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Commitments, Guarantees and Contingencies | 12 Months Ended
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Dec. 31, 2023
Commitments and Contingencies Disclosure [Abstract] |
Commitments, Guarantees and Contingencies | COMMITMENTS, GUARANTEES AND CONTINGENCIES The following table details the estimated minimum payments for certain long-term commitments as of December 31, 2023:
| 2024 | 2025 | 2026 | 2027 | 2028 | Thereafter
Millions |  |  |  |  |  |
Capital Purchase Obligations | $73.9 |  | $1.6 |  | $9.9 |  | $38.1 |  | — |  | $10.5 |
Easements (a) | $8.0 |  | $8.1 |  | $8.1 |  | $8.2 |  | $8.4 |  | $217.7 |
PPAs (b) | $140.7 |  | $133.8 |  | $136.6 |  | $125.7 |  | $132.4 |  | $937.5 |
Other Purchase Obligations (c) | $42.9 |  | — |  | — |  | — |  | — |  | — |
(a)Easement obligations represent the minimum payments for our land easement agreements at our wind energy facilities. (b)Does not include the Oliver Wind I, Oliver Wind II or Nobles 2 PPAs, as Minnesota Power only pays for energy as it is delivered. (See Power Purchase Agreements.) (c)Consists of long-term service agreements for wind energy facilities and minimum purchase commitments under coal and rail contracts. Power Purchase and Sales Agreements. Our long-term PPAs have been evaluated under the accounting guidance for variable interest entities. We have determined that either we have no variable interest in the PPAs, or where we do have variable interests, we are not the primary beneficiary; therefore, consolidation is not required. These conclusions are based on the fact that we do not have both control over activities that are most significant to the entity and an obligation to absorb losses or receive benefits from the entity’s performance. Our financial exposure relating to these PPAs is limited to our capacity and energy payments. These agreements have also been evaluated under the accounting guidance for derivatives. We have determined that either these agreements are not derivatives, or, if they are derivatives, the agreements qualify for the normal purchases and normal sales exception to derivative accounting guidance; therefore, derivative accounting is not required. Square Butte PPA. Minnesota Power has a PPA with Square Butte that extends through 2026 (Agreement). Minnesota Power is obligated to pay its pro rata share of Square Butte’s costs based on its entitlement to the output of Square Butte’s 455 MW coal fired generating unit. Minnesota Power’s output entitlement under the Agreement is 50 percent for the remainder of the Agreement, subject to the provisions of the Minnkota Power PSA described in the following table. Minnesota Power’s payment obligation will be suspended if Square Butte fails to deliver any power, whether produced or purchased, for a period of one year. Square Butte’s costs consist primarily of debt service, operating and maintenance, depreciation and fuel expenses. As of December 31, 2023, Square Butte had total debt outstanding of $171.8 million. Annual debt service for Square Butte is expected to be approximately $33.5 million in 2024, $29.5 million in 2025, $29.6 million in 2026, and $11.9 million in 2027 of which Minnesota Power’s obligation is 50 percent. Fuel expenses are recoverable through Minnesota Power’s fuel adjustment clause and include the cost of coal purchased from BNI Energy under a long-term contract. NOTE 9. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued) Power Purchase and Sales Agreements (Continued) Minnesota Power’s cost of power purchased from Square Butte during 2023 was $86.2 million ($82.7 million in 2022; $82.4 million in 2021). This reflects Minnesota Power’s pro rata share of total Square Butte costs based on the 50 percent output entitlement. Included in this amount was Minnesota Power’s pro rata share of interest expense of $5.5 million in 2023 ($5.1 million in 2022; $5.8 million in 2021). Minnesota Power’s payments to Square Butte are approved as a purchased power expense for ratemaking purposes by both the MPUC and the FERC. Minnesota Power has also entered into the following long-term PPAs for the purchase of capacity and energy as of December 31, 2023:
Counterparty | Quantity | Product | Commencement | Expiration | Pricing
PPAs |  |  |  |  |
Calpine Corporation | 25 MW | Capacity | June 2019 | May 2026 | Fixed
Manitoba Hydro |  |  |  |  |
PPA 1 | 250 MW | Capacity / Energy | June 2020 | May 2035 | (a)
PPA 2 | 133 MW | Energy | June 2020 | June 2040 | Forward Market Prices
Nobles 2 | 250 MW | Capacity / Energy | December 2020 | December 2040 | Fixed
Oliver Wind I | (b) | Energy | December 2006 | December 2040 | Fixed
Oliver Wind II | (b) | Energy | December 2007 | December 2040 | Fixed
(a)The capacity price was adjusted annually until 2020 by the change in a governmental inflationary index. The energy price is based on a formula that includes an annual fixed component adjusted for the change in a governmental inflationary index and a natural gas index, as well as market prices. (b)The PPAs provide for the purchase of all output from the 50 MW Oliver Wind I and 48 MW Oliver Wind II wind energy facilities. Minnesota Power has also entered into the following long-term PSAs for the sale of capacity and energy as of December 31, 2023:
Counterparty | Quantity | Product | Commencement | Expiration | Pricing
PSAs |  |  |  |  |
Basin |  |  |  |  |
PSA 1 | (a) | Capacity | June 2022 | May 2025 | Fixed
PSA 2 | 100 MW | Capacity | June 2025 | May 2028 | Fixed
Great River Energy | 100 MW | Capacity | June 2022 | May 2025 | Fixed
Minnkota Power | (b) | Capacity / Energy | June 2014 | December 2026 | (b)
Oconto Electric Cooperative | 25 MW | Capacity / Energy | January 2019 | May 2026 | Fixed
Silver Bay Power | (c) | Energy | January 2017 | December 2031 | (d)
(a)The agreement provided for 75 MW of capacity from June 1, 2022, through May 31, 2023, and increased to 125 MW of capacity from June 1, 2023, through May 31, 2025. (b)Minnesota Power is selling a portion of its entitlement from Square Butte to Minnkota Power, resulting in Minnkota Power’s net entitlement increasing and Minnesota Power’s net entitlement decreasing until Minnesota Power’s share is eliminated at the end of 2025. Of Minnesota Power’s 50 percent output entitlement, it sold to Minnkota Power approximately 37 percent in 2023 (32 percent in 2022 and 28 percent in 2021). (See Square Butte PPA.) (c)Silver Bay Power supplies approximately 90 MW of load to Northshore Mining, an affiliate of Silver Bay Power. (d)The energy pricing escalates at a fixed rate annually and is adjusted for changes in a natural gas index. NOTE 9. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued) Coal, Rail and Shipping Contracts. Minnesota Power has coal supply agreements providing for the purchase of a significant portion of its coal requirements through December 2025. Minnesota Power also has coal transportation agreements in place for the delivery of a significant portion of its coal requirements through December 2024. The costs of fuel and related transportation costs for Minnesota Power’s generation are recoverable from Minnesota Power’s utility customers through the fuel adjustment clause. Environmental Matters. Our businesses are subject to regulation of environmental matters by various federal, state, and local authorities. A number of regulatory changes to the Clean Air Act, the Clean Water Act and various waste management requirements continue to be promulgated by both the EPA and state authorities. Minnesota Power’s facilities are subject to new requirements under many of these regulations. Minnesota Power is reshaping its generation portfolio, over time, to reduce its reliance on coal, has installed cost-effective emission control technology, and advocates for sound science and policy during rulemaking implementation. We consider our businesses to be in substantial compliance with currently applicable environmental regulations and believe all necessary permits have been obtained. We anticipate that with many new and proposed state and federal environmental regulations and requirements, potential expenditures for future environmental matters may be material and require significant capital investments. Minnesota Power has evaluated various environmental compliance scenarios using possible outcomes of environmental regulations to project power supply trends and impacts on customers. We review environmental matters on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated based on current law and existing technologies. Accruals are adjusted as assessment and remediation efforts progress, or as additional technical or legal information becomes available. Accruals for environmental liabilities are included in the Consolidated Balance Sheet at undiscounted amounts and exclude claims for recoveries from insurance or other third parties. Costs related to environmental contamination treatment and cleanup are expensed unless recoverable in rates from customers. Air. The electric utility industry is regulated at the federal and state level to address air emissions. Minnesota Power’s thermal generating facilities mainly burn low-sulfur western sub-bituminous coal. All of Minnesota Power’s coal-fired generating facilities are equipped with pollution control equipment such as scrubbers, baghouses, and low NO X technologies. Under currently applicable environmental regulations, these facilities are substantially compliant with emission requirements. Cross-State Air Pollution Rule (CSAPR). The CSAPR requires certain states in the eastern half of the U.S., including Minnesota, to reduce power plant emissions that contribute to ozone or fine particulate pollution in other states. The CSAPR does not require installation of controls but does require facilities have sufficient allowances to cover their emissions on an annual basis. These allowances are allocated to facilities from each state’s annual budget and can be bought and sold. Based on review of the NO X and SO 2 allowances issued and pending issuance, as well as consideration of current rules, we currently expect generation levels and emission rates will result in continued compliance with the CSAPR. Minnesota Power will continue to monitor ongoing CSAPR rulemakings and compliance implementation, including the EPA’s Good Neighbor Rule which modifies certain aspects of the CSAPR’s program scope and extent (see EPA Good Neighbor Plan for 2015 Ozone NAAQS). National Ambient Air Quality Standards (NAAQS). The EPA is required to review the NAAQS every five years. If the EPA determines that a state’s air quality is not in compliance with the NAAQS, the state is required to adopt plans describing how it will reduce emissions to attain the NAAQS. Minnesota Power actively monitors NAAQS developments, and the EPA is currently reviewing the primary or secondary NAAQS for NO x, SO 2, and ozone. On February 7, 2024, the EPA announced a final rule lowering the annual primary standard for particulate matter less than 2.5 microns (PM 2.5) from 12 micrograms per cubic meter (ug/m 3) to 9 ug/m 3, while retaining other existing primary and secondary standards such as those for course particulate matter. The Company is reviewing the new standard to determine potential impacts. Anticipated timelines and compliance costs related to this new standard and other expected NAAQS revisions cannot yet be fully estimated; however, costs could be material. Minnesota Power would seek recovery of additional costs through a rate proceeding. NOTE 9. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued) Environmental Matters (Continued) EPA Good Neighbor Plan for 2015 Ozone NAAQS. On June 5, 2023, after disapproving state implementation plans, the EPA published a final Federal Implementation Plan (FIP) rule in the Federal Register, the Good Neighbor Plan, to address regional ozone transport for the 2015 Ozone NAAQS by reducing NOx emissions during the period of May 1 through September 30 (ozone season). In its justification for the final rule, the EPA asserted that 23 states, including Minnesota, were modeled as significant contributors to downwind states’ challenges in attaining or maintaining ozone NAAQS compliance. The Good Neighbor Plan is designed to resolve this interstate transport issue by implementing a variety of NOx reduction strategies, including federal implementation plan requirements, NOx emission limitations, and ozone season allowance program requirements. The final rule imposed restrictions on fossil-fuel fired power plants in 22 states and on certain industrial sources in 20 states, with implementation occurring through changes to the existing CSAPR program for power plants. Since the EPA partially disapproved the Good Neighbor State Implementation Plans (SIPs) for the states of Minnesota and Wisconsin, among others, Minnesota is subject to the final Good Neighbor Plan. However, Minnesota Power and a coalition of other Minnesota utilities and industry (the parties) co-filed challenges to the EPA’s final Minnesota SIP disapproval, submitting a petition for reconsideration and stay to the EPA, and a petition for judicial review to the U.S. Court of Appeals for the Eighth Circuit (Eighth Circuit Court). The parties are challenging and requesting reconsideration of certain technical components of the EPA’s review and subsequent partial disapproval of Minnesota’s SIP. On July 5, 2023, the Eighth Circuit Court granted the stay preventing the Good Neighbor Plan from taking effect in Minnesota. On September 29, 2023, the EPA issued an updated final interim rule addressing the stays in Minnesota and five other states, formally delaying the effective date of the final FIP for states with active stays in place. The state of Minnesota was therefore not subject to compliance obligations for the 2023 ozone season. Future compliance obligations will depend on resolution of the stay. Additionally, challenges have been filed against the final FIP rule by the Minnesota coalition parties and other entities, although the Minnesota coalition FIP challenge is currently in abeyance pending resolution of the SIP disapproval case. In February 2024, the U.S. Supreme Court will hear arguments from several states and industry groups requesting a national stay of the FIP rule. Anticipated compliance costs related to final Good Neighbor Plan compliance cannot yet be estimated due to uncertainties about SIP approval resolution, implementation timing, FIP rule outcome, and allowance costs and facility emissions during the ozone season. However, the costs could be material, including costs of additional NO x controls, emission allowance program participation, or operational changes, if any are required. Minnesota Power would seek recovery of additional costs through a rate proceeding. EPA National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial and Institutional Boilers and Process Heaters (Industrial Boiler MACT) Rule. A final rule issued by the EPA for Industrial Boiler MACT became effective in 2013 with compliance required at major existing sources in 2016, which applied to Minnesota Power’s Hibbard Renewable Energy Center and Rapids Energy Center. Compliance consisted largely of adjustments to fuels and operating practices and compliance costs were not material. After this initial rulemaking, litigation from 2016 through 2018 resulted in court orders directing that the EPA reconsider certain aspects of the regulation. A final rule incorporating these revisions became effective in December 2022, with a compliance deadline of October 6, 2025. Compliance costs are not expected to be material. EPA Mercury and Air Toxics Standards (MATS) Rule. On April 24, 2023, the EPA published a proposed revision to the existing MATS Rule as part of its mandatory 2020 MATS review. In this proposed rule, the EPA is proposing to alter certain compliance and operational requirements, and to lower several emission limits. Compliance would be required in the 2026 to 2027 timeframe. The EPA expects to issue the final rule in April 2024. The MATS regulation applies at Minnesota Power’s Boswell Energy Center, which is currently well-controlled for these emissions and is in full compliance with existing requirements. Compliance costs cannot yet be estimated; however, recovery of any additional costs would be sought through a rate proceeding. NOTE 9. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued) Environmental Matters (Continued) Climate Change. The scientific community generally accepts that emissions of GHGs are linked to global climate change which creates physical and financial risks. Physical risks could include but are not limited to: increased or decreased precipitation and water levels in lakes and rivers; increased or other changes in temperatures; increased risk of wildfires; and changes in the intensity and frequency of extreme weather events. These all have the potential to affect the Company’s business and operations. We are addressing climate change by taking the following steps that also ensure reliable and environmentally compliant generation resources to meet our customers’ requirements: •Expanding renewable power supply for both our operations and the operations of others; •Providing energy conservation initiatives for our customers and engaging in other demand side management efforts; •Improving efficiency of our generating facilities; •Supporting research of technologies to reduce carbon emissions from generating facilities and carbon sequestration efforts; •Evaluating and developing less carbon intensive future generating assets such as efficient and flexible natural gas fired generating facilities; •Managing vegetation on right-of-way corridors to reduce potential wildfire or storm damage risks; and •Practicing sound forestry management in our service territories to create landscapes more resilient to disruption from climate-related changes, including planting and managing long-lived conifer species. EPA Regulation of GHG Emissions. On May 23, 2023, the EPA published in the Federal Register proposed regulatory actions under Section 111 of the Clean Air Act (CAA) addressing greenhouse gas (GHG) emissions from fossil fuel-fired electric generating units (EGUs). The EPA is proposing to revise new source performance standards (NSPS) for new, modified and reconstructed EGUs (Section 111(b) of the CAA) as well as emission guidelines for certain existing (Section 111(d) of the CAA) EGUs. The EPA is also proposing in this action to officially repeal the predecessor regulation “Affordable Clean Energy Rule”, first issued in 2019 and later vacated in 2021. The EPA’s Fall 2023 unified agenda identifies the EPA’s goal of issuing final regulations in April 2024. The Company will continue to monitor this GHG rulemaking and analyze potential impacts to existing and proposed thermal generating facilities. The rule would apply to several Company assets including existing EGUs at Boswell and Laskin as well as the proposed combined cycle natural gas-fired generating facility, NTEC. Minnesota Power continues implementing its Energy Forward strategic plan that provides for significant emissions reductions and diversifying its electricity generation mix to include more renewable and natural gas energy. We are unable to predict compliance costs due to the draft status of the rules and the need for a state implementation plan for Section 111(d) existing units; however, the costs could be material. Minnesota Power would seek recovery of additional costs through a rate proceeding. Water. The Clean Water Act requires NPDES permits be obtained from the EPA or delegated state agency for any wastewater discharged to navigable waters. Minnesota Power has obtained all necessary NPDES permits, including NPDES storm water permits, for applicable facilities to conduct operations. Steam Electric Power Generating Effluent Limitations Guidelines. In 2015, the EPA issued revised federal Effluent Limitation Guidelines (ELG) for steam electric power generating stations under the Clean Water Act. The ELG set effluent limits and prescribed best available control technology for several wastewater streams, including flue gas desulphurization (FGD) water, bottom ash transport water (BATW) and coal combustion landfill leachate. On October 13, 2020, the EPA published a final ELG Rule allowing re-use of bottom ash transport water in FGD scrubber systems and limited discharge for maintaining system water balance. The rule set technology standards and numerical pollutant limits for discharges of BATW and FGD wastewater. Compliance deadlines depend on subcategory, with compliance generally required as soon as possible, beginning after October 13, 2021, but no later than December 31, 2025, or December 31, 2028, in some specific cases. On March 29, 2023, the EPA published a proposed new ELG rule in the Federal Register to update the 2020 ELGs. In the proposed rule, the EPA is revising ELGs for existing sources, including establishing zero discharge limitations for BATW and FGD wastewater; new limits for combustion residual leachate; and allowing states to set discharge limits for legacy wastewater in surface impoundments. The rule proposes to maintain exemptions for units permanently ceasing coal combustion by 2028 and adds a new subcategory for units that have already complied with either the 2015 or 2020 ELG rules and which will retire by 2032. The EPA plans to publish a final ELG rule in April 2024. NOTE 9. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued) Environmental Matters (Continued) ELG revisions are not expected to have a significant impact on Minnesota Power operations. Boswell, where these ELGs are applicable, completed conversion to dry bottom ash handling and installed a FGD dewatering system in September 2022. The dry conversion projects eliminated bottom ash transport water and minimized wastewater from the FGD system. Re-use and onsite consumption are planned for the remaining BATW and FGD waste stream and for dewatering legacy wastewater from Boswell’s existing impoundments. The EPA’s reconsideration of legacy wastewater and leachate discharge requirements has the potential to impact dewatering associated with the closed impoundment at Laskin and the closed Taconite Harbor dry ash landfill. At this time, we estimate no additional material compliance costs for ELG, BATW and FGD requirements. Compliance costs we might incur related to other ELG waste streams (e.g., leachate) or other potential future water discharge regulations at Minnesota Power facilities cannot be estimated; however, the costs could be material, including costs associated with wastewater treatment and re-use. Minnesota Power would seek recovery of additional costs through a rate proceeding. Permitted Water Discharges – Sulfate. In 2017, the MPCA released a draft water quality standard in an attempt to update Minnesota’s existing 10 mg/L sulfate limit for waters used for the production of wild rice with the proposed rulemaking heard before an administrative law judge (ALJ). In 2018, the ALJ rejected significant portions of the proposed rulemaking and the MPCA subsequently withdrew the rulemaking. The existing 10 mg/L limit remains in place, but the MPCA is currently prohibited under state law from listing wild rice waters as impaired or requiring sulfate reduction technology. The federal Clean Water Act requires the MPCA to update the state's impaired water list every two years. Beginning in 2021 through the latest draft proposed on November 14, 2023, this list now includes Minnesota lakes and streams identified as wild rice waters that are listed for sulfate impairment. The list could subsequently be used to set sulfate limits in discharge permits for power generation facilities and municipal and industrial customers, including paper and pulp facilities, and mining operations. At this time, we are unable to determine the specific impacts these developments may have on Minnesota Power operations or its customers, if any. Minnesota Power would seek recovery of additional costs through a rate proceeding. Solid and Hazardous Waste. The Resource Conservation and Recovery Act (RCRA) regulates the management and disposal of solid and hazardous wastes. Minnesota Power is required to notify the EPA of hazardous waste activity and routinely submit reports to the EPA. Coal Ash Management Facilities. Minnesota Power produces the majority of its coal ash at Boswell, with small amounts of ash generated at Hibbard Renewable Energy Center. Ash storage and disposal methods include storing ash in clay-lined onsite impoundments (ash ponds), disposing of dry ash in a lined dry ash landfill, applying ash to land as an approved beneficial use, and trucking ash to state permitted landfills. Coal Combustion Residuals from Electric Utilities (CCR). In 2015, the EPA published a final rule (2015 Rule) regulating CCR as nonhazardous waste under Subtitle D of the Resource Conservation and Recovery Act (RCRA) in the Federal Register. The rule included requirements for new landfill and impoundment construction as well as closure activities related to certain existing impoundments. Costs of compliance for Boswell and Laskin are expected to be incurred primarily over the next 12 years and be between approximately $65 million and $120 million. Compliance costs for CCR at Taconite Harbor are not expected to be material. Minnesota Power would seek recovery of additional costs through a rate proceeding. Minnesota Power continues to work on minimizing compliance costs through evaluation of beneficial re-use and recycling of CCR. In 2018, a U.S. District Court for the District of Columbia decision vacated specific provisions of the CCR rule, which resulted in a change to the status of several existing clay-lined impoundments at Boswell being considered unlined. In September 2020, the EPA finalized the CCR Part A Rule, which required all unlined impoundments to cease disposal and initiate closure. Upon completion of dry ash conversion activities, Boswell ceased disposal in both impoundments in September 2022. Both impoundments are now inactive and have initiated closure. NOTE 9. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued) Environmental Matters (Continued) On May 17, 2023, the EPA released a proposed rule for CCR legacy surface impoundments. The proposal expands the scope of units regulated under the CCR rule to include legacy ponds (inactive surface impoundments at inactive facilities) and creates a new category of units called CCR management units, which includes inactive and closed impoundments and landfills as well as other non-containerized accumulations of CCR. The proposed rule was published in the Federal Register on May 18, 2023. The EPA is proposing to require that generating facilities evaluate and identify all past deposits of CCR materials on their sites and close or re-close existing CCR units to meet current closure standards, as well as install groundwater monitoring systems, conduct groundwater monitoring, and implement groundwater corrective actions as necessary. A final rule is expected in April 2024. This rule has the potential to impact Boswell and Laskin. Compliance costs for Minnesota Power facilities cannot be estimated at this time; however, the costs could be material. Minnesota Power would seek recovery of additional costs through a rate proceeding. Additionally, the EPA released a proposed CCR Part B rulemaking in February 2020 addressing options for beneficial reuse of CCR materials. The final Part B rule expected in late 2024. The final CCR federal permit rule is expected in the first half of 2026. The final federal permit rule will finalize procedures for implementing a CCR federal permit program. Other Environmental Matters Manufactured Gas Plant Site. We are reviewing and addressing environmental conditions at a former manufactured gas plant site located in Superior, Wisconsin, and formerly operated by SWL&P. SWL&P has been working with the Wisconsin Department of Natural Resources (WDNR) in determining the extent and location of contamination at the site and surrounding properties. As of December 31, 2023, we have recorded a liability of $1 million for remediation costs at this site. SWL&P has recorded remediation costs for the site as an associated regulatory asset as we expect recovery of these remediation costs to be allowed by the PSCW. Other Matters We have multiple credit facility agreements in place that provide the ability to issue standby letters of credit to satisfy our contractual security requirements across our businesses. As of December 31, 2023, we had $149.8 million of outstanding letters of credit issued, including those issued under our revolving credit facility. We do not believe it is likely that any of these outstanding letters of credit will be drawn upon. Regulated Operations. As of December 31, 2023, we had $24.2 million outstanding in standby letters of credit at our Regulated Operations which are pledged as security to MISO, the NDPSC and a state agency. ALLETE Clean Energy. ALLETE Clean Energy is party to PSAs that expire in various years between 2024 and 2039. As of December 31, 2023, ALLETE Clean Energy has $91.6 million outstanding in standby letters of credit, the majority of which are pledged as security under these PSAs. Corporate and Other. BNI Energy. As of December 31, 2023, BNI Energy had surety bonds outstanding of $82.4 million related to the reclamation liability for closing costs associated with its mine and mine facilities. Although its coal supply agreements obligate the customers to provide for the closing costs, additional assurance is required by federal and state regulations. BNI Energy’s total reclamation liability is currently estimated at $82.1 million. BNI Energy does not believe it is likely that any of these outstanding surety bonds will be drawn upon. Investment in Nobles 2. Nobles 2 wind energy facility requires standby letters of credit as security for certain contractual obligations. As of December 31, 2023, ALLETE South Wind has $10.1 million outstanding in standby letters of credit, related to our portion of the security requirements relative to our ownership in Nobles 2. NOTE 9. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued) Other Matters (Continued) South Shore Energy. As of December 31, 2023, South Shore Energy had $23.9 million outstanding in standby letters of credit pledged as security in connection with the development of NTEC. ALLETE Properties. As of December 31, 2023, ALLETE Properties had surety bonds outstanding to governmental entities totaling $2.0 million primarily related to development and maintenance obligations for various projects. The estimated cost of the remaining development work is $1.0 million. ALLETE Properties does not believe it is likely that any of these outstanding surety bonds will be drawn upon. Community Development District Obligations. In 2005, the Town Center District issued $26.4 million of tax-exempt, 6.0 percent capital improvement revenue bonds. The capital improvement revenue bonds are payable over 31 years (by May 1, 2036) and are secured by special assessments on the benefited land. To the extent that ALLETE Properties still owns land at the time of the assessment, it will incur the cost of its portion of these assessments, based upon its ownership of benefited property. As of December 31, 2023, we owned 33 percent of the assessable land in the Town Center District (42 percent as of December 31, 2022). As of December 31, 2023, ownership levels, our annual assessments related to capital improvement and special assessment bonds for the ALLETE Properties project within the district is approximately $0.7 million. As we sell property at this project, the obligation to pay special assessments will pass to the new landowners. In accordance with accounting guidance, these bonds are not reflected as debt on our Consolidated Balance Sheet. Legal Proceedings. We are involved in litigation arising in the normal course of business. Also in the normal course of business, we are involved in tax, regulatory and other governmental audits, inspections, investigations and other proceedings that involve state and federal taxes, safety, and compliance with regulations, rate base and cost of service issues, among other things. We do not expect the outcome of these matters to have a material effect on our financial position, results of operations or cash flows. In the first quarter of 2023, an ALLETE Clean Energy subsidiary initiated arbitration proceedings seeking damages against a counterparty for non-performance under a contract. Arbitration hearings were held in June and July 2023, and a final arbitration ruling was issued in favor of ALLETE Clean Energy’s subsidiary in September 2023. The final arbitration ruling awarded $68.3 million to ALLETE Clean Energy’s subsidiary, which included prejudgment interest of $5.1 million, recovery of $3.6 million of arbitration-related costs, and resulted in the recognition of a $58.4 million pre-tax gain in the third quarter of 2023. The arbitration ruling also resulted in the receipt of approximately $60 million of cash, net of distribution to non-controlling interest, in the third quarter of 2023.

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