What changed in this filing

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Item 7. Management’s Discussion and Analysis

2024-02-22 compared with 2023-02-23 · 415 added, 396 removed, 836 unchanged (49% of the section changed)

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CORPORATE DEVELOPMENTS

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 American Transmission Company LLC (ATC) (a for-profit electric transmission company regulated by the Federal Energy Regulatory Commission and certain state regulatory commissions), and non-utility energy infrastructure operations through W.E.

Power LLC (which owns generation assets in Wisconsin), Bluewater Natural Gas Holding LLC (which owns underground natural gas storage facilities in Michigan), and WEC Infrastructure LLC (WECI), which holds ownership interests in several renewable generating facilities.

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

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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.

We published the results of a priority sustainability issue assessment in 2020, identifying the issues that are most important to our company and its stakeholders over the short and long terms.

Our risk and priority assessments have formed our direction as a company.

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.

When taken together, the retirements and new investments should better balance our supply with our demand, while maintaining reliable, affordable energy for our customers.

The retirements will contribute to meeting our goals to reduce carbon dioxide (CO 2 ) emissions from our electric generation.

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 making operating refinements, retiring less efficient generating units, and executing our capital plan.

Over the longer term, the target for our generation fleet is net-zero CO 2 emissions by 2050.

As part of our path toward these goals, we are exploring co-firing with natural gas at our ERGS coal-fired units.

The retirements will contribute to meeting our goals to reduce CO 2 emissions from our electric generation.

When taken together, the retirements and new investments in renewables and clean 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.

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 already have retired more than 1,800 megawatts (MW) of coal-fired generation since the beginning of 2018, which included the 2019 retirement of the Presque Isle power plant as well as the 2018 retirements of the Pleasant Prairie power plant, the Pulliam power plant, and the jointly-owned Edgewater Unit 4 generating units.

We already have retired more than 1,900 MWs of fossil-fueled generation since the beginning of 2018, which included the 2019 retirement of the PIPP as well as the 2018 retirements of the Pleasant Prairie power plant, the Pulliam power plant, and the jointly-owned Edgewater Unit 4 generating units.

See Note 6, Regulatory Assets and Liabilities, for more information related to these power plant retirements.

Through our ESG Progress Plan, we expect to retire approximately 1,600 MW of additional fossil-fueled generation by the end of 2026, which includes the planned retirement in 2024-2025 of Oak Creek Power Plant Units 5-8 and the planned retirement in 2026 of jointly-owned Columbia Units 1-2.

See Note 7, Property, Plant, and Equipment, for more information related to these planned power plant retirements.

We expect to retire approximately 1,800 MWs of additional fossil-fueled generation by the end of 2031, which includes the planned retirement in 2024-2025 of OCPP Units 5-8, the planned retirement by June 2026 of jointly-owned Columbia Units 1 and 2, and the planned retirement in 2031 of Weston Unit 3.

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 $7.0 billion from 2024-2028 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:

• 1,900 MW of utility-scale solar;

• 700 MW of battery storage;

• 2,700 MWs of utility-scale solar;

• 880 MWs of wind;

• 250 MWs of battery storage.

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• 700 MW of wind.

We also plan on investing in a combination of clean, natural gas-fired generation, including:

• 100 MW of reciprocating internal combustion engine (RICE) natural gas-fueled generation;

• the planned purchase of up to 200 MW of capacity in the West Riverside Energy Center – a combined cycle natural gas plant recently completed by Alliant Energy in Wisconsin.

• 1,125 MWs of combustion turbines;

• 132 MWs of RICE natural gas-fueled generation;

• the purchase of 100 MWs of additional capacity in West Riverside.

For more details, 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 MW 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 24 Solar Now projects and currently has another five under construction, together totaling more than 30 MW.

The second program, the Dedicated Renewable Energy Resource (DRER) pilot, would allow large commercial and industrial customers to access renewable resources that WE would operate, adding up to 150 MW of renewables to WE's portfolio.

The DRER pilot would help these larger customers meet their sustainability and renewable energy goals.

In August 2021, the PSCW approved pilot programs for WE and WPS to install and maintain electric vehicle (EV) charging equipment for customers at their homes or businesses.

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 one 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.

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.

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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 both continuous operational improvements and equipment upgrades, as well as the use of renewable natural gas (RNG) throughout our utility systems.

We plan to achieve our net-zero goal through an effort that includes both 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.

We have since signed our first five contracts for RNG for our natural gas distribution business, which will be transporting the output of local dairy farms onto our gas distribution system.

We have since signed contracts for RNG for our natural gas distribution business in Wisconsin, which will be transporting the output of local dairy farms onto our gas distribution systems.

The RNG supplied will directly replace higher-emission methane from natural gas that would have entered our pipes.

Our first five contracts bring us to a total of 1 Bcf of RNG planned to enter our system.

We expect to have RNG flowing to our distribution network in 2023, supporting our goal to reduce methane emissions.

As part of our effort to look for new opportunities in sustainable energy, during 2022 we completed testing the effects of blending hydrogen, a clean generating fuel, with natural gas at one of our RICE generating units in the Upper Peninsula of Michigan.

We partnered with the Electric Power Research Institute (EPRI) in this research that could help create another viable option for decarbonizing the economy.

We are still evaluating the data;

however, our initial findings indicate that all project measures exceeded our expectations.

The results of this testing continue to be analyzed and will be shared more broadly when complete.

In 2023, we are planning a pilot program with EPRI and CMBlu Energy, a Germany-based designer and manufacturer, to test a new form of long-duration energy storage on the U.S.

These contracts bring us to 1.8 Bcf of RNG planned to enter our systems.

RNG began flowing in 2023.

In December 2023, we started a pilot program with Electric Power Research Institute and CMBlu Energy, a Germany-based designer and manufacturer, to test a new form of long-duration energy storage on the U.S.

electric grid.

The program will test battery system performance, including the ability to store and discharge energy for up to twice as long as the typical lithium-ion batteries in use today.

The pilot is planned for the fourth-quarter of 2023.

We expect the full pilot to be completed in 2024.

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 Wisconsin Gas LLC (WG) have received approval to each construct their own liquefied natural gas (LNG) facility to meet anticipated peak demand.

Commercial operation of the WE and WG LNG facilities is targeted for the end of 2023 and 2024, respectively.

• Included in the capital plan are additional proposed LNG storage facilities providing approximately four Bcf of natural gas supply, which is needed to ensure gas supply for winter reliability.

• WE and WG have received approval to each construct their own LNG facility to meet anticipated peak demand.

Each facility would provide 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 at the end of 2023 and the WG LNG facility is targeted for 2024.

• 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

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• The Peoples Gas Light and Coke Company continues to work on its Safety Modernization Program, which primarily involves replacing 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.

• Our utilities continue to upgrade their electric and natural gas distribution systems to enhance reliability.

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 is 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.

As a result, PGL has suspended neighborhood work, pending the results of the limited rehearing.

See Note 26, Regulatory Environment, for more information.

• Our utilities continue to upgrade their electric and natural gas distribution systems to enhance reliability and storm hardening.

We expect to spend approximately $3.8 billion from 2024 to 2028 on reliability related projects with continued investment over the next decade.

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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 Advanced Metering Infrastructure program, replacing aging meter-reading equipment on both our network and customer property.

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.

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See Note 3, Dispositions, for information on recent transactions.

Our investment focus remains in our regulated utility and non-utility energy infrastructure businesses, as well as our investment in ATC.

In our non-utility energy infrastructure segment, we have acquired or agreed to acquire majority interests in eight wind parks and two solar parks, with total available capacity of more than 2,000 MW.

These renewable energy assets represent more than $2.9 billion in committed investments and have long-term agreements to serve customers outside our traditional service areas.

Production tax credits from these renewable investments reduce our cash tax expense.

In addition, we anticipate that credits generated in 2023 and beyond will be eligible to be transferred to third parties in exchange for cash.

See Note 2, Acquisitions, for information on recent and pending transactions.

We expect total capital expenditures for our regulated utility and non-utility energy infrastructure businesses to be approximately $18.1 billion from 2023 to 2027.

Our planned investment focus from 2024 to 2028 is in our regulated utilities and non-utility energy infrastructure business, as well as our investment in ATC.

We expect total capital expenditures for our regulated utility businesses to be approximately $19.5 billion from 2024 to 2028.

In addition, we currently forecast that our share of ATC's projected capital expenditures over the next five years will be approximately $3 billion.

We expect to invest approximately $1.2 billion in our non-utility energy infrastructure business over the same period, which includes our previously announced investment in Maple Flats and the purchase of an additional 10% ownership interest in Samson I.

Specific projects included in the $23.7 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 recent and pending transactions.

Exceptional Customer Care

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$ 4.22 $ 4.45 $ (0.23)

Earnings increased $107.8 million during 2022, compared with 2021.

The significant factors impacting the $107.8 million increase in earnings were:

• A $51.9 million increase in net income attributed to common shareholders at the Wisconsin segment, driven by lower operation and maintenance expense, largely due to the amortization of certain regulatory liabilities to offset a portion of our 2022 forecasted revenue deficiencies.

The amortization was approved by the PSCW in order to forego filing for 2022 base rate increases.

An increase in natural gas margins related to higher retail sales volumes, as well as higher net credits from the non-service components of our net periodic pension and OPEB costs, also contributed to the increase in earnings.

These increases in earnings were partially offset by a negative year-over-year impact from collections of fuel and purchased power costs, higher property and revenue taxes, and higher depreciation and amortization.

• A $45.2 million increase in net income attributed to common shareholders at the non-utility energy infrastructure segment, driven by an increase in PTCs during 2022, primarily due to the Jayhawk wind park that achieved commercial operation in December 2021, higher generation at our other wind parks, and an increase in the PTC rate related to the PTC inflation adjustment issued by the IRS.

In addition, Upstream recognized revenue during 2022 related to market settlements it received from SPP in February 2021.

Due to a complaint filed with the FERC, the revenue related to these settlements could not be recognized until the FERC issued an order denying the complaint in the first quarter of 2022.

A positive impact from a sharing

Earnings decreased $76.4 million during 2023, compared with 2022.

The significant factors impacting the $76.4 million decrease in earnings were:

• A $92.0 million increase in the net loss attributed to common shareholders at the corporate and other segment, driven by higher interest expense on both long-term and short-term debt.

This negative impact was partially offset by net gains from the investments held in the Integrys rabbi trust during 2023, compared with net losses during the same period in 2022.

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 17, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust.

• An $86.9 million decrease in net income attributed to common shareholders at the Illinois segment, driven by higher operating expenses, primarily due to an impairment associated with the ICC's disallowance of certain incurred capital costs in its November 2023 rate orders for PGL and NSG, and the year-over-year impact of a gain recorded in 2022 on the sale of certain real estate by PGL.

Partially offsetting these increases in operating expenses were lower natural gas distribution and maintenance costs and a decrease in expenses related to charitable contributions.

Higher natural gas margins, due to a positive impact from PGL's rate order, effective December 1, 2023, and continued capital investment in the SMP project in 2023 under PGL's QIP rider, also

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arrangement with one of our Blooming Grove customers, resulting from strong energy prices, also contributed to the increase in earnings.

• A $23.2 million increase in net income attributed to common shareholders at the electric transmission segment, primarily due to the impact of the D.C.

Circuit Court of Appeals opinion issued in August 2022 addressing complaints related to ATC's ROE and the year-over-year impact of a goodwill impairment recorded during the fourth quarter of 2021.

These increases in earnings were partially offset by a $20.3 million increase in the net loss attributed to common shareholders at the corporate and other segment, driven by net losses from the investments held in the Integrys rabbi trust during 2022, compared with net gains during 2021.

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 included in other operation and maintenance expense in our operating segments.

See Note 17, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust.

A decrease in earnings from our equity method investments in technology and energy-focused investment funds and higher interest expense also contributed to the higher net loss.

Partially offsetting these negative impacts was the year-over-year impact from the loss on debt extinguishment recorded in 2021.

partially offset the net increase in operating expenses.

See Note 26, Regulatory Environment, for more information on the PGL and NSG rate orders.

• A $10.4 million decrease in net income attributed to common shareholders at the electric transmission segment, driven by the positive impact in 2022 related to the D.C.

Circuit Court of Appeals opinion issued in August 2022 addressing complaints related to ATC's ROE.

For information on this D.C.

Circuit Court of Appeals opinion, see Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – American Transmission Company Allowed Return on Equity Complaints.

These decreases in earnings were partially offset by:

• A $92.9 million increase in net income attributed to common shareholders at the Wisconsin segment, driven by an increase in electric and natural gas margins related to the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2023, and a positive year-over-year impact from collections of fuel and purchased power costs.

These positive impacts were partially offset by a decrease in electric and natural gas margins due to lower sales volumes, and higher operating expenses, including increases in expenses related to transmission, depreciation and amortization, and regulatory amortizations.

• An $11.6 million increase in net income attributed to common shareholders at the non-utility energy infrastructure segment, primarily due to an increase in PTCs driven by the acquisition of additional renewable generation facilities in the second half of 2022 and the first quarter of 2023, partially offset by higher interest expense.

• An $8.4 million increase in net income attributed to common shareholders at the other states segment, driven by higher natural gas margins due to an interim rate increase at MERC, effective January 1, 2023.

See Note 26, Regulatory Environment, for more information.

This positive impact was partially offset by a decrease in natural gas margins due to lower sales volumes and increases in depreciation and amortization and interest expense.

Non-GAAP Financial Measures

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The Wisconsin segment's contribution to net income attributed to common shareholders for the year ended December 31, 2023 was $851.3 million, representing a $92.9 million, or 12.2%, increase over the prior year.

The increase in earnings was driven by lower operation and maintenance expense, largely due to the amortization of certain regulatory liabilities to offset a portion of our 2022 forecasted revenue deficiencies.

The amortization was approved by the PSCW in order to forego filing for 2022 base rate increases.

The higher earnings were driven by an increase in electric and natural gas margins related to the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2023, and a positive year-over-year impact from collections of fuel and purchased power costs.

Year Ended December 31

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During 2022, WE and WPS amortized $81.0 million of the regulatory liabilities associated with their transmission escrows to offset certain 2022 revenue deficiencies, as approved by the PSCW in order to forego filing for 2022 base rate increases.

This amortization drove the decrease in transmission expense during 2022, compared with 2021.

This amortization drove the lower transmission expense during 2022.

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

Effective January 1, 2023, the PSCW approved escrow accounting for pension and OPEB costs, as well as certain costs associated

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

with our jointly-owned Columbia plant.

As a result, our Wisconsin utilities defer as a regulatory asset or liability, the difference between these actual costs and those included in rates until recovery or refund is authorized in a future rate proceeding.

(3) Represents costs associated with the We Power generation units, including operating and maintenance costs recognized by WE.

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(4) Represents operation and maintenance associated with the earnings mechanisms we have in place.

In 2022, also includes $21.6 million of amortization related to a certain portion of WPS's regulatory liability associated with its 2020 earnings sharing mechanism to offset certain 2022 revenue deficiencies, as approved by the PSCW in order to forego filing for 2022 base rate increases.

In 2022, this amount was reduced by the $21.6 million amortization of certain regulatory liability balances associated with WPS's 2020 earnings sharing mechanism to offset certain 2022 revenue deficiencies, as approved by the PSCW in order to forego filing for 2022 base rate increases.

See Note 26, Regulatory Environment, for more information.

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To the extent that changes in fuel and purchased power costs are passed through to customers, the changes are offset by comparable changes in revenues.

See the discussion of electric utility margins below for more information related to recovery of fuel and purchased power costs and the remaining drivers of the changes in electric revenues.

See the discussion of electric utility margins below for more information related to the recovery of fuel and purchased power costs and the remaining drivers of the changes in electric revenues.

Electric Utility Margins

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The significant factors impacting the higher electric utility margins were:

• A $103.5 million increase in margins related to the impact of unprotected excess deferred taxes during 2021, which we agreed to return to customers in our PSCW-approved rate orders.

This increase in margins is offset in income taxes.

See Note 16, Income Taxes, and Note 26, Regulatory Environment, for more information.

• A $9.6 million increase in other revenues, primarily related to third-party use of our assets.

These increases in margins were partially offset by:

• A $50.8 million year-over-year negative impact from collections of fuel and purchased power costs compared with costs collected in rates.

• A $330.5 million increase in margins related to the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2023.

• A $61.6 million year-over-year 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 beyond the 2% price variance is generally deferred for future recovery or refund to customers.

As a result of the higher fuel costs in both 2021 and 2022, WPS was unable to defer a portion of its under-collected fuel and purchased power costs due to earning an ROE in excess of the PSCW authorized amount.

• Lower margins of $14.9 million driven by the expiration of certain wholesale contracts.

• An $8.4 million net decrease in margins related to lower sales volumes, driven by the impact of cooler weather during the 2022 cooling season, compared with 2021.

As measured by cooling degree days, 2022 was 11.0% cooler than 2021 in the Milwaukee area.

In 2022, WPS was unable to defer a portion of its under-collected fuel and purchased power costs due to earning an ROE in excess of the PSCW authorized amount.

• A $15.7 million increase in margins during 2023, related to the expiration of a capacity purchase contract driven by the acquisition of the Whitewater facility, effective January 1, 2023.

These increases in margins were partially offset by:

• A $67.9 million decrease in margins related to lower retail electric sales volumes, including steam operations, driven by the impact of unfavorable weather during 2023, compared with 2022.

As measured by cooling degree days, 2023 was 7.2% and 17.0% cooler than 2022 in the Milwaukee area and Green Bay area, respectively.

As measured by heating degree days, 2023 was 15.1% and 11.4% warmer than 2022 in the Milwaukee area and Green Bay area, respectively.

• A $25.1 million decrease in other revenues, primarily related to a FERC order in January 2023 that eliminated reactive power compensation MISO was required to pay to generators, including our electric utilities, as well as lower revenues from third-party use of our assets.

The decrease in reactive power revenues is substantially offset by a decrease in transmission expense related to a deferral of these revenues as a component of our transmission escrow, as approved by the PSCW in June 2023 and discussed below.

• Lower margins of $8.0 million driven by the expiration of a wholesale contract in May 2022.

Natural Gas Revenues

Natural gas revenues increased $490.3 million during 2022, compared with 2021.

Natural gas revenues decreased $373.6 million during 2023, compared with 2022.

Because prudently incurred natural gas costs are passed through to our customers in current rates, the changes are offset by comparable changes in revenues.

The average per-unit cost of natural gas increased approximately 27% during 2022, compared with 2021.

The average per-unit cost of natural gas decreased approximately 25% during 2023, compared with 2022.

The remaining drivers of changes in natural gas revenues are described in the discussion of natural gas utility margins below.

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Natural gas utility margins at the Wisconsin segment increased $59.1 million during 2023, compared with 2022.

The most significant factors impacting the higher natural gas utility margins were:

• A $59.7 million increase in margins from higher sales volumes, driven by the continued economic recovery in Wisconsin from the COVID-19 pandemic, as well as colder weather during the 2022 heating season, compared with 2021.

As measured by heating degree days, 2022 was 11.1% and 9.7% colder than 2021 in the Milwaukee area and Green Bay area, respectively.

• A $9.9 million increase in margins related to the amortization of a certain portion of WG's regulatory liability consisting of credit balances associated with the escrow of natural gas storage service costs from Bluewater Gas Storage.

In September 2021, the PSCW issued a written order for our Wisconsin utilities approving certain accounting treatments to offset certain 2022 revenue deficiencies in order to forego filing for 2022 base rate increases.

See Note 26, Regulatory Environment, for more information.

The most significant factor impacting the higher natural gas utility margins was a $116.6 million increase in margins related to the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2023.

This increase in margins was partially offset by a $57.4 million decrease in margins from lower sales volumes, driven by the impact of unfavorable weather during 2023, compared with 2022.

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

Other operating expenses at the Wisconsin segment decreased $44.4 million during 2022, compared with 2021.

The significant factors impacting the decrease in other operating expenses were:

• An $80.2 million decrease in transmission expense driven by the amortization of a certain portion of WE's and WPS's regulatory liabilities associated with transmission escrow balances, as discussed in the notes under the other operation and maintenance table above.

• A $19.3 million decrease in expense related to the earnings sharing mechanisms in place at our Wisconsin utilities, as discussed in the notes under the other operation and maintenance table above.

See Note 26, Regulatory Environment, for more information.

• A $14.5 million decrease in other operation and maintenance expense due to increases to certain regulatory assets resulting from decisions included in the December 2022 Wisconsin rate orders.

• An $8.6 million decrease in other operation and maintenance expense during 2022, compared with 2021, related to certain COVID-19 expenditures.

• A $6.8 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.

• A $3.1 million decrease in other operating and maintenance expense related to our power plants, driven by increases to certain plant-related regulatory assets resulting from decisions included in the December 2022 Wisconsin rate orders.

This decrease in expense was partially offset by increased maintenance at our plants, including a planned outage at the Weston power plant, and reductions in refined coal credits during 2022, compared with 2021.

• A $2.8 million decrease in expense related to higher gains on land sales during 2022, compared with 2021.

• A $2.4 million decrease in expense related to charitable projects supporting our customers and the communities within our service territories.

These decreases in other operating expenses were partially offset by:

• A $31.7 million increase in property and revenue taxes, driven by higher gross receipt and property taxes.

• A $29.3 million increase in electric and natural gas distribution expenses, primarily driven by higher costs to manage system reliability, for storm restoration, and for overall maintenance of our distribution system during 2022.

• A $27.8 million net increase in depreciation and amortization, driven by assets being placed into service as we continue to execute on our capital plan and an increase related to the We Power leases.

These increases were partially offset by $10.2 million of deferred depreciation related to capital investments made by WG since it's last rate case, as approved by the PSCW in an order that allowed our Wisconsin utilities to offset certain 2022 revenue deficiencies in order to forego filing for 2022 base rate increases.

Other operating expenses at the Wisconsin segment increased $273.4 million during 2023, compared with 2022.

The significant factors impacting the increase in other operating expenses were:

• A $109.5 million increase in transmission expense as approved in the PSCW's 2023 rate orders, effective January 1, 2023.

See the notes under the other operation and maintenance table above for more information.

This amount is net of a deferral of $11.9 million approved by the PSCW in June 2023, retroactive to December 1, 2022, in response to a FERC order eliminating reactive power compensation to our utilities, as discussed in electric margins above.

• A $96.8 million increase in depreciation and amortization, driven by assets being placed into service as we continue to execute on our capital plan.

• A $62.7 million increase in regulatory amortizations and other pass through expenses, as discussed in the notes under the other operation and maintenance table above.

• A $33.3 million increase in other operation and maintenance expense related to the We Power leases, as discussed in the notes under the other operation and maintenance table above.

• A $29.4 million increase in other operating and maintenance related to our power plants, driven by increases to certain plant-related regulatory assets in 2022 as a result of the December 2022 Wisconsin rate orders as well as operating costs associated with Whitewater, which we purchased in January 2023.

These increases were partially offset by lower severance during 2023.

• A $19.1 million increase in expense related to the earnings sharing mechanisms in place at our Wisconsin utilities, as discussed in the notes under the other operation and maintenance table above.

See Note 26, Regulatory Environment, for more information.

These increases in other operating expenses were partially offset by:

• A $23.9 million decrease in expense primarily related to lower commitments made in 2023 to fund our charitable foundations.

• A $19.1 million increase in pre-tax gains on the sale of land, primarily at the site of our former Pleasant Prairie power plant during 2023.

• A $15.6 million decrease in electric and natural gas distribution expenses, driven by lower costs to maintain the distribution system and for storm restoration during 2023, compared with 2022.

• A $7.0 million decrease in expenses associated with the settlement of legal claims.

Other Income, Net

Other income, net at the Wisconsin segment increased $26.0 million during 2022, compared with 2021, driven by higher net credits from the non-service components of our net periodic pension and OPEB costs.

See Note 20, Employee Benefits, for more information on our benefit costs.

Higher AFUDC–Equity due to continued capital investment also contributed to the increase in other income, net.

2022 Form 10-K 53

WEC Energy Group, Inc.

Other income, net at the Wisconsin segment increased $37.7 million during 2023, compared with 2022, driven by higher AFUDC-Equity due to continued capital investment.

See Note 27, Other Income, Net, for more information.

Interest Expense

Interest expense at the Wisconsin segment increased $45.1 million during 2023, compared with 2022.

The increase was primarily driven by WE and WPS issuing long-term debt during the third and fourth quarters of 2022, respectively.

Also driving the increase was an increase to short-term debt interest rates.

These increases were partially offset by the deferral of interest expense related to capital investments made by WG since its last rate case, as approved by the PSCW in an order that allowed our Wisconsin utilities to offset certain 2022 revenue deficiencies in order to forego filing for a 2022 base rate increase.

The increase was primarily due to the impact of WE and WPS issuing long-term debt during the third and fourth quarters of 2022, respectively, and higher average short-term debt balances and increased short-term debt interest rates.

Also contributing to the increase was the 2022 deferral of $8.2 million of interest expense related to capital investments made by WG since its 2020 rate case, as approved by the PSCW in an order that allowed our Wisconsin utilities to offset certain 2022 revenue deficiencies in order to forego filing for 2022 base rate increases.

This deferred interest expense is now being amortized over a two-year period.

During 2023, WG amortized $4.1 million of interest expense.

See Note 26, Regulatory Environment, for more information.

Also offsetting the increases was lower interest expense on finance lease liabilities, primarily related to the We Power leases, as finance lease liabilities decrease each year as payments are made.

Higher AFUDC–Debt due to continued capital investment also contributed to offsetting the increases.

These increases were partially offset by higher AFUDC-Debt due to continued capital investment and lower interest expense on finance lease liabilities, primarily related to the We Power leases, as finance lease liabilities decrease each year as payments are made.

2023 Form 10-K 56

WEC Energy Group, Inc.

Income Tax Expense

Income tax expense at the Wisconsin segment increased $127.6 million during 2022, compared with 2021.

The increase was primarily due to an approximate $100 million negative impact related to the lower year-over-year amortization of the unprotected excess deferred tax benefits from the Tax Legislation in connection with the Wisconsin rate orders approved by the PSCW, effective January 1, 2020.

The impact due to the benefit from the amortization of these unprotected excess deferred tax benefits in 2021 did not impact earnings as there was an offsetting impact in operating income.

Also contributing to the increase was higher pre-tax income in 2022.

See Note 16, Income Taxes, and Note 26, Regulatory Environment, for more information.

Income tax expense at the Wisconsin segment decreased $10.1 million during 2023, compared with 2022.

The decrease was primarily due to a $23.1 million increase in PTCs and a $6.3 million increase in income tax benefits associated with AFUDC-Equity, both driven by continued capital investment.

These decreases in income tax expense were partially offset by higher pre-tax income.

See Note 16, Income Taxes, for more information.

Illinois Segment Contribution to Net Income Attributed to Common Shareholders

The Illinois segment's contribution to net income attributed to common shareholders for the year ended December 31, 2022 was $226.9 million, representing a $3.9 million, or 1.7%, increase over the prior year.

The increase was driven by a gain on the sale of certain real estate in Chicago, as well as higher natural gas margins due to PGL's continued capital investment in the SMP project under its QIP rider and NSG's rate increase, effective September 15, 2021.

These positive impacts were partially offset by increases in various operating expenses, as discussed below.

Since the majority of PGL and NSG customers use natural gas for heating, net income attributed to common shareholders is sensitive to weather and is generally higher during the winter months.

The Illinois segment's contribution to net income attributed to common shareholders for the year ended December 31, 2023 was $140.0 million, representing an $86.9 million, or 38.3%, decrease from the prior year.

The decrease was driven by higher operating expenses, primarily due to an impairment associated with the ICC's disallowance of certain incurred capital costs in its November 2023 rate orders for PGL and NSG, and the year-over-year impact of a gain recorded in 2022 on the sale of certain real estate by PGL.

Partially offsetting these increases in operating expenses were lower natural gas distribution and maintenance costs and a decrease in expenses related to charitable contributions.

Higher natural gas margins, due to a positive impact from PGL's rate order, effective December 1, 2023, and continued capital investment in the SMP project in 2023 under PGL's QIP rider, also partially offset the net increase in operating expenses.

See Note 26, Regulatory Environment, for more information on the PGL and NSG rate orders.

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.

Year Ended December 31

4 unchanged sentences

Other operation and maintenance 397.9 459.2 61.3

Impairment related to ICC disallowances 178.9 — (178.9)

Depreciation and amortization 237.3 230.9 (6.4)

6 unchanged sentences

Net income attributed to common shareholders $ 140.0 $ 226.9 $ (86.9)

2022 Form 10-K 54

WEC Energy Group, Inc.

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

8 unchanged sentences

(1) These riders and regulatory amortizations are substantially offset in margins and therefore do not have a significant impact on net income.

2023 Form 10-K 57

WEC Energy Group, Inc.

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

14 unchanged sentences

Natural Gas Revenues

Natural gas revenues increased $218.1 million during 2022, compared with 2021.

Natural gas revenues decreased $333.1 million during 2023, compared with 2022.

Because prudently incurred natural gas costs are passed through to our customers in current rates, the changes are offset by comparable changes in revenues.

The average per-unit cost of natural gas sold increased approximately 14% during 2022, compared with 2021.

The average per-unit cost of natural gas sold decreased approximately 35% during 2023, compared with 2022.

The remaining drivers of changes in natural gas revenues are described in the discussion of margins below.

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The increase in margins was primarily driven by:

• A $24.9 million increase in revenues at PGL due to continued capital investment in the SMP project.

PGL recovers the costs related to the SMP through a surcharge on customer bills pursuant to an ICC approved QIP rider, which is in effect through 2023.

For information on the QIP rider and PGL's plan to recover these costs after 2023, see Note 26, Regulatory Environment.

• An $8.0 million increase related to the impact of the NSG rate order approved by the ICC, effective September 15, 2021, which includes the Variable Income Tax Adjustment Rider in base rates.

The Variable Income Tax Adjustment Rider recovers or refunds changes in actual income tax expense resulting from changes in income tax rates and amortization of deferred taxes, which differ from amounts included in rates.

See Note 26, Regulatory Environment, for more information on NSG's rate order.

• A $5.0 million increase in the invested capital tax adjustment rider, which did not impact net income as it was offset in property and revenue taxes.

The invested capital tax adjustment rider is a mechanism that allows PGL and NSG to recover or refund the difference between the cost of invested capital tax incurred and the amount collected through base rates.

2022 Form 10-K 55

WEC Energy Group, Inc.

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

• A $29.5 million increase in margins related to the impact of the PGL rate order issued by the ICC, effective December 1, 2023.

• A $23.9 million increase in revenues at PGL due to continued capital investment in the SMP project under the QIP rider.

PGL recovered the costs related to the SMP through a surcharge on customer bills pursuant to the QIP rider, which was in effect for most of 2023.

For information on PGL's rate order, the QIP rider, PGL's plan to recover SMP costs after 2023, and the pause in spending on the SMP, see Note 26, Regulatory Environment.

Other Operating Expenses (includes other operation and maintenance, impairment related to ICC disallowances, depreciation and amortization, and property and revenue taxes)

Other operating expenses at the Illinois segment increased $148.2 million, net of the $32.9 million impact of the riders referenced in the table above, during 2023, compared with 2022.

The significant factors impacting the increase in operating expenses were:

• A $22.4 million increase in expenses related to charitable projects supporting our customers and the communities within our service territories.

• A $12.8 million increase in depreciation and amortization, primarily driven by PGL's continued capital investment in the SMP project.

• A $12.7 million increase in natural gas distribution and maintenance costs, primarily related to maintaining the natural gas infrastructure, including costs associated with PGL's gas storage field.

• An $11.4 million increase in expenses associated with the settlement of legal claims.

• A $9.8 million increase in benefit costs, primarily due to higher pension and stock-based compensation costs.

• A $7.4 million increase in property and revenue taxes, primarily driven by an increase in the invested capital tax related to continued capital investment.

This increase was offset in natural gas utility margins.

• A $6.9 million increase in customer service expense, primarily driven by higher call volumes.

These increases in operating expenses were partially offset by a $54.5 million pre-tax gain on the sale of certain real estate in Chicago.

The significant factors impacting the increase in other operating expenses were:

• A $178.9 million impairment associated with the ICC orders received in November 2023 related to PGL's and NSG's rate reviews, which included the disallowance of previously incurred capital costs at PGL and NSG, in the amount of $177.2 million and $1.7 million, respectively.

See Note 26, Regulatory Environment, for more information on the ICC disallowances.

• A $54.5 million pre-tax gain on the sale of certain real estate in Chicago during 2022.

See Note 3, Dispositions, for more information.

• An $11.1 million increase in expense 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 for more information.

2023 Form 10-K 58

WEC Energy Group, Inc.

These increases in operating expenses were partially offset by:

• A $43.8 million decrease in natural gas distribution and maintenance costs, primarily related to maintaining the natural gas infrastructure during 2023, compared with 2022.

• A $25.0 million decrease in expenses related to contributions to charitable projects supporting our customers and the communities within our service territories during 2023, compared with 2022.

• A $9.4 million decrease in expenses associated with the settlement of legal claims during 2022.

• An $8.7 million decrease in property and revenue taxes, primarily driven by lower property and use taxes.

• A $3.7 million decrease in customer service expense due to lower call center expense and metering costs.

• A $3.0 million decrease in benefit costs, primarily due to lower stock-based compensation expense related to plan performance during 2023.

Other Income, Net

Other income, net at the Illinois segment increased $6.8 million during 2022, compared with 2021, driven by higher net credits from the non-service components of our net periodic pension and OPEB costs.

Other income, net at the Illinois segment decreased $7.4 million during 2023, compared with 2022, driven by lower net credits from the non-service components of our net periodic pension and OPEB costs.

See Note 20, Employee Benefits, for more information on our benefit costs.

Interest Expense

Interest expense at the Illinois segment increased $7.2 million during 2022, compared with 2021, driven primarily by $225.0 million and $100.0 million of long-term debt issuances in November 2021 and December 2022, respectively, and increased short-term debt interest rates.

Interest expense at the Illinois segment increased $15.1 million during 2023, compared with 2022, driven by higher long-term debt balances related to incremental borrowings in both 2023 and 2022, primarily related to additional capital investment.

Also contributing to the increase was higher short-term debt interest rates.

Income Tax Expense

Income tax expense at the Illinois segment increased $3.8 million during 2022, compared with 2021, driven by an increase in pre-tax income and a $1.3 million negative impact associated with previously unrecognized tax benefits recorded in 2021.

See Note 16, Income Taxes, for more information.

Income tax expense at the Illinois segment decreased $34.5 million during 2023, compared with 2022, driven by a decrease in pre-tax income.

Other States Segment Contribution to Net Income Attributed to Common Shareholders

The other states segment's contribution to net income attributed to common shareholders for the year ended December 31, 2022 was $39.7 million, representing a $3.9 million, or 10.9%, increase over the prior year.

The increase was driven by higher natural gas margins due to a rate increase at MGU, effective January 1, 2022, and higher sales volumes during 2022, compared with 2021.

These positive impacts were partially offset by increases in operating expenses, as well as interest expense, as discussed below.

The other states segment's contribution to net income attributed to common shareholders for the year ended December 31, 2023 was $48.1 million, representing an $8.4 million, or 21.2%, increase over the prior year.

The increase was driven by higher natural gas margins due to an interim rate increase at MERC, effective January 1, 2023.

See Note 26, Regulatory Environment, for more information.

This positive impact was partially offset by a decrease in natural gas margins due to lower sales volumes and increases in depreciation and amortization and interest expense.

2023 Form 10-K 59

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(in millions) 2023 2022 B (W)

Operation and maintenance not included in line items below $ 77.8 $ 70.5 $ (7.3)

Operation and maintenance not included in line item below

$ 72.6 $ 77.8 $ 5.2

Regulatory amortizations and other pass through expenses (1)

21.9 20.7 (1.2)

Other — 0.1 0.1

Total other operation and maintenance $ 94.5 $ 98.5 $ 4.0

19 unchanged sentences

Natural Gas Revenues

Natural gas revenues increased $99.5 million during 2022, compared with 2021.

Natural gas revenues decreased $99.4 million during 2023, compared with 2022.

Because prudently incurred natural gas costs are passed through to our customers in current rates, the changes are offset by comparable changes in revenues.

The average per-unit cost of natural gas sold increased approximately 4.0% during 2022, compared with 2021.

The average per-unit cost of natural gas sold decreased approximately 17% during 2023, compared with 2022.

The remaining drivers of changes in natural gas revenues are described in the discussion of margins below.

Natural Gas Utility Margins

Natural gas utility margins increased $27.2 million during 2022, compared with 2021.

The increase in margins was primarily driven by:

• A $13.0 million increase related to the new rates at MGU that went into effect in 2022.

Natural gas utility margins increased $15.0 million during 2023, compared with 2022, driven by a $19.5 million increase related to an interim rate increase at MERC that was effective January 1, 2023.

See Note 26, Regulatory Environment, for more information.

• A $9.3 million increase related to higher sales volumes due to both continued economic recovery and colder weather during 2022, compared with 2021.

• A $2.6 million increase related to MERC's GUIC rider, which was in place through December 31, 2022.

The GUIC rider allowed MERC to recover previously approved GUIC incurred to replace or modify natural gas facilities to the extent the work is required by state, federal, or other government agencies and exceeds the costs included in base rates.

• A $1.2 million increase 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.

This increase in natural gas utility margins was partially offset by a $6.1 million decrease related to lower sales volumes, primarily driven by warmer weather.

As measured by heating degree days, 2023 was 14.7% and 13.1% warmer than 2022 at MERC and MGU, respectively.

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

Other operating expenses at the other states segment increased $15.4 million during 2022, compared with 2021.

The significant factors impacting the increase in operating expenses were:

• A $7.9 million increase in natural gas operations and customer service expense, primarily driven by various operation and maintenance projects approved in MGU's rate case and an increase in costs related to safety and reliability programs at MERC.

• A $4.5 million increase in property and revenue taxes, driven by higher use tax at MGU.

• A $2.8 million increase in depreciation and amortization related to continued capital investment.

• A $1.2 million increase in operation and maintenance expense due to MERC's CIP program, which has an offsetting increase in margins.

Other operating expenses at the other states segment decreased $0.5 million during 2023, compared with 2022.

The significant factors impacting the decrease in operating expenses were:

• A $1.8 million decrease in natural gas operations and customer service expense, driven by fewer operation and maintenance projects at MGU during 2023.

• A $1.6 million decrease in benefit costs, primarily due to lower stock-based compensation expense related to plan performance.

These decreases in other operating expenses were partially offset by a $2.4 million increase in depreciation and amortization related to continued capital investment.

Other Income, Net

Other income, net at the other states segment increased $1.4 million during 2022, compared with 2021, driven by higher net credits from the non-service components of our net periodic pension and OPEB costs.

Other income, net at the other states segment decreased $1.9 million during 2023, compared with 2022, driven by lower net credits from the non-service components of our net periodic pension and OPEB costs.

See Note 20, Employee Benefits, for more information on our benefit costs.

Interest Expense

Interest expense at the other states segment increased $7.7 million during 2022, compared with 2021, driven primarily by the deferral of $4.9 million of interest expense during 2021, as approved by the MPSC to mitigate the impacts from delaying the filing of

MGU's 2021 rate case.

See Note 26, Regulatory Environment, for additional information.

This deferred interest expense is now being amortized over a four-year period as a result of MGU's approved rate increase.

2022 Form 10-K 58

WEC Energy Group, Inc.

Interest expense at the other states segment increased $2.0 million during 2023, compared with 2022, primarily due to higher short-term debt interest rates.

Income Tax Expense

4 unchanged sentences

Equity in earnings of transmission affiliates $ 177.5 $ 194.7 $ (17.2)

Other expense — 0.1 0.1

Interest expense 19.4 19.4 —

2 unchanged sentences

Net income attributed to common shareholders $ 119.1 $ 129.5 $ (10.4)

2023 Form 10-K 61

WEC Energy Group, Inc.

Equity in Earnings of Transmission Affiliates

Equity in earnings of transmission affiliates increased $36.6 million during 2022, compared with 2021, driven by:

• A $20.5 million increase in equity earnings due to the impact of a D.C.

Equity in earnings of transmission affiliates decreased $17.2 million during 2023, compared with 2022.

The decrease was primarily driven by the $20.5 million positive impact recorded in 2022 related to the D.C.

Circuit Court of Appeals opinion issued in August 2022 addressing complaints related to ATC's ROE.

1 unchanged sentence

• An $8.5 million increase in equity earnings related to a goodwill impairment recorded during the fourth quarter of 2021 by ATC Holdco, which was formed to invest in transmission-related projects outside of ATC's traditional footprint.

Continued capital investment by ATC also contributed to the year-over-year increase in equity earnings.

Partially offsetting this negative year-over-year impact was continued capital investment by ATC.

Income Tax Expense

Income tax expense at the electric transmission segment increased $13.5 million during 2022, compared with 2021, driven by an increase in pre-tax income and a $3.3 million negative impact associated with a previously recorded reversal of a tax remeasurement in 2021.

Income tax expense at the electric transmission segment decreased $6.8 million during 2023, compared with 2022, driven by a decrease in pre-tax income.

Non-Utility Energy Infrastructure Segment Contribution to Net Income Attributed to Common Shareholders

4 unchanged sentences

Income before income taxes 266.4 303.9 (37.5)

Income tax expense (benefit) (20.9) 3.1 24.0

Income tax benefit (68.4) (20.9) 47.5

Net (income) loss attributed to noncontrolling interests 1.2 (0.4) 1.6

Net income attributed to common shareholders $ 336.0 $ 324.4 $ 11.6

2022 Form 10-K 59

WEC Energy Group, Inc.

Operating Income

Operating income at the non-utility energy infrastructure segment increased $22.5 million during 2022, compared with 2021, driven by:

• A $15.2 million positive impact from recognition of revenue related to our Upstream wind park in 2022 that was associated with market settlements received from SPP in February 2021.

Operating income at the non-utility energy infrastructure segment decreased $12.1 million during 2023, compared with 2022, driven by these items at WECI:

• Recognition of $15.2 million in revenue related to our Upstream wind park in 2022 that was associated with market settlements received from SPP in February 2021.

These settlements were subject to a FERC complaint, so we were not able to recognize them as revenue until the FERC issued an order denying that complaint in 2022.

• A $13.4 million positive impact from a sharing arrangement with one of our Blooming Grove customers resulting from strong energy prices.

These increases in operating income were partially offset by:

• A $5.1 million negative impact from higher operating losses at our Jayhawk wind park that achieved commercial operation in December 2021.

The site experienced operating losses in 2022 due to SPP reliability curtailments reducing output and transmission congestion reducing energy market prices.

• A $13.4 million positive revenue impact in 2022 from a sharing arrangement with one of our Blooming Grove customers resulting from strong energy prices.

These decreases in operating income were partially offset by:

• Recognition of $6.4 million in revenue related to our Blooming Grove wind park 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 $4.4 million positive impact from Sapphire Sky Wind, a new wind facility acquired in February 2023.

In addition to the above items at WECI, there was a $5.4 million positive impact from We Power due to continued capital investment.

Interest Expense

Interest expense at the non-utility energy infrastructure segment decreased $2.1 million during 2022, compared with 2021, primarily due to a lower principal balance as a result of the semi-annual principal payments on long-term debt.

Income Tax Expense (Benefit)

At the non-utility energy infrastructure segment, $20.9 million of income tax benefit was recorded during 2022, compared with $3.1 million of income tax expense recorded during 2021.

The change was primarily due to a $30.3 million increase in PTCs in 2022, driven by the Jayhawk wind park that achieved commercial operation in December 2021, higher generation at our other wind parks, and an increase in the PTC rate related to the PTC inflation adjustment issued by the IRS.

This favorable change in the income tax benefit was partially offset by higher pre-tax earnings in 2022.

Interest expense at the non-utility energy infrastructure segment increased $25.4 million during 2023, compared with 2022, driven by a $16.1 million increase in 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 and is eliminated in consolidation.

Also driving the increase was the impact of WECI Wind Holding II's issuance of long-term debt in December 2022.

2023 Form 10-K 62

WEC Energy Group, Inc.

Income Tax Benefit

The income tax benefit at the non-utility energy infrastructure segment increased $47.5 million during 2023, compared with 2022.

The increase was primarily due to a $37.5 million increase in PTCs in 2023, driven by the acquisition of additional renewable generation facilities in the second half of 2022 and in the first quarter of 2023.

Also contributing to the favorable income tax variance were lower pre-tax earnings during 2023, compared with 2022.

Corporate and Other Segment Contribution to Net Income Attributed to Common Shareholders

4 unchanged sentences

Interest expense 257.6 119.4 (138.2)

Loss on debt extinguishment — 36.3 36.3

Loss before income taxes (231.1) (116.5) (114.6)

2 unchanged sentences

Operating Loss

The operating loss at the corporate and other segment decreased $7.2 million during 2022, compared with 2021, driven by the resolution of a previously recorded liability as certain outstanding matters reached a favorable outcome in 2022.

The operating loss at the corporate and other segment increased $15.1 million during 2023, compared with 2022, driven by the year-over-year impact from the 2022 resolution of a previously recorded liability as certain outstanding matters reached a favorable outcome.

Lower operating income at Wispark also contributed to the higher operating loss, driven by the 2022 positive impact from a payment on a note receivable that was previously written off due to uncertainty regarding its collectability and lower gains related to the sale of land and other assets.

Other Income, Net

Other income, net at the corporate and other segment decreased $37.1 million during 2022, compared with 2021.

The decrease was driven by a $12.6 million net loss from the investments held in the Integrys rabbi trust during 2022, compared with an $18.6 million net gain during 2021.

Other income, net at the corporate and other segment increased $38.7 million during 2023, compared with 2022.

The significant factors impacting the increase in other income, net were:

• A $13.7 million net gain from the investments held in the Integrys rabbi trust during 2023, compared with a $12.6 million net loss during 2022.

See Note 17, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust.

• An $18.3 million increase in intercompany interest income, driven by WECI's issuance of a $430.0 million long-term intercompany note to WEC Energy Group in April 2023 and higher interest rates on short-term borrowings to subsidiaries in our operating segments.

This intercompany interest income is offset by higher intercompany interest expense in our operating segments and is eliminated in consolidation.

These increases in other income, net were partially offset by a $3.5 million net loss from our equity method investments in technology and energy-focused investment funds during 2023, compared with $6.5 million of net earnings during 2022.

Interest Expense

Interest expense at the corporate and other segment increased $138.2 million during 2023, compared with 2022, primarily due to the impact of long-term debt issuances in September 2022, January 2023, and April 2023.

Also driving the increase in interest expense was higher average short-term debt balances and increased short-term debt interest rates.

2023 Form 10-K 63

WEC Energy Group, Inc.

Note 17, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust.

An $11.9 million decrease in earnings from our equity method investments in technology and energy-focused investment funds also contributed to the lower other income, net.

Interest Expense

Interest expense at the corporate and other segment increased $26.6 million during 2022, compared with 2021, due to a $900.0 million long-term debt issuance in September 2022.

See Note 14, Long-Term Debt, for more information.

Also contributing to the increase was higher short-term debt interest rates.

Loss on Debt Extinguishment

There was no loss on debt extinguishment during 2022, as we did not refinance any debt obligations prior to maturity during 2022.

Income Tax Benefit

The income tax benefit at the corporate and other segment decreased $0.1 million during 2022, compared with 2021, driven by $10.3 million of previously unrecognized tax benefits recorded during 2021.

This decrease in income tax benefit was offset by higher pre-tax loss and a $3.9 million increase in excess tax benefits recognized related to stock option exercises during 2022, compared with 2021.

The income tax benefit at the corporate and other segment increased $22.6 million during 2023, compared with 2022, driven by a higher pre-tax loss.

This increase in the income tax benefit was partially offset by a $5.9 million decrease in excess tax benefits recognized related to stock option exercises.

LIQUIDITY AND CAPITAL RESOURCES

11 unchanged sentences

Net cash provided by operating activities increased $957.7 million during 2023, compared with 2022, driven by:

• A $696.2 million increase in cash from higher overall collections from customers as a result of an increase in natural gas sales volumes during 2022, compared with 2021, driven by the continued economic recovery from the COVID-19 pandemic and colder weather.

In addition, we continued to recover the natural gas costs we under-collected from our Illinois and Minnesota customers related to the extreme weather conditions that occurred in February 2021.

See Note 26, Regulatory Environment, for more information on the recovery of these natural gas costs.

• A $1.54 billion increase in cash from lower payments for fuel and purchased power at our generation plants, as well as lower natural gas costs related to natural gas sold to our customers during 2023, compared with 2022, primarily driven by a decrease in the price of natural gas.

• A $111.3 million increase in cash related to $58.9 million of cash received for income taxes during 2023, compared with $52.4 million of cash paid for income taxes during 2022.

The increase in cash received for income taxes was driven by proceeds received in 2023 related to PTCs that were sold to a third party.

• A $24.1 million increase in cash related to higher distributions received from ATC during 2023, compared with 2022.

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

• A $403.7 million decrease in cash driven by collateral paid to counterparties during 2023, compared with collateral received from counterparties during 2022, as well as realized losses on derivative instruments recognized during 2023, compared with realized gains recognized during 2022.

• A $168.2 million decrease in cash from higher payments for interest, driven by long-term debt issuances during the last four months of 2022 and early 2023, higher average short-term debt balances, and higher interest rates during 2023, compared with 2022.

2023 Form 10-K 64

WEC Energy Group, Inc.

• A $51.2 million increase in cash related to a decrease in contributions and payments related to pension and OPEB plans during 2022, compared with 2021.

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

• A $461.3 million decrease in cash from higher payments for fuel and purchased power at our plants during 2022, compared with 2021.

Our plants incurred higher fuel costs throughout 2022 as a result of an increase in the price of natural gas.

• A $127.9 million decrease in cash from higher payments for operating and maintenance expenses.

During 2022, our payments were higher for reliability and storm restoration, transmission, benefit costs, natural gas distribution and maintenance costs, natural gas storage costs, and customer service.

• A $28.3 million decrease in cash related to higher payments for property and revenue taxes, driven by higher gross receipt taxes, property taxes, and an increase in the Illinois invested capital tax during 2022, compared with 2021.

• An $18.6 million decrease in cash related to higher cash paid for income taxes, driven by higher taxable income during 2022, compared with 2021.

During 2023, our payments were higher associated with previous commitments to charitable projects, transmission costs, and operation and maintenance related to our We Power and Wisconsin generation units, as well as due to the timing of payments for accounts payable.

• A $22.1 million decrease in cash related to higher payments for environmental remediation related to work completed on former manufactured gas plant sites during 2023, compared with 2022.

• A $12.6 million decrease in cash related to lower distributions from ATC during 2022, compared with 2021.

• An $11.4 million decrease in cash related to higher payments for interest related to increases in long-term and short-term debt interest rates during 2022, compared with 2021.

Investing Activities

Net cash used in investing activities increased $915.8 million during 2023, compared with 2022, driven by:

• The acquisition of a 90% ownership interest in Thunderhead in September 2022 for $382.0 million.

See Note 2, Acquisitions, for more information.

• 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 $257.3 million, net of cash acquired of $5.2 million.

• A $178.0 million increase in cash paid for capital expenditures during 2023, compared with 2022, which is discussed in more detail below.

• Capital contributions paid to transmission affiliates of $45.5 million during 2022.

• The acquisition of a 90% ownership interest in Red Barn in April 2023 for $143.8 million.

• The acquisition of a 13.8% ownership interest in West Riverside in June 2023 for $95.3 million.

See Note 8, Jointly Owned Utility Facilities, for more information.

• The acquisition of Whitewater in January 2023 for $76.0 million.

• A decrease of $39.1 million in insurance proceeds received during 2023, compared with 2022.

In 2022, we received insurance proceeds for property damage related to the PSB water damage claim.

See Note 7, Property, Plant, and Equipment, for more information.

• A $36.2 million decrease in proceeds received from the sale of assets during 2023, compared with 2022.

See Note 3, Dispositions, for more information.

• An $18.2 million increase in capital contributions paid to transmission affiliates during 2023, compared with 2022.

See Note 21, Investment in Transmission Affiliates, for more information.

There were no payments to transmission affiliates during 2021.

• The purchase of spectrum frequencies for $19.2 million during 2022.

See Note 10, Goodwill and Intangibles, for more information.

• A $17.8 million increase in cash paid for ATC's construction costs during 2022, compared with 2021, which will be reimbursed in the future.

• A $10.1 million decrease in cash received for the reimbursement of ATC's construction costs during 2023, compared with 2022.

See Note 21, Investment in Transmission Affiliates, for more information.

These increases in net cash used in investing activities were partially offset by:

• The acquisition of a 90% ownership interest in Jayhawk in February 2021 for $119.9 million.

See Note 2, Acquisitions, for more information.

• A $47.1 million increase in proceeds from the sale of assets during 2022, compared with 2021, primarily related to the sale of real estate owned by PGL.

See Note 3, Dispositions, for more information.

• Insurance proceeds of $41.6 million received during 2022 for property damage, primarily related to the PSB water damage claim.

See Note 7, Property, Plant, and Equipment, for more information.

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These increases in net cash used in investing activities were partially offset by the acquisition of a 90% ownership interest in Thunderhead in September 2022 for $382.0 million.

For more information on our acquisitions, see Note 2, Acquisitions.

Capital Expenditures

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Total capital expenditures $ 2,492.9 $ 2,314.9 $ 178.0

The increase in cash paid for capital expenditures at the Wisconsin segment during 2022, compared with 2021, was primarily driven by higher payments for capital expenditures related to Paris and other renewable energy projects, the new natural gas-fired generation being constructed at WPS's existing Weston power plant site, and WG's LNG facility.

These increases were partially offset by lower payments for capital expenditures related to upgrades to WE's and WPS's natural gas distribution systems and the restoration of WE's PSB.

See Note 7, Property, Plant, and Equipment, for more information on the PSB.

The decrease in cash paid for capital expenditures at the Illinois segment during 2022, compared with 2021, was primarily driven by lower capital expenditures related to upgrades at the Manlove Gas Storage Field and upgrades to PGL's natural gas distribution system.

The decrease in cash paid for capital expenditures at the non-utility energy infrastructure segment during 2022, compared with 2021, was primarily driven by lower payments for capital expenditures related to the construction of Jayhawk, which went into commercial operation in December 2021.

See Note 2, Acquisitions, for more information.

This decrease in cash paid for capital expenditures was partially offset by an increase in capital expenditures for wastewater treatment system modifications for We Power's ERGS units.

See Note 24, Commitments and Contingencies, for more information on the wastewater treatment system modifications.

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The increase in cash paid for capital expenditures at the Wisconsin segment during 2023, compared with 2022, was driven by higher payments related to renewable energy projects, upgrades to WE's and WPS's electric and natural gas distribution systems, and construction of WE's and WG's LNG facilities.

These increases were partially offset by lower payments for capital expenditures related to the natural gas-fired generation constructed at WPS's Weston power plant site.

The decrease in cash paid for capital expenditures at the non-utility energy infrastructure segment during 2023, compared with 2022, was primarily driven by lower payments for capital expenditures related to wastewater treatment system modifications for We Power's ERGS units.

See Note 24, Commitments and Contingencies, for more information.

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

Financing Activities

Net cash provided by financing activities increased $382.4 million during 2022, compared with 2021, driven by:

• A $1,168.3 million increase in cash due to a decrease in retirements of long-term debt during 2022, compared with 2021.

• A $340.0 million increase in cash due to a repayment of a 364-day term loan during 2021.

• A $51.6 million increase in cash due to a decrease in payments for debt extinguishment and issuance costs during 2022, compared with 2021.

• A $17.9 million increase in cash received from the exercise of stock options during 2022, compared with 2021.

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

• A $711.8 million decrease in cash due to $252.6 million of net repayments of commercial paper during 2022, compared with $459.2 million of net borrowings of commercial paper during 2021.

• A $384.5 million decrease in cash due to lower issuances of long-term debt during 2022, compared with the same period in 2021.

Net cash provided by financing activities decreased $153.6 million during 2023, compared with 2022, driven by:

• A $913.3 million decrease in cash due to higher retirements of long-term debt during 2023, compared with 2022.

• A $66.3 million decrease in cash due to higher dividends paid on our common stock during 2023, compared with 2022.

In January 2023, our Board of Directors increased our quarterly dividend by $0.0525 per share (7.2%) effective with the March 2023 dividend payment.

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• A $36.1 million decrease in cash due to an increase in common stock purchased during 2022, compared with 2021, to satisfy requirements of our stock-based compensation plans.

• A $27.3 million decrease in cash proceeds related to fewer stock options exercised during 2023, compared with 2022.

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

• A $626.3 million increase in cash due to $373.7 million of net borrowings of commercial paper during 2023, compared with $252.6 million of net repayments of commercial paper during 2022.

• A $170.7 million increase in cash due to higher issuances of long-term debt during 2023, compared with 2022.

• A $52.6 million increase in cash due to a decrease in common stock purchased during 2023, compared with 2022, to satisfy requirements of our stock-based compensation plans.

Significant Financing Activities

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Our significant cash requirements are discussed in further detail below.

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Significant Capital Projects

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Our utilities continue to upgrade their electric and natural gas distribution systems to enhance reliability.

These upgrades include addressing our aging infrastructure and system hardening and the AMI program.

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.

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Below are examples of projects that are proposed or currently underway.

• We have received approval to invest in 100 MW of utility-scale solar within our Wisconsin segment.

WE has partnered with an unaffiliated utility to construct a solar project, Badger Hollow II, that will be located in Iowa County, Wisconsin.

Once constructed, WE will own 100 MW of this project.

WE's share of the cost of this project is estimated to be approximately $151 million.

Commercial operation of Badger Hollow II is targeted for 2023.

• 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 MW of solar generation and 99 MW of battery storage of this project.

WE's and WPS's combined share of the cost of this project is estimated to be approximately $390 million, with construction of the solar portion expected to be completed in 2023.

• 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 MW of solar generation and 68 MW of battery storage of this project.

WE's and WPS's combined share of the cost of this project is estimated to be approximately $400 million, with construction of the solar portion expected to be completed in 2024.

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.

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.

WE's and WPS's combined share of the cost of this project is estimated to be approximately $405 million, with construction expected to be completed in 2024.

As part of its order, the PSCW approved battery capacity at this project, which is no longer included in the current capital plan.

We will continue to evaluate timing, cost, and feasibility of the installation of batteries.

• WE and WPS, along with an unaffiliated utility, received PSCW approval to acquire Koshkonong, a utility-scale solar-powered electric generating facility.

The project will be located in Dane County, Wisconsin and once fully constructed, WE and WPS will collectively own 270 MWs of solar generation.

WE's and WPS's combined share of the cost of this project is estimated to be approximately $486 million, with construction expected to be completed in 2026.

As part of its order, the PSCW approved battery capacity at this project, which is no longer included in the current capital plan.

We will continue to evaluate timing, cost, and feasibility of the installation of batteries.

• In September 2023, WPS filed a request with the PSCW to exercise a second option to acquire an additional 100 MWs of capacity in West Riverside, a combined cycle natural gas plant operated by an unaffiliated utility in Rock County, Wisconsin.

In October 2023, WPS filed for approval to assign the second option to purchase West Riverside to WE.

If approved, our share of the cost of this ownership interest is expected to be approximately $100 million, with the transaction expected to close in 2024.

• 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, a utility-scale solar-powered electric generating facility.

The project will be located in Columbia County, Wisconsin and once fully constructed, WE and WPS will collectively own 270 MWs of solar generation of this project.

If approved, WE and WPS's combined share of the cost of the project is estimated to be approximately $576 million, with construction expected to be

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• WPS, along with an unaffiliated utility, received PSCW approval to acquire Red Barn, a utility-scale wind-powered electric generating facility.

The project will be located in Grant County, Wisconsin and once constructed, WPS will own 82 MW of this project.

WPS's share of the cost of this project is estimated to be approximately $160 million, with construction expected to be completed in the first half of 2023.

• In April 2021, WE and WPS, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire the Koshkonong Solar-Battery Park, a utility-scale solar-powered electric generating facility with a battery energy storage system.

The project will be located in Dane County, Wisconsin and once fully constructed, WE and WPS will collectively own 270 MW of solar generation and 149 MW of battery storage of this project.

If approved, WE's and WPS's combined share of the cost of this project is estimated to be approximately $585 million, with construction of the solar portion expected to be completed in 2025.

• WE and WPS received PSCW approval to construct 128 MWs of natural gas-fired generation at WPS's existing Weston power plant site in northern Wisconsin.

The new facility will consist of seven RICE units.

We estimate the cost of this project to be approximately $170 million, with construction expected to be completed in 2023.

• Effective January 1, 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 electrical generation facility in Whitewater, Wisconsin.

The cost of this facility was approximately $75.0 million, which includes transaction costs and working capital.

See Note 15, Leases, for more information.

• In January 2022, WPS, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire a portion of West Riverside's nameplate capacity.

WPS is also requesting approval to assign the option to purchase part of West Riverside to WE.

If approved, WPS or WE would acquire 100 MW of capacity, in the first of two potential option exercises.

West Riverside is a combined cycle natural gas plant recently completed by an unaffiliated utility in Rock County, Wisconsin.

If approved, our share of the cost of this ownership interest is approximately $91 million, with the transaction expected to close in the second quarter of 2023.

In addition, WPS could exercise a second option to acquire an additional 100 MW of capacity.

If approved, our share of the cost of this ownership interest is expected to be approximately $90 million, with the transaction expected to close in 2024.

In March 2022, the DOC opened an investigation into whether new tariffs should be imposed on solar panels and cells imported from multiple southeast Asian countries.

See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – United States Department of Commerce Complaints and Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Uyghur Forced Labor Prevention Act for information on the potential impacts to our solar projects as a result of the DOC investigation and CBP actions related to solar panels, respectively.

The expected in-service dates identified above already reflect some of these impacts.

WE and WG have received PSCW approval to each construct its own LNG facility.

Each facility would provide approximately one Bcf of natural gas supply to meet anticipated peak demand without requiring the construction of additional interstate pipeline capacity.

These facilities are expected to reduce the likelihood of constraints on WE's and WG's natural gas systems during the highest demand days of winter.

The total cost of both projects is estimated to be approximately $370 million, with approximately half being invested by each utility.

Commercial operation of the WE and WG LNG facilities are targeted for the end of 2023 and 2024, respectively.

PGL is continuing work on the SMP, a project under which PGL is replacing approximately 2,000 miles of Chicago's aging natural gas pipeline infrastructure.

PGL currently recovers these costs through a surcharge on customer bills pursuant to an ICC approved QIP rider, which is in effect through 2023.

After 2023, PGL will return to the traditional ratemaking process to recover the costs of necessary infrastructure improvements.

PGL's projected average annual investment through 2025 is between $280 million and $300 million.

completed by the end of 2026.

Approval for battery capacity at this project was also requested, which is not included in the current capital plan.

We will continue to evaluate the timing, cost, and feasibility of the installation of batteries.

• In December 2023, UMERC filed a request with the MPSC to acquire and construct Renegade, a utility-scale solar-powered electric generating facility.

The project will be located in Delta County, 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 August 2023, the DOC issued a ruling in its investigation into whether new tariffs should be imposed on solar panels and cells imported from multiple southeast Asian countries.

See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – United States Department of Commerce Complaint and Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Uyghur Forced Labor Prevention Act for information on the potential impacts to our solar projects as a result of the DOC ruling and CBP actions related to solar panels, respectively.

The expected in-service dates and costs identified above already reflect some of these impacts.

The construction of additional LNG facilities has been proposed as part of the 2024-2028 capital plan .

The facilities would provide approximately four Bcf of natural gas supply and are expected to reduce the likelihood of constraint s on the natural gas systems during the highest demand days of winter.

The total cost of the projects is estimated to be approximately $860 million .

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.

On January 3, 2024, the ICC granted PGL a limited-scope rehearing, which includes 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 our delivery system.

As a result, PGL has suspended neighborhood work pending the results of the limited hearing.

See Note 26, Regulatory Environment, for more information on the SMP.

The non-utility energy infrastructure line item in the table above includ es WECI's recent and planned investments in Sapphire Sky, Samson I, and Maple Flats.

The non-utility energy infrastructure line item in the table above includ es WECI's previously announced investment in Maple Flats and the purchase in January 2024 of an additional 10% ownership interest in Samson I.

See Note 2, Acquisitions, for more information on these projects.

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We do not expect to make any contributions to ATC Holdco during that period.

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WEC's portion of the cost for MISO Tranche 1 is estimated to be approximately $330 million between 2024 and 2028.

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

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(in millions) Total Less Than 1 Year 1-3 Years 3-5 Years More Than 5 Years

Interest payments on long-term debt (1)

Interest payments due on long-term debt (1)

$ 7,966.6 $ 677.7 $ 1,155.5 $ 899.1 $ 5,234.3

(1) The interest due on our variable rate debt is based on the interest rates that were in effect on December 31, 2023.

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Common Stock Dividends

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In addition to our energy-related purchase obligations, we have commitments for other costs incurred in the normal course of business, including costs related to information technology services, meter reading services, maintenance and other service agreements for certain generating facilities, and various engineering agreements.

Our estimated future cash requirements related to these purchase obligations are reflected below.

Our estimated future cash requirements related to these purchase obligations, excluding energy-related obligations, are reflected below.

Payments Due by Period

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In addition to the above, our balance sheet at December 31, 2023 included various other liabilities that, due to the nature of the liabilities, the amount and timing of future payments cannot be determined with certainty.

These liabilities include AROs, liabilities

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for the remediation of manufactured gas plant sites, and liabilities related to the accounting treatment for uncertainty in income taxes.

These liabilities include AROs, liabilities for the remediation of manufactured gas plant sites, and liabilities related to the accounting treatment for uncertainty in income taxes.

For additional information on these liabilities, see Note 9, Asset Retirement Obligations, Note 24, Commitments and Contingencies, and Note 16, Income Taxes, respectively.

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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 13, Short-Term Debt and Lines of Credit, Note 19, Guarantees, and Note 23, Variable Interest Entities.

See Note 13, Short-Term Debt and Lines of Credit, Note 19, Guarantees, and Note 23, Variable Interest Entities, for more information.

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Sources of Cash

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.

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.

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.

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At December 31, 2023, our current liabilities exceeded our current assets by $2,319.1 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 $1,454.2 million under 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.

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 under 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 13, Short-Term Debt and Lines of Credit, and Note 14, Long-Term Debt, for more information about our credit facilities and debt securities.

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The adjusted presentation attributes $250.0 million of the 2007 Junior Notes to common shareholders' equity and $250.0 million to long-term debt.

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.

The adjusted presentation of our consolidated capitalization structure is included as a complement to our capitalization structure presented in accordance with GAAP.

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Any credit ratings downgrade could impact our ability to access capital markets.

In December 2022, Moody's changed the rating outlook for WG to stable from negative as a result of the rate case decision WG received in December 2022.

Moody's affirmed WG's ratings including its A3 senior unsecured rating and its P-2 short term rating for commercial paper.

See Note 26, Regulatory Environment, for more information on the rate case decision.

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.

On May 2, 2023, S&P Global Inc.

affirmed WEC Energy Group’s ratings and revised its outlook to negative from stable, citing weakening financial measures.

S&P Global Inc.

upgraded WEC Energy Group’s outlook back to stable on November 21, 2023, following their review of our updated five year capital and financing plan.

The factors leading to the upgraded outlook included the maintenance of improving financial metrics and the expected reduction in our exposure to coal fired generation through the rest of the decade.

The ratings outlooks on our utilities remain stable.

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explanation of the significance of these ratings may be obtained from the rating agency.

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.

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The FERC supports large RTOs, which directly impacts the structure of the wholesale electric market.

Due to the FERC's support of RTOs, MISO uses the MISO Energy Markets to carry out its operations, including the use of LMP to value electric transmission congestion and losses.

Due to the FERC's support of RTOs, MISO uses the MISO Energy Markets to carry out its operations, including the use of LMPs to value electric transmission congestion and losses.

Increased competition in the retail and wholesale markets, which may result from restructuring efforts, could have a significant and adverse financial impact on us.

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However, natural gas utilities have customarily avoided competing for existing customers of other utilities, as there would be duplicative utility facilities and/or increased costs to customers.

If this approach were to change, it could lead to a greater level of competition amongst utilities to obtain customers.

If this approach were to change, it could lead to a greater level of competition amongst utilities to obtain customers and potentially adversely impact our results of operations.

MERC offers both natural gas transportation service and interruptible natural gas sales to enable customers to better manage their energy costs.

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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 requires a $15.4 million and $0.7 million refund to ratepayers at PGL and NSG, respectively.

These amounts are being 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.

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 is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency.

In March 2022, PGL filed its 2021 reconciliation with the ICC, which, along with the 2020, 2019, 2018, 2017, and 2016 reconciliations, are still pending.

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.

In March 2023, PGL filed its 2022 reconciliation with the ICC, which, along with the reconciliations from 2016 through 2021, are still pending.

In addition, costs incurred during 2023 under the QIP rider are also still subject to reconciliation and review.

Annual costs included in PGL's QIP rider have ranged from $192 million to $348 million.

As of December 31, 2023, there can be no assurance that all costs incurred under the QIP rider during the open reconciliation years, which include 2016 through 2023, will be deemed recoverable by the ICC.

Disallowances by the ICC, if any, could be material and have a material adverse impact on our results of operations.

See Note 26, Regulatory Environment, for more information regarding recent and pending rate proceedings, orders, and investigations involving our utilities.

Future Illinois Proceedings

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.

In addition, the ICC ordered staff to develop a plan for a "Future of Gas" proceeding.

The goal of this proceeding will be 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 will include 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 will include a broad range of stakeholders, including Illinois utilities and other interested parties.

Once initiated, the “Future of Gas” proceeding is expected to last at least one year.

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 26, 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 on January 24, 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.

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Petitions Before PSCW Regarding Third-Party Financed Distributed Energy Resources

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

On December 1, 2022, the PSCW granted one petitioner’s request for a declaratory ruling, finding that the owner of the third-party financed DER at issue in the petitioner’s brief is not a public utility under Wisconsin law.

In December 2022, the PSCW granted one petitioner’s request for a declaratory ruling, finding that the owner of the third-party financed DER at issue in the petitioner’s brief is not a public utility under Wisconsin law.

The ruling was limited to the specific facts and circumstances of the lease presented in that petition.

A second petition is also being considered.

A petition by the WUA to reopen or rehear the case expired without action by the PSCW.

The WUA has filed an appeal which is pending consideration by the circuit court.

The second petition was denied.

Although the finding in the first petition was limited to the specific facts and circumstances of the lease presented in that petition, similar findings or a broader policy position could adversely impact our business operations.

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On September 15, 2021, the state of Illinois signed into law the Climate and Equitable Jobs Act.

This new legislation includes, among other things, a path for Illinois to move towards 100% clean energy, expanded commitments to energy efficiency and renewable energy, additional consumer protections, and expanded ethics reform.

The provisions in this legislation with the potential to have the most significant financial impact on PGL and NSG relate to the new consumer protection requirements.

This legislation includes, among other things, a path for Illinois to move towards 100% clean energy, expanded commitments to energy efficiency and renewable energy, additional consumer protections, and expanded ethics reform.

The provisions in this legislation that had the potential to have the most significant financial impact on PGL and NSG related to the new consumer protection requirements.

Effective September 15, 2021, the new legislation prohibits utilities from charging customers a fee when they elect to pay for service with a credit card.

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In December 2021, the ICC approved the use of a TPTFA rider for PGL.

The TPTFA rider allows PGL to recover the costs incurred for these third-party transaction fees.

See Note 26, Regulatory Environment, for more information on the rider.

NSG recovers costs related to these third-party transaction fees through its base rates, effective September 15, 2021.

In accordance with the new legislation, effective January 1, 2023, natural gas utilities are also no longer allowed to charge late payment fees to low-income residential customers.

We are currently evaluating the impact this legislation may have on our future results of operations.

The TPTFA rider allowed PGL to recover the costs incurred for these third-party transaction fees prior to them being included in PGL's base rates.

Effective December 1, 2023, PGL began recovering these costs through its base rates.

See Note 26, Regulatory Environment, for more information on the TPTFA rider.

NSG has been recovering costs related to these third-party transaction fees through its base rates since September 15, 2021.

In accordance with the new legislation, effective January 1, 2023, natural gas utilities are no longer allowed to charge late payment fees to certain low-income residential customers.

As a result of the ICC's November 2023 rate orders, we do not expect this legislation to have a significant impact on our results of operations.

Uyghur Forced Labor Prevention Act

The CBP issued a WRO in June 2021, applicable to certain silica-based products originating from the Xinjiang Uyghur Autonomous Region of China (Xinjiang), such as polysilicon, included in the manufacturing of solar panels.

In June 2022, the WRO was superseded by the implementation of the UFLPA, which was signed into law by President Biden in December 2021.

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 compliance requirements, and we expect the same will be true for UFLPA purposes, we cannot currently predict what, if any, impact the UFLPA will have on the overall supply of solar panels into the United States and the related impact to timing and cost of solar projects included in our capital plan.

While our suppliers were able to provide the CBP sufficient documentation to meet WRO compliance requirements, and we expect the same will be true for UFLPA purposes, we cannot currently predict what, if any, long-term impact the UFLPA will have on the overall supply of solar panels into the United States and 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

In February 2022, a California based company filed a petition (Antidumping and Countervailing Duties) with the DOC seeking to impose new tariffs on solar panels and cells imported from multiple countries, including Malaysia, Vietnam, Thailand, and Cambodia.

The petitioners claimed that Chinese solar manufacturers are shifting products to these countries to avoid the tariffs required on products imported from China and requested that the DOC conduct a country-wide inquiry into each of the four countries.

After investigation, in December 2022, the DOC announced its preliminary determination that certain companies are circumventing anti-dumping and countervailing duty orders on solar cells and modules from China.

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United States Department of Commerce Complaints

In August 2021, a group of anonymous domestic solar manufacturers filed a petition (AD/CVD) with the DOC seeking to impose new tariffs on solar panels and cells imported from several countries, including Malaysia, Vietnam, and Thailand.

The petitioners claimed that Chinese solar manufacturers are shifting products to these countries to avoid the tariffs required on products imported from China.

In November 2021, the DOC rejected this petition.

In denying the petition, the DOC cited the anonymous group’s refusal of the DOC’s request to provide more detail and identify its members due to the members' concerns about retribution from the dominant Chinese solar industry.

In February 2022, a California based company filed a petition (AD/CVD) with the DOC seeking to impose new tariffs on solar panels and cells imported from multiple countries, including Malaysia, Vietnam, Thailand, and Cambodia.

While the petition is similar to the one rejected by the DOC in November 2021, there are notable differences.

The group added Cambodia to the petition and requested that the DOC conduct a country-wide inquiry into each of the four countries.

In March 2022, the DOC decided to act on the February petition and investigate the claim.

On December 2, 2022, the DOC announced its preliminary determination that certain companies are circumventing anti-dumping and countervailing duty orders on solar cells and modules from China.

As the next step, the DOC will conduct in-person audits to verify the information that was the basis of the finding.

If the DOC makes a final determination, which is currently expected in the second quarter of 2023, that such circumvention is occurring it would be able to apply any final tariffs retroactively to November 4, 2021.

If imposed, the new tariffs could further disrupt the supply of solar modules to the United States, and could impact the cost and timing of our solar projects.

In June 2022, the Biden Administration used its executive powers to issue a 24-month tariff moratorium on solar panels manufactured in Cambodia, Malaysia, Thailand, and Vietnam.

The moratorium comes as a direct response to concerns raised about the adverse impact from the ongoing DOC complaint on the U.S.

solar industry.

As the DOC will continue its investigation discussed above, companies may still be subject to tariffs after the moratorium ends;

however, U.S.

companies will reportedly be exempt from any retroactive tariffs that previously could have applied.

The Biden Administration also announced that it plans to invoke the Defense Production Act to accelerate the production of solar panels in the U.S.

The Biden Administration's actions did not address whether WROs applied to panels under previous complaints would be affected.

In August 2023, the DOC issued its final decision, substantially affirming its preliminary determination that circumvention was occurring in each of the four Southeast Asian countries noted above.

In its decision, the DOC affirmed that the Biden Administration’s current 24-month tariff moratorium will remain in effect until June 6, 2024, subject to certain use and installation requirements, at which time tariffs are expected to resume.

In December 2023, two U.S.

solar manufacturers filed a challenge to this moratorium in the United States Court of International Trade.

The Biden Administration also invoked the Defense Production Act to accelerate the production of solar panels in the U.S.;

however, the DOC’s ruling 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.

At this time, we do not expect this final ruling to have a material impact on our 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 the next five years, including approximately $85 billion for investments in power, utilities, and renewables infrastructure across the United States.

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.

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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 this new IRA transferability option, we entered into a sales agreement in September 2023 to sell substantially all of our 2023 PTCs to a third party.

See Note 1(q), 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.

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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

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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.

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.

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When two complaints were 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.

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The base ROEs listed in the two ROE complaint sections below do not include the 50 basis point ROE incentive currently provided for membership in a transmission organization.

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The refunds were applied to WE's and WPS's PSCW-approved escrow accounting for transmission expense.

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• Opinion Issued by the D.C.

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Therefore, ATC recorded a liability on its financials for these potential refunds, which reduced our equity earnings from ATC by $18.6 million during the third quarter of 2022.

The liability recorded by ATC is based on a 9.88% base ROE for the first complaint period.

The liability recorded by ATC is based on a 9.88% base

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ROE for the first complaint period.

If it is ultimately determined a refund is required for the first complaint period, we would not expect any such refund to have a material impact on our financial statements or results of operations in the future.

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Environmental Matters

See Note 24, 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.

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See Note 24, Commitments and Contingencies, for a discussion of certain environmental matters affecting us, including rules and regulations relating to air quality, water quality, and land quality.

Market Risks and Other Significant Risks

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Higher commodity costs can increase our working capital requirements, result in higher gross receipts taxes, and lead to increased energy efficiency investments by our customers to reduce utility usage and/or fuel substitution.

Higher commodity costs combined with slower economic conditions also expose us to greater risks of accounts receivable write-offs as more customers are unable to pay their bills.

Higher commodity costs combined

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with slower economic conditions also expose us to greater risks of accounts receivable write-offs as more customers are unable to pay their bills.

See Note 5, Credit Losses, for more information on riders and other mechanisms that allow for cost recovery or refund of uncollectible expense.

Due to the cold temperatures, wind, snow and ice throughout the central part of the country during February 2021, the cost of gas purchased for our natural gas utility customers was temporarily driven higher than our normal winter weather expectations.

As a result of this extreme weather event, we requested approval for the recovery of an additional $322 million of natural gas costs across our service territories, above what was either set as a benchmark in our respective GCRMs or included in rates.

See Note 26, Regulatory Environment, for more information on our recovery efforts associated with these costs.

Our utilities' rates are based upon estimated normal temperatures.

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This sensitivity analysis was performed assuming a constant level of variable rate debt during the period and an immediate increase in interest rates, with no other changes for the remainder of the period.

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Marketable Securities Return

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We consult with our investment advisors on an annual basis to help us forecast expected long-term returns on plan assets by reviewing actual historical returns and calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the funds.

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Economic Conditions

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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 three risk factors below.

For additional information concerning risks related to inflation and supply chain disruptions, see the four risk factors below.

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.

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.

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.

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

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Risk Factors – Risks Related to Economic and Market Volatility – Fluctuating commodity prices could negatively impact our operations.

For additional information concerning other risk factors, including market risks, see the Cautionary Statement Regarding Forward-Looking Information at the beginning of this report and Item 1A.

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If recovery or refund of costs is not approved or is no longer considered probable, these regulatory assets or liabilities are recognized in current period earnings.

Management regularly assesses whether these regulatory assets and liabilities are probable of future recovery or refund by considering factors such as changes in the regulatory environment, earnings from our electric and natural gas utility operations, rate orders issued by our regulators, historical decisions by our regulators regarding regulatory assets and liabilities, and the status of any pending or potential deregulation legislation.

Management regularly assesses whether these regulatory assets and liabilities are probable of future recovery or

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refund by considering factors such as changes in the regulatory environment, earnings from our electric and natural gas utility operations, rate orders issued by our regulators, historical decisions by our regulators regarding regulatory assets and liabilities, and the status of any pending or potential deregulation legislation.

The application of the Regulated Operations Topic of the FASB ASC would be discontinued if all or a separable portion of our utility operations no longer met the criteria for application.

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The fair values for the reporting units were calculated using a combination of the income approach and the market approach.

The income approach received a weighting of 60% while the market approach received a weighting of 40% to determine an overall valuation.

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.

Since all of our reporting units are regulated, a fair recovery of and return on costs prudently incurred to serve customers is assumed.

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.

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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.

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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.

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Examples of events or changes in circumstances include, but are not limited to, a significant decrease in the market price, a significant change in use, a regulatory decision related to recovery of assets from customers, adverse legal factors or a change in business climate, operating or cash flow losses, or an expectation that the asset might be sold or abandoned.

See Note 1(k), Asset Impairment, for our policy on accounting for abandonments.

See Note 1(k), Asset Impairment, for our policy on accounting for abandonments and recently completed plant subject to disallowance.

Performing an impairment evaluation involves a significant degree of estimation and judgment by management in areas such as identifying circumstances that indicate an impairment may exist, identifying and grouping affected assets, and developing the undiscounted future cash flows.

An impairment loss is measured as the excess of the carrying amount of the asset in comparison to the fair value of the asset.

The fair value of the asset is assessed using various methods, including recent comparable third-party sales for our nonregulated operations, internally developed discounted cash flow analysis, expected recovery of regulated assets, and analysis from outside advisors.

The fair value of the asset is assessed using various methods, including recent comparable third-party

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sales for our nonregulated operations, internally developed discounted cash flow analysis, expected recovery of regulated assets, and analysis from outside advisors.

See Note 7, Property, Plant, and Equipment, for more information on our generating units probable of being retired.

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We believe that changes to benefit costs at our other utilities would be recovered or refunded through the ratemaking process.

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The following table shows how a given change in certain actuarial assumptions would impact the projected benefit obligation and the reported net periodic pension cost (including amounts capitalized to our balance sheets).

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We establish our expected return on assets based on consideration of historical and projected asset class returns, as well as the target allocations of the benefit trust portfolios.

The assumed long-term rate of return on pension plan assets was 6.88% in 2022 and 2021, and 6.87% in 2020.

The assumed long-term rate of return on pension plan assets was 6.62% in 2023 and

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6.88% in 2022 and 2021.

The actual rate of return on pension plan assets, net of fees, was 9.23%, (14.03)%, and 9.51%, in 2023, 2022, and 2021, respectively.

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The assumptions involved are supported by historical data, reasonable projections, and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions.

Significant changes in these assumptions could have a material impact on our

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financial condition and results of operations.

Significant changes in these assumptions could have a material impact on our financial condition and results of operations.

See Note 1(q), Income Taxes, and Note 16, Income Taxes, for a discussion of accounting for income taxes.

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis