| Commitments, Guarantees and Contingencies | COMMITMENTS, GUARANTEES AND CONTINGENCIES Power Purchase and Sale 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. Our PPAs are summarized in Note 9. Commitments, Guarantees and Contingencies to the Consolidated Financial Statements in our 2023 Form 10-K, with additional disclosure provided in the following paragraphs. Square Butte PPA. As of March 31, 2024, Square Butte had total debt outstanding of $162.6 million. 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. Minnesota Power’s cost of power purchased from Square Butte during the three months ended March 31, 2024, was $22.9 million ($22.1 million for the same period in 2023). 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 $1.3 million ($1.3 million for the same period in 2023). Minnesota Power’s payments to Square Butte are approved as a purchased power expense for ratemaking purposes by both the MPUC and the FERC. Minnkota Power PSA. Minnesota Power has a PSA with Minnkota Power, which commenced in 2014. Under the PSA, 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, Minnesota Power sold to Minnkota Power approximately 41 percent in 2024 and 37 percent in 2023. 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 have been promulgated by both the EPA and state authorities over the past several years. Minnesota Power’s facilities are subject to additional 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 state and federal environmental regulations and requirements finalized, or to be finalized in the near future, 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 both 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. NOTE 6. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued) Environmental Matters (Continued) 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 our 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 fine particulate matter while retaining other existing primary and secondary standards such as those for coarse 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 potential NAAQS revisions cannot yet be estimated; however, costs could be material. Minnesota Power would seek recovery of additional costs through a rate proceeding. 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 within their state borders. 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 the state of Minnesota’s SIP. On July 5, 2023, the Eighth Circuit Court granted a stay of the SIP disapproval preventing the Good Neighbor Plan from taking effect in Minnesota. On March 28, 2024, the EPA issued a partial denial of several administrative reconsideration and stay petitions, including from the Minnesota coalition. 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. On February 21, 2024, the U.S. Supreme Court heard 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. NOTE 6. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued) Environmental Matters (Continued) 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 25, 2024, the EPA published a final rule to revise the existing 2012 MATS Rule, which regulates air emissions of hazardous air pollutants from coal- and oil-fired electric generating units (EGUs). The final rule eliminates certain MATS compliance flexibility, lowers the particulate emission standard for all coal-fired EGUs, and reduces the mercury emission standard for lignite-fired EGUs. The rule will become effective 60 days after publication in the Federal Register , with compliance beginning in 2027. The MATS regulation applies at Minnesota Power’s Boswell facility, which is currently well-controlled for these emissions and already complying with some of the new requirements. The Company is analyzing the new rule but anticipates that its impacts to Boswell may be minimal. However, compliance costs cannot yet be estimated, and recovery of any additional costs would be sought through a rate proceeding. 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 April 25, 2024, the EPA issued several final greenhouse gas regulations to establish emissions standards and guidelines for fossil fuel-fired electric generating units (EGUs) under Section 111 of the Clean Air Act (CAA). The final rules revise new source performance standards (NSPS) for new, modified and reconstructed EGUs (Section 111(b) of the CAA) and creates new emission guidelines for existing EGUs (Section 111(d) of the CAA). The action also officially repeals the predecessor regulation “Affordable Clean Energy Rule”, first issued in 2019 and later vacated in 2021. Compliance will be required beginning January 1, 2030 for existing sources, and upon commencing operation of new units. The 111(d) rule also requires states to submit plans to provide for the establishment, implementation and enforcement of standards of performance for existing sources. States must submit their plans to the EPA within 24 months after publication of the final emissions guidelines. The final 111 rules apply to several Company assets, including existing EGUs at the Boswell and Laskin facilities as well as the proposed combined cycle natural gas-fired generating facility, NTEC. The Company is reviewing the new rule, but anticipates compliance may require operational or planning adjustments. The state implementation plan process for Section 111(d) existing units will also be a factor in determining specific requirements and timing. We are unable to predict compliance costs at this time; 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 agencies for any wastewater discharged into navigable waters. We have obtained all necessary NPDES permits, including NPDES storm water permits for applicable facilities, to conduct our operations. NOTE 6. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued) Environmental Matters (Continued) 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. It set effluent limits and prescribed Best Available Control Technology (BACT) for several wastewater streams, including flue gas desulphurization (FGD) water, bottom ash transport water and coal combustion landfill leachate. In October 2020, the EPA published a final ELG Rule allowing re-use of bottom ash transport water in FGD scrubber systems with limited discharges related to maintaining system water balance. The rule set technology standards and numerical pollutant limits for discharges of bottom ash transport water 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 April 25, 2024, the EPA released a pre-publication version of a final ELG rule to update the 2020 ELGs. In the final rule, the EPA is revising ELGs for existing sources, including establishing zero discharge limitations for bottom ash transport water, FGD wastewater, and combustion residual leachate, and allowing states to set discharge limits for legacy wastewater in surface impoundments based on best professional judgment. 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 final ELG rule also establishes mercury and arsenic limitations for functionally equivalent discharges of leachate via groundwater to surface water. Compliance deadlines are determined by the applicable state permitting authority. Compliance deadlines could be required as soon as 60 days after the final rule is published in the Federal Register, but no later than December 31, 2029. Bottom ash transport and FGD wastewater ELGs are not expected to have a significant impact on Minnesota Power operations. Zero leachate discharge requirements have the potential to impact dewatering associated with the closed Taconite Harbor dry ash landfill and Laskin’s closed Cell E impoundment. New limitations for arsenic and mercury related to functionally equivalent (groundwater to surface water) discharges are not currently anticipated to impact Minnesota Power facilities. We estimate no additional material compliance costs for ELG bottom ash water 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 approved by the EPA in April 2024, 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 of 1976 regulates the management and disposal of solid and hazardous wastes. We are required to notify the EPA of hazardous waste activity and, consequently, 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. NOTE 6. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued) Environmental Matters (Continued) 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 additional 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. On April 25, 2024, the EPA finalized the CCR Legacy Impoundment Rule. The final rule 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 rule requires all regulated generating facilities to evaluate and identify 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. Additionally, the EPA finalized portions of the proposed CCR Part B Rule, which allows CCR Units to certify closure while conducting groundwater remediation activities. This rule is currently under review; however impacts to previously closed CCR Units at Boswell and Laskin are anticipated. 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, alternative liner demonstrations and other CCR regulatory revisions. Portions of the Part B rule addressing alternative liner equivalency standards were finalized in November 2020. Finalization of the remaining beneficial reuse requirements are 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 March 31, 2024, SWL&P has recorded a liability of approximately $1 million for remediation costs at this site. SWL&P has recorded the recovery of the remediation costs associated with the site as a regulatory asset as we expect recovery of these costs to be allowed by the PSCW. Other Matters. Letters of Credit, Surety Bonds and Other Indemnifications. We have multiple credit facility agreements in place that provide the ability to issue standby letters of credit to satisfy contractual security requirements across our businesses. As of March 31, 2024, we had $150.1 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. In April 2024, under the tax credit transferability provision of the Inflation Reduction Act, we entered into an agreement with a third party to sell a portion of our production tax credits. ALLETE has indemnified the third party for the value of production tax credits sold to date of approximately $14 million. Regulated Operations. As of March 31, 2024, we had $25.4 million outstanding in standby letters of credit at our Regulated Operations which are pledged as security to MISO, the NDPSC and state agencies. NOTE 6. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued) Other Matters (Continued) ALLETE Clean Energy. ALLETE Clean Energy is party to PSAs that expire in various years between 2024 and 2039. As of March 31, 2024, ALLETE Clean Energy has $80.6 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 March 31, 2024, 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 . The Nobles 2 wind energy facility requires standby letters of credit as security for certain contractual obligations. As of March 31, 2024, ALLETE South Wind has $10.1 million outstanding in standby letters of credit, related to its portion of the security requirements relative to its ownership in Nobles 2. South Shore Energy . As of March 31, 2024, South Shore Energy had $29.7 million outstanding in standby letters of credit pledged as security in connection with the development of NTEC. 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. |
