2023. Both measures were driven by:
•A $64.3 million increase in margins related to the impacts of the PGL and NSG rate orders issued by the ICC, effective December 1, 2023 and February 1, 2024, respectively. PGL’s rate order includes the recovery of costs related to PGL’s SMP in base rates. Previously, these costs were being recovered under its QIP rider. As base revenues are concentrated in the winter months (first and fourth quarters) when natural gas usage is highest, this rate design change drove a large increase in margins during the first quarter of 2024.
•A $16.5 million increase in revenues associated with certain riders that are offset in other operation and maintenance and therefore do not have a significant impact on net income.
These increases in gross margin (GAAP) and utility margin (non-GAAP) were partially offset by a $12.9 million decrease in revenues driven by an ICC order received in August 2024 related to PGL's 2016 Rider QIP reconciliation prudency review, which requires refunds to ratepayers for amounts previously collected related to the disallowance of certain capital costs.
Additionally, the smaller increase in gross margin (GAAP) as compared to the increase in utility margin (non-GAAP), was driven by the following items that are further described in Other Operating Expenses below:
•A $14.8 million increase in depreciation and amortization;
•A $14.1 million increase in property and revenue taxes;
•A $10.2 million increase in natural gas distribution and maintenance costs; and
•A $5.0 million increase in customer service expense.
Other Operating Expenses (includes other operation and maintenance, depreciation and amortization, and property and revenue taxes)
Other operating expenses at the Illinois segment increased $43.0 million, net of the $16.5 million impact of the riders referenced in the table above, during the nine months ended September 30, 2024, compared with the same period in 2023. The significant factors impacting the increase in other operating expenses were:
•A $14.8 million increase in depreciation and amortization expense, driven by assets being placed into service as we continue to execute on our capital plan.
•A $14.1 million increase in property and revenue taxes, driven by an increase in the invested capital tax. This increase was related to an increase in regulatory amortizations as approved in the PGL and NSG rate orders issued by the ICC, effective December 1, 2023 and February 1, 2024, respectively.
•A $12.1 million impairment driven by an ICC order received in August 2024 related to the 2016 annual prudency review of PGL's 2016 Rider QIP, which included a disallowance of certain capital costs.
•A $10.2 million increase in natural gas distribution and maintenance costs, primarily related to maintaining the natural gas infrastructure.
•A $5.0 million increase in customer service expense primarily due to higher metering costs.
•A $2.8 million increase in rate case related regulatory amortizations.
These increases in other operating expenses were partially offset by:
•An $11.1 million decrease in expenses driven by an ICC order received in May 2023 related to an annual prudency review of PGL's and NSG's UEA riders, which required refunds to ratepayers starting in September 2023. See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Regulatory Recovery and Note 25, Regulatory Environment, for more information.
•A $10.5 million decrease in expenses associated with the favorable settlement of a legal claim during the nine months ended September 30, 2024.
Interest Expense
Interest expense at the Illinois segment increased $5.8 million during the nine months ended September 30, 2024, compared with the same period in 2023, driven by the impact of PGL and NSG issuing long-term debt in November 2023.
Income Tax Expense
Income tax expense at the Illinois segment increased $1.5 million during the nine months ended September 30, 2024, compared with the same period in 2023, driven by a $1.3 million decrease in the amortization of the federal excess protected deferred tax benefits from the Tax Legislation. See Note 14, Income Taxes, for more information.
Other States Segment Contribution to Net Income Attributed to Common Shareholders
The other states segment's contribution to net income attributed to common shareholders was $35.5 million during the nine months ended September 30, 2024, representing a $4.6 million, or 14.9%, increase over the same period in 2023. The increase was driven by higher margins due to MGU's rate increase approved by the MPSC that was effective January 1, 2024 and MERC's final rate increase approved by the MPUC in November 2023. Lower property and revenue taxes also contributed to the increase in earnings. These positive impacts were partially offset by higher depreciation and amortization expense.
Since the majority of MERC and MGU customers use natural gas for heating, net income attributed to common shareholders at the other states segment is sensitive to weather and is generally higher during the winter months.
Nine Months Ended September 30
(in millions)
2024
2023
B (W)
Operating revenues
$
308.6
$
379.5
$
(70.9)
Operating expenses
Cost of natural gas sold
131.5
208.0
76.5
Other operation and maintenance
67.8
68.2
0.4
Depreciation and amortization
34.9
32.2
(2.7)
Property and revenue taxes
15.1
18.4
3.3
Operating income
59.3
52.7
6.6
Other income, net
0.3
0.7
(0.4)
Interest expense
12.1
12.0
(0.1)
Income before income taxes
47.5
41.4
6.1
Income tax expense
12.0
10.5
(1.5)
Net income attributed to common shareholders
$
35.5
$
30.9
$
4.6
The following table shows a breakdown of other operation and maintenance:
Nine Months Ended September 30
(in millions)
2024
2023
B (W)
Operation and maintenance not included in line item below
$
56.5
$
53.5
$
(3.0)
Regulatory amortizations and other pass through expenses (1)
11.3
14.7
3.4
Total other operation and maintenance
$
67.8
$
68.2
$
0.4
(1)Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on net income.
The following tables provide information on delivered sales volumes by customer class and weather statistics:
Nine Months Ended September 30
Therms (in millions)
Natural Gas Sales Volumes
2024
2023
B (W)
Customer Class
Residential
189.2
204.4
(15.2)
Commercial and industrial
118.8
132.4
(13.6)
Total retail
308.0
336.8
(28.8)
Transportation
612.2
587.8
24.4
Total sales in therms
920.2
924.6
(4.4)
Nine Months Ended September 30
Degree Days
Weather (1)
2024
2023
B (W)
MERC
Heating (5,135 Normal)
4,267
4,882
(12.6)
%
MGU
Heating (4,087 Normal)
3,259
3,579
(8.9)
%
(1)Normal heating degree days for MERC and MGU are based on a 20-year moving average and 15-year moving average, respectively, of monthly temperatures from various weather stations throughout their respective service territories.
The following table summarizes our other states segment gross margin (GAAP) and reconciles gross margin (GAAP) to utility margin (non-GAAP). See Non-GAAP Financial Measures above for additional information regarding gross margin (GAAP) and utility margin (non-GAAP).
Nine Months Ended September 30
(in millions)
2024
2023
B (W)
Operating revenues
$
308.6
$
379.5
$
(70.9)
Operating expenses
Cost of natural gas sold
(131.5)
(208.0)
76.5
Other operation and maintenance (1)
(41.5)
(39.8)
(1.7)
Depreciation and amortization
(34.9)
(32.2)
(2.7)
Property and revenue taxes
(15.1)
(18.4)
3.3
Gross margin (GAAP)
85.6
81.1
4.5
Other operation and maintenance (1)
41.5
39.8
1.7
Depreciation and amortization
34.9
32.2
2.7
Property and revenue taxes
15.1
18.4
(3.3)
Utility margin (non-GAAP)
$
177.1
$
171.5
$
5.6
(1) Operating and maintenance expenses deemed to be directly attributable to our revenue-producing activities include distribution and customer service expenses. These expenses are included in the above table to calculate gross margin as defined under GAAP.
Gross margin (GAAP) increased $4.5 million during the nine months ended September 30, 2024, compared with the same period in 2023 and utility margin (non-GAAP) increased $5.6 million during the nine months ended September 30, 2024, compared with the same period in 2023. Both measures were driven by:
•A $6.6 million increase related to MGU's rate increase approved by the MPSC that was effective January 1, 2024.
•A $1.5 million increase related to MERC's final rate increase approved by the MPUC in November 2023.
These increases were partially offset by a $1.2 million decrease related to MERC CIP revenue, which was offset in operation and maintenance expense. Rebates and programs are available to residential and commercial customers of MERC through the CIP, which is funded by rate payers using the Conservation Cost Recovery Charge and the Conservation Cost Recovery Adjustment funds that are collected on their monthly billing statements.
Additionally, the lower increase in gross margin (GAAP) as compared to the increase in utility margin (non-GAAP), was driven by the following items that are further described in Other Operating Expenses below:
•A $2.7 million increase in depreciation and amortization expense; and
•A $1.7 million increase in natural gas operations and customer service expense; partially offset by
•A $3.3 million decrease in property and revenue taxes.
Other Operating Expenses (includes other operation and maintenance, depreciation and amortization, and property and revenue taxes)
Other operating expenses at the other states segment decreased $1.0 million during the nine months ended September 30, 2024, compared with the same period in 2023. The significant factors impacting the decrease in operating expenses were:
•A $3.3 million decrease in property and revenue taxes, driven by the resolution of a use tax audit at MGU.
•A $3.0 million decrease in bad debt expense, driven by improvements in MERC's and MGU's loss rates.
•A $1.2 million decrease in operation and maintenance expense related to MERC's CIP program, which has an offsetting decrease in margins.
These decreases in other operating expenses were partially offset by:
•A $2.7 million increase in depreciation and amortization expense related to continued capital investment.
•A $1.7 million increase in natural gas operations and customer service expense, driven by the timing of various operation and maintenance projects, primarily at MERC.
•A $1.1 million increase in benefit costs, partially driven by higher costs related to stock-based compensation and deferred compensation.
Income Tax Expense
Income tax expense at the other states segment increased $1.5 million during the nine months ended September 30, 2024, compared with the same period in 2023, driven by higher pre-tax income.
Electric Transmission Segment Contribution to Net Income Attributed to Common Shareholders
Nine Months Ended September 30
(in millions)
2024
2023
B (W)
Equity in earnings of transmission affiliates
$
138.3
$
132.1
$
6.2
Interest expense
14.5
14.6
0.1
Income before income taxes
123.8
117.5
6.3
Income tax expense
30.6
29.4
(1.2)
Net income attributed to common shareholders
$
93.2
$
88.1
$
5.1
Equity in Earnings of Transmission Affiliates
Equity in earnings of transmission affiliates increased $6.2 million during the nine months ended September 30, 2024, compared with the same period in 2023. This increase was primarily due to continued capital investment by ATC.
Income Tax Expense
Income tax expense at the electric transmission segment increased $1.2 million during the nine months ended September 30, 2024, compared with the same period in 2023, primarily due to an increase in pre-tax income.
Non-Utility Energy Infrastructure Segment Contribution to Net Income Attributed to Common Shareholders
Operating income at the non-utility energy infrastructure segment increased $14.3 million during the nine months ended September 30, 2024, compared with the same period in 2023, which was primarily due to a $9.7 million positive impact from We Power due to continued capital investment.
In addition, WECI had a positive impact of $4.2 million driven by these items:
•A $24.4 million positive impact in 2024 related to the receipt of performance payments.
•A $12.9 million increase in PPA revenue resulting from increased generation driven by higher wind speeds and lower energy curtailments.
These increases in operating income were partially offset by:
•An $11.3 million increase in operation and maintenance expenses due primarily to equipment failures at several of our renewable generation facilities.
•A $7.9 million negative impact due to transmission congestion that reduced energy market prices.
•Recognition of $6.4 million in revenue related to Blooming Grove in 2023 for a capacity payment received from PJM Interconnection that was associated with a December 2022 cold weather event. The capacity payment was subject to a FERC complaint, so we recognized this as revenue in 2023 when FERC issued an order denying that complaint.
•A $4.6 million decrease due to lower amounts recognized for REC sales in 2024 at Blooming Grove driven by lower contracted REC prices overall, as well as timing of REC contract execution.
•A net $2.9 million negative impact on operating income due to higher depreciation in 2024, partially offset by an increase in amortization of intangible revenue contract liabilities from Sapphire Sky, a wind facility acquired in February 2023 and Samson I, a solar facility acquired in February 2023.
Interest Expense
Interest expense at the non-utility energy infrastructure segment increased $1.8 million during the nine months ended September 30, 2024, compared with the same period in 2023, primarily due to a $5.4 million increase in intercompany interest expense due to WECI’s issuance of a $430.0 million long-term intercompany note payable to WEC Energy Group in April 2023. This intercompany interest expense is offset by higher intercompany interest income at the corporate and other segment. Partially offsetting this increase, was lower interest expense due to a lower principal balance, as a result of the semi-annual principal payments on long-term debt.
Income Tax Benefit
The income tax benefit at the non-utility energy infrastructure segment increased $15.4 million during the nine months ended September 30, 2024, compared with the same period in 2023. The increase was primarily due to an increase in PTCs that was related to the IRS approved PTC rate increase and higher production volumes, partially offset by higher pre-tax earnings.
Corporate and Other Segment Contribution to Net Income Attributed to Common Shareholders
Nine Months Ended September 30
(in millions)
2024
2023
B (W)
Operating loss
$
(6.1)
$
(16.1)
$
10.0
Other income, net
41.7
35.3
6.4
Interest expense
222.1
183.9
(38.2)
Loss before income taxes
(186.5)
(164.7)
(21.8)
Income tax benefit
(58.0)
(63.3)
(5.3)
Net loss attributed to common shareholders
$
(128.5)
$
(101.4)
$
(27.1)
Operating Loss
The operating loss at the corporate and other segment decreased $10.0 million during the nine months ended September 30, 2024, compared with the same period in 2023. The lower operating loss was driven by a $12.6 million positive impact from WBS's allocation of its net credits from the non-service components of its net periodic pension and OPEB costs. These net credits are initially recorded in other income, net, but are allocated to our operating segments as an overhead cost, which is recorded through operating expenses. As a result, this positive impact is fully offset in the other income, net line item discussed below. This positive impact was partially offset by a $1.7 million period-over-period decrease in gains on the sale of land and other assets at Wispark.
Other Income, Net
Other income, net at the corporate and other segment increased $6.4 million during the nine months ended September 30, 2024, compared with the same period in 2023. The significant factors impacting the increase in other income, net were:
•A $9.5 million increase in interest income, driven by a $5.4 million increase in intercompany interest income from WECI due to its issuance of a $430.0 million long-term intercompany note to WEC Energy Group in April 2023. This intercompany interest income is offset by higher intercompany interest expense at our non-utility energy infrastructure segment. Higher interest income on cash balances of $2.7 million also contributed to the increase.
•A $6.7 million period-over-period increase due to net earnings of $3.5 million from our equity method investments in technology and energy-focused investment funds during the nine months ended September 30, 2024, compared with net losses of $3.2 million during the same period in 2023.
•A $2.6 million increase in the net gains from the investments held in the Integrys rabbi trust. The gains from the investments held in the rabbi trust partially offset the changes in benefit costs related to deferred compensation, which are primarily included in other operation and maintenance expense in our utility segments.
These increases in other income, net were partially offset by a $12.6 million decrease driven by lower net credits from the non-service components of WBS's net periodic pension and OPEB costs. As discussed above, this negative impact was offset by lower operating expenses as these credits are allocated to our operating segments as an overhead cost.
Interest Expense
Interest expense at the corporate and other segment increased $38.2 million during the nine months ended September 30, 2024, compared with the same period in 2023, due to the impact of long-term debt issuances by WEC Energy Group in April and September 2023 and May 2024, higher average short-term debt balances, and increased average short-term debt interest rates. Partially offsetting these increases in interest expense was the impact of Integrys' long-term debt redemption in August 2023, WEC Energy Group's long-term debt maturity in September 2023, WEC Energy Group's tender offer for its 2007 Junior Notes in January and February 2024, and WEC Energy Group's repurchase of $19.0 million of its 2007 Junior Notes in May 2024.
The income tax benefit at the corporate and other segment decreased $5.3 million during the nine months ended September 30, 2024, compared with the same period in 2023. This decrease was driven by a $13.6 million increase in the interim tax expense recorded to adjust consolidated income tax expense to the projected, annualized consolidated effective income tax rate, partially offset by a higher pre-tax loss.
LIQUIDITY AND CAPITAL RESOURCES
Overview
We expect to maintain adequate liquidity to meet our cash requirements for the operation of our businesses 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 nine months ended September 30:
(in millions)
2024
2023
Change in 2024 Over 2023
Cash provided by (used in):
Operating activities
$
2,630.0
$
2,538.4
$
91.6
Investing activities
(2,053.2)
(2,771.7)
718.5
Financing activities
(381.0)
192.5
(573.5)
Operating Activities
Net cash provided by operating activities increased $91.6 million during the nine months ended September 30, 2024, compared with the same period in 2023, driven by:
•A $230.4 million increase in cash related to $214.6 million of cash received for income taxes during the nine months ended September 30, 2024, compared with $15.8 million of cash paid for income taxes during the same period in 2023. The increase in cash received for income taxes was driven by proceeds received during the nine months ended September 30, 2024, related to 2023 and 2024 PTCs that were sold to third parties.
•A $146.5 million increase in cash driven by lower amounts of collateral paid to counterparties during the nine months ended September 30, 2024, compared with same period in 2023, as well as lower realized losses on derivative instruments recognized during the nine months ended September 30, 2024, compared with the same period in 2023.
These increases in net cash provided by operating activities were partially offset by:
•A $188.5 million decrease in cash from lower overall collections from customers during the nine months ended September 30, 2024, compared with the same period in 2023. This decrease was driven by a lower per-unit cost of natural gas and lower sales volumes from unfavorable weather during the nine months ended September 30, 2024, compared with the same period in 2023.
•A $100.2 million decrease in cash from higher payments for interest, driven by long-term debt issuances at higher interest rates during 2023 and 2024, higher average short-term debt balances, and increased average short-term debt interest rates during the nine months ended September 30, 2024, compared with the same period in 2023.
Net cash used in investing activities decreased $718.5 million during the nine months ended September 30, 2024, compared with the same period in 2023, driven by:
•The acquisition of a 90% ownership interest in Sapphire Sky in February 2023 for $442.6 million, net of cash acquired of $0.3 million.
•The acquisition of an 80% ownership interest in Samson I in February 2023 for $249.4 million, net of cash acquired of $5.2 million.
•The acquisition of a 90% ownership interest in Red Barn in April 2023 for $143.8 million.
•The acquisition of Whitewater in January 2023 for $76.0 million.
•An $18.8 million decrease in cash paid for ATC's construction costs during the nine months ended September 30, 2024, compared with the same period in 2023. These construction costs are reimbursable by ATC. See Note 20, Investment in Transmission Affiliates, for more information.
These decreases in net cash used in investing activities were partially offset by:
•A $205.2 million increase in cash paid for capital expenditures during the nine months ended September 30, 2024, which is discussed in more detail below.
•A $29.2 million decrease in proceeds received from the sale of assets during the nine months ended September 30, 2024, compared with the same period in 2023, driven by the sale of land at the site of our former Pleasant Prairie power plant in 2023. See Note 3, Disposition, for more information.
For more information on our acquisitions, see Note 2, Acquisitions.
Capital Expenditures
Capital expenditures by segment for the nine months ended September 30 were as follows:
Reportable Segment
(in millions)
2024
2023
Change in 2024 Over 2023
Wisconsin
$
1,546.6
$
1,263.5
$
283.1
Illinois
256.2
343.4
(87.2)
Other states
82.2
71.4
10.8
Non-utility energy infrastructure
33.7
33.9
(0.2)
Corporate and other
16.0
17.3
(1.3)
Total capital expenditures
$
1,934.7
$
1,729.5
$
205.2
The increase in cash paid for capital expenditures at the Wisconsin segment during the nine months ended September 30, 2024, compared with the same period in 2023, was driven by higher payments for WE's electric distribution system, increased capital expenditures for renewable energy projects at WE, WPS, and UMERC, increased capital expenditures for combustion turbines at OCPP, as well as increased capital expenditures for a project to consolidate our electric utility operations technology. These increases in capital expenditures were partially offset by decreased payments for natural gas-fired generation that was constructed at WPS's existing Weston power plant site and construction of WE's and WG's LNG facilities which were completed in November 2023 and February 2024, respectively.
The decrease in cash paid for capital expenditures at the Illinois segment during the nine months ended September 30, 2024, compared with the same period in 2023, was driven by lower payments related to PGL's natural gas distribution system, including SMP. For more information on the factors contributing to this decrease, see Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Future Illinois Proceedings.
The increase in cash paid for capital expenditures at the Other States segment during the nine months ended September 30, 2024, compared with the same period in 2023, was driven by increased payments for MGU's natural gas distribution system.
See Capital Resources and Requirements – Capital Requirements – Significant Capital Projects for more information.
Financing Activities
Net cash related to financing activities decreased $573.5 million during the nine months ended September 30, 2024, compared with the same period in 2023, driven by:
•A $1,326.6 million decrease in cash due to higher net repayments of commercial paper during the nine months ended September 30, 2024, compared with the same period in 2023.
•A $53.1 million decrease in cash due to higher dividends paid on our common stock during the nine months ended September 30, 2024, compared with the same period in 2023. In January 2024, our Board of Directors increased our quarterly dividend by $0.055 per share (7.1%) effective with the March 2024 dividend payment.
•The purchase of an additional 10% ownership interest in Samson I in January 2024 for $28.1 million.
These decreases in cash were partially offset by:
•A $622.4 million increase in cash due to higher issuances of long-term debt during the nine months ended September 30, 2024, compared with the same period in 2023.
•A $158.5 million increase in cash due to lower retirements of long-term debt during the nine months ended September 30, 2024, compared with the same period in 2023.
•A $51.0 million increase in cash due to the issuance of common stock during the nine months ended September 30, 2024. We did not issue any common stock during the nine months ended September 30, 2023. See Note 9, Common Equity, for more information.
Other Significant Financing Activities
For more information on our other significant financing activities, see Note 10, Short-Term Debt and Lines of Credit, and Note 11, Long-Term Debt.
Cash Requirements
We require funds to support and grow our businesses. 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 shareholders, 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 2023 Annual Report on Form 10-K for additional information regarding our significant cash requirements.
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, 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 23, Commitments and Contingencies.
(in millions)
2024 (1)
2025
2026
Wisconsin
$
2,692.6
$
4,202.4
$
4,410.7
Illinois
353.4
373.7
404.8
Other states
119.5
106.5
121.4
Non-utility energy infrastructure
953.7
437.6
23.1
Corporate and other
26.2
17.9
10.2
Total
$
4,145.4
$
5,138.1
$
4,970.2
(1)This includes actual capital expenditures incurred through September 30, 2024, as well as estimated capital expenditures for the remainder of the year.
Our utilities continue to upgrade their electric and natural gas distribution systems to enhance reliability. These upgrades include addressing our aging infrastructure, 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.
We are 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.
•WE and WPS, along with an unaffiliated utility, received PSCW approval to acquire and construct Paris, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Kenosha County, Wisconsin and once fully constructed, WE and WPS will collectively own 180 MWs of solar generation and 99 MWs of battery storage of this project. WE's and WPS's combined share of the cost of this project is estimated to be approximately $542 million, with construction of the solar portion and battery storage expected to be completed in 2024 and 2025, respectively.
•WE and WPS, along with an unaffiliated utility, received PSCW 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 and WPS will collectively own 225 MWs of solar generation and 68 MWs of battery storage of this project. WE's and WPS's combined share of the cost of this project is estimated to be approximately $567 million, with construction of the solar portion and battery storage expected to be completed in 2025 and 2026, respectively.
•WE and WPS, along with an unaffiliated utility, received PSCW approval to acquire Koshkonong, 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 and WPS will collectively own 270 MWs of solar generation and 149 MWs of battery storage of this project. WE's and WPS's combined share of the cost of this project is estimated to be approximately $930 million, with construction of the solar portion and battery storage expected to be completed in 2026 and 2027, respectively.
•In May 2024, WE completed the acquisition of an additional 100 MWs of capacity in West Riverside, a combined cycle natural gas plant operated by an unaffiliated utility in Rock County, Wisconsin, for $97.9 million.
•WE and WPS plan to enhance fuel flexibility at the coal-fired ERGS units and Weston Unit 4.
•In February 2024, WE and WPS, along with an unaffiliated utility, filed a request with the PSCW to acquire and construct High Noon Solar Energy Center, a utility-scale solar-powered electric generating facility with a battery energy storage system. If approved, the project will be located in Columbia County, Wisconsin and once fully constructed, WE and WPS will collectively own 270 MWs of solar generation and 149 MWs of battery storage of this project. If approved, WE and WPS's combined share of the cost of this project is estimated to be approximately $883 million, with construction of the solar portion and battery storage expected to be completed in 2027.
•UMERC received MPSC approval to acquire and construct Renegade, a utility-scale solar-powered electric generating facility. The project will be located in Delta and Marquette counties, Michigan and once fully constructed UMERC will own 100 MWs of solar generation. The cost of this project is estimated to be approximately $226 million, with construction expected to be completed by the end of 2026.
•In April 2024, WE filed a request with the PSCW to build five natural gas fired combustion turbines capable of producing approximately 1,100 MWs which would be located at the existing OCPP site. If approved, the cost of this project is estimated to be approximately $1.2 billion.
•In April 2024, WE filed a request with the PSCW to add seven natural gas-fired RICE units near the Paris Generating Station. The new RICE units would be fueled with natural gas and capable of producing approximately 128 MWs. If approved, the cost of this project is estimated to be approximately $280 million.
•In April 2024, WE filed a request with the PSCW to construct the Rochester Lateral, which would supply additional natural gas service to the OCPP site. The natural gas lateral would be built in Kenosha, Racine, and Milwaukee counties. If approved, the cost of this project is estimated to be approximately $200 million.
•In April 2024, WE filed a request with the PSCW to construct an LNG facility which would be located on the OCPP site. If approved, the facility would have a storage capacity of two Bcf and the cost of this project is estimated to be approximately $456 million.
•In September 2024, WE and WPS, along with an unaffiliated utility, filed a request with the PSCW to acquire Dawn Harvest Solar Energy Center, a utility-scale solar-powered electric generating facility with a battery energy storage system. If approved, the project will be located in Rock County, Wisconsin and once fully constructed, WE and WPS will collectively own 135 MWs of solar generation and WE will own 50 MWs of battery storage of this project. If approved, WE and WPS's combined share of the cost of this project is estimated to be approximately $409 million, with construction expected to be completed in 2028.
•In September 2024, WE and WPS, along with an unaffiliated utility, filed a request with the PSCW to acquire Saratoga, a utility-scale solar-powered electric generating facility with a battery energy storage system and Ursa, a utility-scale solar-powered electric generating facility. If approved, Saratoga will be located in Wood County, Wisconsin and Ursa will be located in Columbia County, Wisconsin. Once fully constructed, WE and WPS will collectively own 135 MWs of solar generation and 45 MWs of battery storage of Saratoga and 180 MWs of solar generation of Ursa. If approved, WE and WPS's combined share of the cost of Ursa is estimated to be approximately $406 million, with construction expected to be completed in 2027. If approved, WE and WPS's combined share of the cost of Saratoga is estimated to be approximately $406 million, with construction expected to be completed in 2028.
•In September 2024, WE and WPS, along with an unaffiliated utility, filed a request with the PSCW to acquire and construct Badger Hollow and to acquire Whitetail, two utility-scale wind-powered electric generating facilities. If approved, Badger Hollow will be located in Iowa and Grant counties, Wisconsin and Whitetail will be located in Grant County, Wisconsin. Once fully constructed, WE and WPS will collectively own 100 MWs of wind generation of Badger Hollow and 60 MWs of wind generation of Whitetail. If approved, WE and WPS's combined share of the cost of Badger Hollow is estimated to be $320 million, with construction expected to be completed in 2027. If approved, WE and WPS's combined share of the cost of Whitetail is estimated to be approximately $200 million, with construction expected to be completed in 2027.
•In October 2024, WE and WPS, along with an unaffiliated utility, filed a request with the PSCW to acquire and construct Good Oak and Gristmill, two utility-scale solar electric generating facilities. If approved, both Good Oak and Gristmill will be located in Columbia County, Wisconsin. Once fully constructed, WE and WPS will collectively own 88 MWs of solar generation of Good Oak and 60 MWs of solar generation of Gristmill. If approved, WE and WPS's combined share of the cost of Good Oak is estimated to be $194 million and the cost of Gristmill is estimated to be approximately $130 million, with construction for both projects expected to be completed in 2028.
The construction of additional LNG facilities in Wisconsin has been proposed as part of the 2025-2029 capital plan and would provide another approximately four Bcf of natural gas supply. The facilities are expected to reduce the likelihood of constraints on our natural gas distribution system during the highest demand days of winter.
In August 2023, the DOC issued a ruling in its investigation into whether new tariffs should be imposed on solar panels and cells imported from four southeast Asian countries. In response to a new petition in April 2024, the DOC and USITC are conducting additional investigations into the solar panels and cells from the same four 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 ruling and related USITC investigation, and CBP actions, related to solar panels, respectively. The expected in-service dates and costs identified above already reflect some of these impacts.
During 2023, PGL continued work on the SMP, a project to replace approximately 2,000 miles of Chicago's aging natural gas pipeline infrastructure. In November 2023, the ICC ordered PGL to pause spending on the SMP until the ICC has a proceeding to determine the optimal method of pipeline replacement and a prudent investment level. The ICC initiated the proceeding on January 31, 2024, and the proceeding is expected to last twelve months. For more information, see Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Future Illinois Proceedings. The ICC granted PGL a limited-scope rehearing, which focused exclusively on the authorized spending for the completion of SMP projects that started in 2023 and the authorized spending for emergency repairs needed to ensure the safety and reliability of PGL's delivery system. On May 30, 2024, the ICC issued a written order on the rehearing that approved $28.5 million of additional spending for emergency work. See Note 25, Regulatory Environment, for more information on the SMP.
The non-utility energy infrastructure line item in the table above includes WECI's investment in Maple Flats, Delilah I, Hardin III, and the purchase of an additional 10% ownership interest in Samson I. See Note 2, Acquisitions, for more information on these projects.
We expect to provide total capital contributions to ATC (not included in the above table) of approximately $315 million from 2024 through 2026. We do not expect to make any contributions to ATC Holdco during that period. WEC's portion of the investment in MISO Tranche 1 is estimated to be approximately $580 million between 2025 and 2029. Tranche 1 is part of MISO's Long Range Transmission Planning initiative to upgrade the grid so that it can reliably accommodate for the shift in generation to lower-carbon resources.
Long-Term Debt
See Note 11, Long-Term Debt, for information regarding the changes in our outstanding long-term debt during the nine months ended September 30, 2024.
Common Stock Dividends
Our current quarterly dividend rate is $0.835 per share, which equates to an annual dividend of $3.34 per share. For information related to our most recent common stock dividend declared, see Note 9, Common Equity.
Other Significant Cash Requirements
See Note 23, Commitments and Contingencies, for information regarding our minimum future commitments related to purchase obligations for the procurement of fuel, power, and natural 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 nine months ended September 30, 2024.
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 financial guarantees and letters of credit that support construction projects, commodity contracts, and other payment obligations. 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 10, Short-Term Debt and Lines of Credit, Note 17, Guarantees, and Note 22, Variable Interest Entities.
We anticipate meeting our short-term and long-term cash requirements to operate our businesses and implement our corporate strategy through internal generation of cash from operations and access to the capital markets, which allows us to obtain external short-term borrowings, including commercial paper and term loans, and intermediate or long-term debt securities, as well as other types of securities. In addition, in January 2024, we started issuing common equity through a combination of our employee benefit plans and stock purchase and dividend reinvestment plan. We also anticipate issuing common equity through an at-the-market program in the future. 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. Subject to market conditions and other factors, we may repurchase our debt securities through open market purchases, privately negotiated transactions and/or other types of transactions. In January and February 2024, pursuant to a tender offer, we purchased $122.1 million aggregate principal amount of the $500.0 million outstanding of our 2007 Junior Notes. Additionally, in May 2024, we repurchased $19.0 million aggregate principal amount of the $377.9 million outstanding of our 2007 Junior Notes for $18.7 million, plus accrued interest, with proceeds received from issuing commercial paper.
WEC Energy Group, WE, WPS, WG, and PGL maintain bank back-up credit facilities, which provide liquidity support for each company's 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 for the remainder of 2024, 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 for certain subsidiaries, and other factors. Our regulated utilities plan to maintain capital structures consistent with those approved by their respective regulators. For more information on our utilities' approved capital structures, see Item 1. Business – E. Regulation in our 2023 Annual Report on Form 10-K.
The issuance of securities by our utility companies is subject to the approval of the applicable state commissions or FERC. Additionally, with respect to the public offering of securities, WEC Energy Group, WE, and WPS file registration statements with the SEC under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the appropriate regulatory authorities, 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.
At September 30, 2024, our current liabilities exceeded our current assets by $1,390.2 million. We do not expect this to have an impact on our liquidity, as we currently believe that our cash and cash equivalents, our available capacity of $2,705.3 million under our existing revolving credit facilities, cash generated from ongoing operations, and access to the capital markets are adequate to meet our short-term and long-term cash requirements.
See Note 10, Short-Term Debt and Lines of Credit, and Note 11, Long-Term Debt, for more information about our credit facilities, commercial paper, and debt securities.
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 have 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 2023 Annual Report on Form 10-K.
The following table shows our capitalization structure as of September 30, 2024, as well as an adjusted capitalization structure that we believe is consistent with how a majority of the rating agencies currently view our 2007 Junior Notes:
(in millions)
Actual
Adjusted
Common shareholders' equity
$
12,082.0
$
12,261.4
Preferred stock of subsidiary
30.4
30.4
Long-term debt (including current portion)
18,712.9
18,533.5
Short-term debt
597.0
597.0
Total capitalization
$
31,422.3
$
31,422.3
Total debt
$
19,309.9
$
19,130.5
Ratio of debt to total capitalization
61.5
%
60.9
%
Included in long-term debt on our balance sheet as of September 30, 2024, is $358.9 million principal amount of the 2007 Junior Notes. The adjusted presentation attributes $179.4 million of the 2007 Junior Notes to common shareholders' equity and $179.5 million to long-term debt.
The adjusted presentation of our consolidated capitalization structure is included as a complement to our capitalization structure presented in accordance with GAAP. Management evaluates and manages our capitalization structure, including our total debt to total capitalization ratio, using the GAAP calculation as adjusted to reflect the treatment of the 2007 Junior Notes by the majority of rating agencies. Therefore, we believe the non-GAAP adjusted presentation reflecting this treatment is useful and relevant to investors in understanding how management and the rating agencies evaluate our capitalization structure.
Debt Covenants
Certain of our short-term and long-term debt agreements contain financial covenants that we must satisfy, including debt to capitalization ratios and debt service coverage ratios. At September 30, 2024, we were in compliance with all such covenants related to outstanding short-term and long-term debt. We expect to be in compliance with all such debt covenants for the foreseeable future. See Note 11, Common Equity, Note 13, Short-Term Debt and Lines of Credit, and Note 14, Long-Term Debt, in our 2023 Annual Report on Form 10-K, for more information regarding our debt covenants.
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 September 30, 2024. 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 September 30, 2024, it could have been required to post $103 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.
In June 2024, Moody's changed the rating outlook for PGL to negative from stable as a result of the November 2023 rate order and the May 2024 limited re-hearing. The change in rating outlook has not had, and we do not believe that it will have, a material impact on our ability to access capital markets. Moody's affirmed PGL's ratings including its Aa3 senior secured rating and its P-1 short term rating for commercial paper. See Note 25, Regulatory Environment, for more information on the outcome of the rate order.
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 2023 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.
Regulatory, Legislative, and Legal Matters
Regulatory Recovery
Our utilities account for their regulated operations in accordance with accounting guidance under the Regulated Operations Topic of the FASB ASC. Regulated entities are allowed to defer certain costs that would otherwise be charged to expense if the regulated entity believes the recovery of those costs is probable. We record regulatory assets pursuant to generic and/or specific orders issued by our regulators. Recovery of the deferred costs in future rates is subject to the review and approval by those regulators. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of the deferred costs, including those referenced below, is not approved by our regulators, the costs would be charged to income in the current period. Regulators can impose liabilities on a prospective basis for amounts previously collected from customers and for amounts that are expected to be refunded to customers. We record these items as regulatory liabilities. See Note 6, Regulatory Assets and Liabilities, for more information on our regulatory assets and liabilities. See Note 25, Regulatory Environment, in this report, and Note 26, Regulatory Environment, in our 2023 Annual Report on Form 10-K for more information regarding recent and pending rate proceedings, orders, and investigations involving our utilities.
Uncollectible Expense Adjustment Rider
The rates of PGL and NSG include a UEA rider for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. The UEA rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency by the ICC. In May 2023, the ICC issued a written order on PGL's and NSG's 2018 UEA rider reconciliation. The order required a $15.4 million and $0.7 million refund to ratepayers at PGL and NSG, respectively. These amounts were refunded over a period of nine months, which began on September 1, 2023. In June 2023, the ICC denied PGL's and NSG's application requesting a rehearing of the ICC's May 2023 order. In July 2023, PGL and NSG petitioned the Illinois Appellate Court for review of the ICC orders. Their appeal is still pending.
As of September 30, 2024, there can be no assurance that all costs incurred under the UEA rider during the open reconciliation years, which include 2019 through 2023, will be deemed recoverable by the ICC. The combined annual costs of PGL and NSG included in the rider, which reflect uncollectible write-offs in excess of what is recovered in base rates, have ranged from $10 million to $40 million during these open reconciliation years. Disallowances by the ICC, if any, could be material and have a material adverse impact on our results of operations.
Qualifying Infrastructure Plant Rider
In January 2014, the ICC approved PGL's use of the QIP rider as a recovery mechanism for costs incurred related to investments in QIP. This rider, which was in effect until December 1, 2023, continues to be subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. On August 14, 2024, the ICC issued a final order on PGL's 2016 annual reconciliation, which included a disallowance of $14.8 million of certain capital costs. PGL recorded a pre-tax charge to income of $25.3 million during the third quarter of 2024 related to the disallowance and the previously recognized return on these investments. On October 25 2024, PGL filed a petition with the Illinois Appellate Court for review of the ICC's August 14, 2024 order.
In March 2024, PGL filed its 2023 reconciliation with the ICC, which, along with the reconciliations from 2017 through 2022, is still pending. The aggregate capital costs included in the QIP rider during the open reconciliation years, which include 2017 through 2023, are approximately $2,058 million. As of September 30, 2024, there can be no assurance that all of these costs, along with any previously recognized return on these investments, will be deemed recoverable by the ICC. Further disallowances by the ICC, if any, could be material and have a material adverse impact on our results of operations.
In the PGL rate order issued by the ICC in November 2023, the ICC ordered PGL to pause spending on its SMP until the ICC completes a proceeding to determine the optimal method for replacing aging natural gas infrastructure and a prudent investment level. The ICC initiated the proceeding on January 31, 2024, and the proceeding is expected to last 12 months.
On March 7, 2024, the ICC initiated a statewide "Future of Gas" proceeding. The goal of this proceeding is to explore the issues involved with decarbonization of the gas distribution system in Illinois and recommend any future ICC action or legislative changes needed. It includes the formal exploration and consideration of the role of natural gas in the future, including in the context of the state’s environmental and energy policy goals. The proceeding includes a broad range of stakeholders, including Illinois utilities and other interested parties. The “Future of Gas” proceeding is expected to be completed in 2026.
At this time, we cannot predict the ultimate outcome of these proceedings or the resulting impact to our natural gas operations in Illinois. Future natural gas investment opportunities in Illinois could be negatively impacted depending upon the outcomes. See Note 25, Regulatory Environment, for more information regarding the November 2023 ICC rate order.
Chicago Decarbonization Efforts
The CABO was introduced at a meeting of the Chicago city council held in January 2024. If approved, this ordinance would set an indoor emissions standard that would require zero-to-low-emission energy systems in newly built commercial and residential buildings and major building additions in the city of Chicago. The proposed emission standards would effectively prohibit the use of natural gas in new buildings and homes and require electric heat and appliances. The CABO would not impact existing homes and businesses. In addition, certain buildings and equipment, such as hospitals, commercial kitchens, and back-up generators, would be exempt from the new emission limits.
In response to the CABO, a resolution was also introduced that would require the formation of a working group comprised of various subject matter experts to analyze the costs of converting buildings from natural gas to electricity, the costs for additional electric generation capacity needed for future building conversions, and the impact of shifting natural gas system costs from new construction to existing buildings if electrification measures are adopted. If the resolution is passed, this analysis would need to be completed prior to the adoption of any decarbonization initiatives, such as the CABO.
If approved by the city council, the CABO is expected to become effective one year after the approval date. PGL's future natural gas operations could be materially adversely impacted if the CABO is passed.
Petition Before PSCW Regarding Third-Party Financed Distributed Energy Resources
In May 2022, a petition was 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, therefore, is not subject to the PSCW’s jurisdiction under any statute or rule regulating public utilities. The party that filed the petition provides financing to its 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.
In December 2022, the PSCW granted the petitioner’s request for a declaratory ruling in part, 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 facts and circumstances of the specific project lease presented in that petition. The PSCW declined to issue the petitioner’s request for a broader declaratory ruling that the petitioner would not be regulated as a "public utility". Upon appeal, in April 2024, the Dane County Circuit Court reversed the PSCW’s decision, finding that the PSCW erroneously interpreted the definition of "public utility," and the evidence did not support its determination that the lease at issue in the petition did not involve the sale of electricity to the "public" under Wisconsin law. The case was remanded to the PSCW for further review. In June 2024 the PSCW issued an order to reopen the docket to consider modifications based upon the circuit court’s remand. On October 3, 2024, the PSCW issued an order declining to issue any declaratory ruling because the project lease originally at issue was no longer going forward. At this time we do not expect any material impact on our business operations.
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. 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 and UFLPA compliance requirements, and we expect the same will be true for subsequent projects, 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 whether we will experience any further impacts to the timing and cost of solar projects included in our long-term capital plan.
United States Department of Commerce Complaints
The solar panel industry continues to experience uncertainty resulting from AD and CVD investigations involving four southeast Asian countries including Malaysia, Vietnam, Thailand, and Cambodia.
In August 2023, the DOC issued a final decision regarding an AD/CVD petition filed by a California-based company alleging that Chinese manufacturers were shifting products to the four southeast Asian countries to avoid tariffs required on products imported from China and requesting that the DOC conduct a country-wide inquiry into each country. In its final decision, the DOC determined that circumvention was occurring in each of the four Southeast Asian countries noted above. Duties began to be applied to certain imports of solar cells from Malaysia, Vietnam, Thailand and Cambodia after expiration of the Biden Administration’s 24-month tariff moratorium on June 6, 2024. In addition, in response to its findings, the DOC promulgated new regulations that imposed enhanced duties in certain circumstances, including when the USITC determines there is a reasonable indication the domestic solar industry is materially or potentially injured because of imported products that violate certain fair trade laws.
In April 2024, a coalition of several U.S. producers of solar panels filed a petition with the DOC requesting new tariffs on imports from the same four Southeast Asian countries. The group alleged that some Chinese companies had moved their solar operations to avoid penalties implemented after the expiration of the moratorium. In May 2024, in response to the petition, the DOC initiated a new AD/CVD investigation of solar panels from the four southeast Asian countries.
In April 2024, the USITC began a preliminary investigation and, in June 2024, issued a preliminary determination that there is a reasonable indication imports of solar panels from the four Southeast Asian countries have caused injury to the U.S. solar industry. Based on the USITC’s preliminary decision, the DOC began an investigation and, on October 1, 2024 announced a preliminary affirmative determination in its CVD investigation and set preliminary duties on imports from the four southeast Asian countries. Its AD investigation is proceeding and a preliminary determination is scheduled for late 2024. If the DOC and USITC make final affirmative determinations in their investigations, the DOC may impose enhanced duties, including retroactive duties in certain circumstances. Final determinations are scheduled for early 2025.
The Biden Administration invoked the Defense Production Act to accelerate the production of solar panels in the U.S.; however, final determinations by the DOC and/or USITC may have an adverse impact on the solar industry overall. Additionally, the Biden Administration's actions did not address whether WROs applied to panels under previous complaints would be affected.
We are continuing to monitor these investigations as they progress to determine the potential impact on our business and results of operations.
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 a five year period, 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.
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 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. Under the IRA transferability option, we entered into a sales agreement in May 2024 to sell substantially all of our 2024 PTCs to a third party. See Note 14, Income Taxes, for more information about the impact of these sales. 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.
Return on Equity Incentive for Membership in a Transmission Organization
The FERC currently allows transmission utilities, including ATC, to increase their ROE by 50 basis points as an incentive for membership in a transmission organization, such as MISO. This incentive was established to stimulate infrastructure development and to support the evolving electric grid. However, a Notice of Proposed Rulemaking was issued by the FERC on April 15, 2021, proposing to limit the 50 basis point increase in ROE to only be available to transmission utilities initially joining a transmission organization for the first three years of membership. If this proposal becomes a final rule, ATC would be required to submit, within 30 days of the final rule's effective date, a compliance filing eliminating the 50 basis point incentive from its tariff. As a result, we estimate that this proposal, if adopted, would reduce our future after-tax equity earnings from ATC by approximately $7 million annually on a prospective basis. The transmission costs WE, WPS, and UMERC are required to pay ATC after the effective date would also be reduced by this proposal.
American Transmission Company Allowed Return on Equity Complaint
The ROE allowed by the FERC helps determine how much transmission owners, such as ATC, earn on their transmission assets as well as how much consumers pay for those assets. When a complaint was filed arguing the base ROE for MISO transmission owners, including ATC, was too high, the FERC started analyzing the base ROE for these transmission owners.
The base ROEs listed in the ROE complaint section below do not include the 50 basis point ROE incentive currently provided for membership in a transmission organization. See the Return on Equity Incentive for Membership in a Transmission Organization section above for more information on this incentive.
Return on Equity Complaint
In November 2013, a group of MISO industrial customers filed a complaint with the FERC asking that the FERC order a reduction to the base ROE used by MISO transmission owners, including ATC, from 12.2% to 9.15%. Due to this complaint, the FERC and the D.C. Circuit Court of Appeals issued the following orders and opinion. The refunds resulting from these orders and opinion are also described below.
•September 2016 FERC Order – On September 28, 2016, the FERC issued an order reducing the base ROE for MISO transmission owners to 10.32% for the period covered by the first complaint, November 12, 2013 through February 11, 2015 and September 28, 2016 going forward.
•November 2019 FERC Order – On November 21, 2019, the FERC issued another order after directing MISO transmission owners and other stakeholders to provide briefs and comments on a proposed change to the methodology for calculating base ROE. In this order, the FERC expanded its base ROE methodology to include the capital-asset pricing model in addition to the discounted cash flow model to better reflect how investors make their investment decisions. The FERC also rejected the use of the risk premium model as part of its base ROE methodology in this order. The FERC's modified methodology further reduced the base ROE for all MISO transmission owners, including ATC, to 9.88% for the period covered by the first complaint. In response to this FERC decision, requests for the FERC to rehear the November 2019 Order in its entirety were filed by various parties.
•May 2020 FERC Order – On May 21, 2020, the FERC issued an order that granted in part and denied in part the requests to rehear the November 2019 Order. In this May 2020 Order, the FERC made additional revisions to its base ROE methodology, including reinstating the use of the risk premium model. The additional revisions made by the FERC increased the base ROE for all MISO transmission owners, including ATC, from the 9.88% authorized in the November 2019 Order to 10.02% for the period covered by the first complaint. Various parties then filed requests to rehear certain parts of the May 2020 Order with the FERC.
•November 2020 FERC Order – In response to the rehearing requests filed concerning certain parts of the May 2020 Order, the FERC issued an order in November 2020 that confirmed the ROE previously authorized in its May 2020 Order.
•Refunds for FERC Orders Issued Prior to October 2024 – Due to the base ROE changes resulting from the FERC orders issued prior to October 2024, ATC was required to provide refunds, with interest, for the 15-month refund period from November 12, 2013 through February 11, 2015 and for the period from September 28, 2016 through November 19, 2020. In January 2022, ATC completed providing WE, WPS, and UMERC with the net refunds related to the transmission costs they paid during these periods. The refunds were applied to WE's and WPS's PSCW-approved escrow accounting for transmission expense.
•August 2022 D.C. Circuit Court of Appeals Opinion – Since several petitions for review were filed with the D.C. Circuit Court of Appeals concerning this ROE complaint, the D.C. Circuit Court of Appeals issued an opinion on August 9, 2022, addressing these petitions. In its August 2022 Opinion, the D.C. Circuit Court of Appeals ruled the FERC failed to adequately explain why it reinstated the use of the risk premium model as part of its ROE methodology in its May 2020 Order after previously rejecting the model in its November 2019 Order. Due to this ruling, the D.C. Circuit Court of Appeals vacated the FERC’s previous orders and remanded the issue of determining an appropriate base ROE for MISO transmission owners back to the FERC for additional proceedings. As a result, ATC had reflected a reserve for potential refunds based on a 9.88% base ROE.
•October 2024 FERC Order – In response to the August 2022 D.C. Circuit Court of Appeals Opinion, the FERC issued an order on October 17, 2024. The FERC’s October 2024 Order removed the risk premium model from the base ROE methodology and required MISO transmission owners, including ATC, to adopt a 9.98% base ROE for the period covered by the first complaint.
•Refunds for FERC Order Issued in October 2024 – Prior to the October 2024 FERC order, the base ROE for MISO transmission owners was 10.02% based on the November 2020 FERC order. Since the October 2024 FERC order changed the base ROE to 9.98%, ATC will be providing additional refunds, with interest, for the 15-month refund period from November 12, 2013 through February 11, 2015 and for the period from September 28, 2016 through October 17, 2024. Therefore, ATC is expected to provide WE, WPS, and UMERC with refunds related to the transmission costs they paid during these two refund periods. The refunds will be applied to WE’s and WPS’s PSCW-approved escrow accounting for transmission expense.
Due to the change between the 9.88% base ROE originally reflected in its reserve and the 9.98% base ROE authorized in the October 2024 FERC Order, ATC will reduce its refund liability. We expect this to increase our pre-tax equity earnings by approximately $19 million to $20 million. We are still in the process of reviewing the October 2024 FERC order for any additional impacts to us.
Environmental Matters
See Note 23, 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 businesses and the environments in which those businesses 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 regional conflicts, including those in Ukraine, Israel and in other parts of the Middle East, 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 2023 Annual Report on Form 10-K for a discussion of market and other significant risks applicable to us.
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 our capital plan. For additional information concerning risks related to inflation and supply chain disruptions, see the four risk factors below that are disclosed in Part I of our 2023 Annual Report on Form 10-K.
•Item 1A. Risk Factors – Risks Related to the Operation of Our Business – Public health crises, including epidemics and pandemics, could adversely affect our business functions, financial condition, liquidity, and results of operations.
•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 operations.
For additional information concerning risk factors, including market risks, see the Cautionary Statement Regarding Forward-Looking Information at the beginning of this report.
Weather
Our utilities' rates are based upon estimated normal temperatures. Our electric utility margins are unfavorably sensitive to below normal temperatures during the summer cooling season and, to some extent, to above normal temperatures during the winter heating season. Our natural gas utility margins are unfavorably sensitive to above normal temperatures during the winter heating season. PGL, NSG, and MERC have decoupling mechanisms in place that help reduce the impacts of weather. Decoupling mechanisms differ by state and allow utilities to recover or refund certain differences between actual and authorized margins. A summary of actual weather information in our utilities' service territories during the three and nine months ended September 30, 2024 and 2023, as measured by degree days, can be found in Results of Operations.
Our utility operations (primarily our electric utility operations) and the operations of WECI, can be negatively impacted from storms. High wind conditions, lightning, hail, and flooding from these storms can result in downed wires and poles, as well as damage to wind and solar generation facilities and other operating equipment. This can result in us incurring significant restoration costs at our utilities and at WECI, including lost revenue to customers. Our utilities' rates include a fixed amount for expected storm restoration costs. To the extent actual storm restoration costs are above what is included in these rates, earnings at our utility operations are negatively impacted and it becomes more difficult to achieve our authorized ROEs. Similarly, restoration costs and lost revenue from storms negatively impacts operations and earnings at our non-utility WECI renewable generation facilities.
Critical Accounting Policies and Estimates
We have reviewed our critical accounting policies and considered whether any new critical accounting estimates or other significant changes to our accounting policies require additional disclosures. We have found that the disclosures made in our 2023 Annual Report on Form 10-K are still current and that there have been no significant changes, except as follows:
Goodwill
We completed our annual goodwill impairment tests for all of our reporting units that carried a goodwill balance as of July 1, 2024. No impairments were recorded as a result of these tests. For all of our reporting units, the fair values calculated in step one of the test were greater than their carrying values. The fair values for the reporting units were calculated using a combination of the income approach and the market approach.
For the income approach, we used internal forecasts to project cash flows. Any forecast contains a degree of uncertainty, and changes in these cash flows could significantly increase or decrease the calculated fair value of a reporting unit. For our reporting units that are regulated, a fair recovery of and return on costs prudently incurred to serve customers is assumed. An unfavorable outcome in a rate case could cause the fair values of our reporting units to decrease.
Key assumptions used in the income approach include ROEs, the long-term growth rates used to determine terminal values at the end of the discrete forecast period, and the discount rates. The discount rate is applied to estimated future cash flows and is one of the most significant assumptions used to determine fair value under the income approach. As interest rates rise, the calculated fair values will decrease. The discount rate is based on the weighted-average cost of capital for each reporting unit, taking into account both the after-tax cost of debt and cost of equity. The terminal year ROE for each utility is driven by its current allowed ROE. The terminal growth rate is based primarily on a combination of historical and forecasted statistics for real gross domestic product and personal income for each utility service area.
For the market approach, we used a higher weighting for the guideline public company method than the guideline merged and acquired company method due to a low number of mergers and acquisitions in recent years. The guideline public company method uses financial metrics from similar publicly traded companies to determine fair value. The guideline merged and acquired company method calculates fair value by analyzing the actual prices paid for recent mergers and acquisitions in the industry. We applied multiples derived from these two methods to the appropriate operating metrics for our reporting units to determine fair value.
The underlying assumptions and estimates used in the impairment tests were made as of a point in time. Subsequent changes in these assumptions and estimates could change the results of the tests.
For all of our reporting units that carried a goodwill balance at July 1, 2024, the fair value exceeded its carrying value by over 50%. Based on these results, our reporting units are not at risk of failing step one of the goodwill impairment test.
See Note 19, Goodwill and Intangibles, for more information.
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 2023 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 – Market Risks and Other Significant Risks in Item 2 of Part I of this report, as well as Note 15, Fair Value Measurements, Note 16, Derivative Instruments, and Note 17, Guarantees, in this report for information concerning our market risk exposures.
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 third quarter of 2024 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
The following should be read in conjunction with Item 3. Legal Proceedings in Part I of our 2023 Annual Report on Form 10-K. See Note 23, Commitments and Contingencies, and Note 25, Regulatory Environment, in this report for additional information on material legal proceedings and matters related to us and our subsidiaries.
In addition to those legal proceedings discussed in Note 23, Commitments and Contingencies, and Note 25, Regulatory Environment, 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 impact on our financial statements.
ITEM 1A. RISK FACTORS
There were no material changes from the risk factors disclosed in Item 1A. Risk Factors in Part I of our 2023 Annual Report on Form 10-K.
ITEM 5. OTHER INFORMATION
During the three months ended September 30, 2024, 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).
The following exhibits are filed or furnished with or incorporated by reference in the report with respect to WEC Energy Group, Inc. (File No. 001-09057). An asterisk (*) indicates that the exhibit has previously been filed with the SEC and is incorporated herein by reference.
Number
Exhibit
4
Instruments Defining the Rights of Security Holders, Including Indentures
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
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.
WEC ENERGY GROUP, INC.
(Registrant)
/s/ WILLIAM J. GUC
Date:
November 1, 2024
William J. Guc
Vice President and Controller
(Duly Authorized Officer and Chief Accounting Officer)
