In accordance with their rate orders approved by the PSCW in December 2022, WE, WPS, and WG filed requests for limited electric and natural gas rate case re-openers, as applicable, with the PSCW in May 2023. The WE and WPS limited electric rate case re-openers included updated fuel costs and revenue requirements for the generation projects that were previously approved by the PSCW and were placed into service in 2023 or are expected to be placed into service in 2024. WE's limited electric re-opener also included the projected savings from the retirement of the OCPP Units 5 and 6, which are expected to be retired in May 2024. WE and WG also filed a request for a limited natural gas rate case re-opener to reflect the additional revenue requirements associated with their previously approved LNG projects. WE's LNG project was placed into service in November 2023, and WG's LNG project is expected to be placed into service in 2024.

In April 2022, WE, WPS, and WG filed requests with the PSCW to increase their retail electric, natural gas, and steam rates, as applicable. These requests were updated in July 2022 to reflect new developments that impacted the original proposals. The requested increases in electric rates were driven by capital investments in new wind, solar, and battery storage; capital investments in natural gas generation; reliability investments, including grid hardening projects to bury power lines and strengthen WE's distribution system against severe weather; and changes in wholesale business with other utilities. Many of these investments had already been approved by the PSCW. The requested increases in natural gas rates primarily related to capital investments previously approved by the PSCW, including LNG storage for our natural gas distribution system.

In September 2022, WE, WPS, and WG entered into settlement agreements with certain intervenors to resolve most of the outstanding issues in each utility's respective rate case; however, the PSCW declined to approve the settlement agreements. In December 2022, the PSCW issued final written orders approving electric, natural gas, and steam base rate increases, effective January 1, 2023. The final orders reflected the following:


	WE					WPS					WG
2023 base rate increase
Electric	$	283.5	million	/	9.1%	$	120.5	million	/	9.8%	N/A
Gas	$	46.1	million	/	9.6%	$	26.4	million	/	7.1%	$	46.5	million	/	6.4%
Steam	$	7.6	million	/	35.3%	N/A					N/A
ROE	9.8%					9.8%					9.8%
Common equity component average on a financial basis	53.0%					53.0%					53.0%

•The utilities will keep their current earnings sharing mechanisms, under which, if a utility earns above its authorized ROE: (i) the utility retains 100.0% of earnings for the first 15 basis points above the authorized ROE; (ii) 50.0% of the next 60 basis points is refunded to ratepayers; and (iii) 100.0% of any remaining excess earnings is required to be refunded to ratepayers.

•WE and WPS will continue to work with PSCW staff and other interested parties to develop alternative low income assistance programs. WE and WPS also collectively contributed $4.0 million to the Keep Wisconsin Warm Fund.

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

•WE, WPS, and WG maintained their earnings sharing mechanisms for 2022, with modification. The earnings sharing mechanisms were modified to authorize the utility to retain 100.0% of the first 15 basis points of earnings above its then authorized ROE. The earnings sharing mechanisms otherwise remained as previously authorized.

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


	WE					WPS					WG
2020 Effective rate increase (decrease)
Electric (1) (2)	$	15.3	million	/	0.5%	$	15.8	million	/	1.6%	N/A
Gas (3)	$	10.4	million	/	2.8%	$	4.3	million	/	1.4%	$	(1.5)	million	/	(0.2)%
Steam	$	1.9	million	/	8.6%	N/A					N/A

ROE	10.0%					10.0%					10.2%

Common equity component average on a financial basis	52.5%					52.5%					52.5%

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

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

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

In accordance with its rate order, WE filed an application with the PSCW in July 2020 requesting a financing order to securitize $100 million of Pleasant Prairie power plant's book value, plus the carrying costs accrued on the $100 million during the securitization process and the related financing fees. In November 2020, the PSCW issued a written order approving the application. The financing order also authorized WE to form a bankruptcy-remote special purpose entity, WEPCo Environmental Trust, for the sole purpose of issuing ETBs to recover the approved costs. In May 2021, WEPCo Environmental Trust issued $118.8 million of

The WPS rate order allows WPS to collect the previously deferred revenue requirement for ReACT™ costs above the authorized $275 million level. The total cost of the ReACT™ project was $342 million. This regulatory asset is being collected from customers over eight years.

The PSCW approved all three Wisconsin utilities continuing to have an earnings sharing mechanism through 2021. The earnings sharing mechanism was modified from its previous structure to one that was consistent with other Wisconsin investor-owned utilities. Under this earnings sharing mechanism, if the utility earned above its authorized ROE: (i) the utility retained 100.0% of earnings for the first 25 basis points above the authorized ROE; (ii) 50.0% of the next 50 basis points were required to be refunded to customers; and (iii) 100.0% of any remaining excess earnings were required to be refunded to customers. In addition, the rate orders also required WE, WPS, and WG to maintain residential and small commercial electric and natural gas customer fixed charges at previously authorized rates and to maintain the status quo for WE's and WPS's electric market-based rate programs for large industrial customers through 2021.

On January 6, 2023, PGL and NSG filed requests with the ICC to increase their natural gas base rates. The requested rate increases were primarily driven by capital investments made to strengthen the safety and reliability of each utility’s natural gas distribution system. PGL was also seeking to recover costs incurred to upgrade its natural gas storage field and operations facilities and to continue improving customer service. PGL did not request an extension of the QIP rider as PGL will return to the traditional rate making process to recover the costs of necessary infrastructure improvements.

On November 16, 2023, the ICC issued final written orders approving base rate increases for PGL and NSG. The written orders were subsequently amended for various technical corrections. The amended written orders approved the following base rate increases:

•A $304.6 million (43.5%) base rate increase for PGL’s natural gas customers. This amount includes the recovery of costs related to PGL’s SMP that were previously being recovered under its QIP rider. PGL's new rates were effective December 1, 2023.

•An $11.0 million (11.6%) base rate increase for NSG’s natural gas customers. The new rates at NSG were not effective until February 1, 2024 as changes were required to NSG's billing system as a result of the final rate order.

As part of its decisions, the ICC, among other things, disallowed $236.2 million of capital costs related to the construction and improvement of PGL’s shops and facilities and $1.7 million of capital costs related to NSG's construction of a gas infrastructure project. In addition, the ICC ordered PGL to pause spending on its SMP until the ICC has a proceeding to determine the optimal method for replacing aging natural gas infrastructure and a prudent investment level. In accordance with the written order, the ICC initiated the proceeding on January 31, 2024.

On December 15, 2023, PGL and NSG filed an application for rehearing with the ICC requesting reconsideration of various issues in the ICC's November 16, 2023 written orders. On January 3, 2024, the ICC granted PGL and NSG a limited-scope rehearing. The rehearing will be limited to:

As the ICC did not grant a rehearing on the disallowance of PGL's and NSG's capital costs, we recorded a $178.9 million non-cash impairment of our property, plant, and equipment in 2023. This amount includes $177.2 million of previously incurred disallowed costs at PGL related to its shops and facilities, and the $1.7 million of capital costs disallowed at NSG. The remaining disallowance of capital costs at PGL related to expected future spend. We anticipate appealing the ICC’s disallowance of PGL's and NSG's capital costs to the Illinois circuit court after the rehearing process is complete.

In accordance with the Climate and Equitable Jobs Act that was signed into law in Illinois, effective September 15, 2021, Illinois utilities are prohibited from charging customers a fee when they elect to pay for service with a credit card. Utilities are now required to incur these expenses and seek recovery through a rate proceeding or by establishing a recovery mechanism. In December 2021, the ICC approved the use of a TPTFA rider for PGL. The TPTFA rider allowed PGL to recover the costs incurred for these third-party transaction fees prior to them being included in base rates. PGL began recovering costs under the rider on February 1, 2022. Amounts deferred under the rider were being recovered over a period of 12 months and are subject to an annual reconciliation whereby costs are reviewed by the ICC for accuracy and prudency. Effective December 1, 2023, PGL discontinued its use of the TPTFA rider and began recovering costs related to these third-party transaction fees through its base rates. NSG began recovering these costs through its base rates, effective September 15, 2021.

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

In July 2013, Illinois Public Act 98-0057, The Natural Gas Consumer, Safety & Reliability Act, became law. This law provides natural gas utilities with a cost recovery mechanism that allows collection, through a surcharge on customer bills, of prudently incurred costs to upgrade Illinois natural gas infrastructure. In January 2014, the ICC approved a QIP rider for PGL, which was in effect until December 1, 2023. As discussed above, PGL has returned to the traditional rate-making process for recovery of these costs, and they are now included in PGL's base rates.

Costs previously incurred under PGL's QIP rider are still subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. In March 2023, PGL filed its 2022 reconciliation with the ICC, which, along with the reconciliations from 2016 through 2021, are still pending. Annual costs included in the rider have ranged from $192 million to $348 million.

As of December 31, 2023, there can be no assurance that all costs incurred under PGL's 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.

In November 2022, MERC initiated a rate proceeding with the MPUC to increase its retail natural gas base rates. In December 2022, the MPUC approved MERC's request for interim rates totaling $37.0 million, subject to refund. The interim rates went into effect on January 1, 2023.

On November 14, 2023, the MPUC issued a written order approving a settlement agreement MERC reached with certain intervenors. The settlement agreement reflects a natural gas base rate increase of $28.8 million (7.1%), along with a 9.65% ROE and a common equity component average of 53.0%. The natural gas rate increase was primarily driven by increased capital investments as well as inflationary pressure on operating costs. Under the terms of the settlement agreement, MERC will continue the use of its decoupling mechanism for residential customers, and it will be expanded to include certain small commercial and industrial customers. Final rates will be effective March 1, 2024.

MERC’s customers are entitled to a refund to the extent the interim rate increase exceeded the final approved rate increase. As of December 31, 2023, MERC had recorded a regulatory liability of $8.5 million for refunds due to customers. These amounts will be refunded to customers during the second quarter of 2024.

On December 28, 2023, MGU provided notification to the MPSC of its intent to file an application requesting an increase to its natural gas rates. The application is expected to be filed in March 2024 and to request new rates be effective January 1, 2025. MGU is currently in the process of evaluating its rate request.

In March 2023, MGU filed a request with the MPSC to increase its retail natural gas base rates. In August 2023, the MPSC issued a written order approving a comprehensive settlement that resolved all issues in MGU's rate case. The key terms of the settlement agreement include:

The rate increase was primarily driven by capital investments made to strengthen the safety and reliability of MGU's natural gas distribution system and to provide service to additional customers. Inflationary pressure on operating costs also contributed to the rate increase. The new rates were effective January 1, 2024.

In February 2020, MGU provided notification to the MPSC of its intent to file an application requesting an increase to MGU's natural gas rates to be effective January 1, 2021. However, MGU decided that it would delay its filing of the rate case as a result of the Coronavirus Disease – 2019 pandemic.

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

In March 2021, MGU filed its request with the MPSC to increase its natural gas rates. In September 2021, the MPSC issued a written order approving a settlement agreement MGU reached with certain intervenors. The order authorized a rate increase of $9.3 million (6.35%) and reflected a 9.85% ROE and a common equity component average of 51.5%. The natural gas rate increase was primarily driven by MGU's significant investment in capital infrastructure since its previous rate review that resulted in revised base rates effective January 1, 2016. The order also allowed MGU to implement a rider for its MRP, which supports recovery of planned capital investment related to pipeline replacements to maintain system safety and reliability between 2023 and 2027, without having to file a rate case. All costs recovered through the rider are subject to a prudence review by the MPSC. The new rates were effective January 1, 2022.

On December 28, 2023, UMERC provided notification to the MPSC of its intent to file an application requesting an increase to its electric rates. The application is expected to be filed in March 2024 and to request new rates be effective January 1, 2025. UMERC is currently in the process of evaluating its rate request.

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

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

PGL and NSG incurred approximately $131 million and $10 million, respectively, of natural gas costs in February 2021 in excess of the amounts included in their rates. These costs were recovered over a period of 12 months, which started on April 1, 2021. PGL's and NSG's natural gas costs were reviewed for prudency by the ICC as part of their annual natural gas cost reconciliation. In January 2023, the ICC issued written orders approving each company's 2021 reconciliation.

In February 2021, MERC incurred approximately $75 million of natural gas costs in excess of the benchmark set in its GCRM. In August 2021, the MPUC issued a written order approving a joint proposal filed by MERC and four other Minnesota utilities to recover their respective excess natural gas costs. In accordance with the order, MERC recovered $10 million of these costs through its annual natural gas true-up process over a period of 12 months, and the remaining $65 million was to be recovered over a period of 27 months, both beginning in September 2021. Recovery of these costs and the issue of prudence was referred to a contested-case proceeding. In October 2022, the MPUC issued a written order approving a settlement agreement entered into by MERC and various parties related to the recovery of the extraordinary natural gas costs incurred in February 2021. Under the settlement agreement, MERC agreed to not seek recovery of $3 million of these costs. MERC substantially recovered the remaining $62 million of extraordinary natural gas costs over the previously approved 27-month recovery period.