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Regulatory Matters | 12 Months Ended
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Dec. 31, 2021
Regulated Operations [Abstract] |
Regulatory Matters [Text Block] | REGULATORY MATTERS Electric Rates. Entities within our Regulated Operations segment file for periodic rate revisions with the MPUC, PSCW or FERC. As authorized by the MPUC, Minnesota Power also recognizes revenue under cost recovery riders for transmission, renewable and environmental investments and expenditures. (See Transmission Cost Recovery Rider, Renewable Cost Recovery Rider, Solar Cost Recovery Rider and Environmental Improvement Rider.) Revenue from cost recovery riders was $38.9 million in 2021 ($29.9 million in 2020; $31.8 million in 2019). 2020 Minnesota General Rate Case. In November 2019, Minnesota Power filed a retail rate increase request with the MPUC seeking an average increase of approximately 10.6 percent for retail customers. The rate filing sought a return on equity of 10.05 percent and a 53.81 percent equity ratio. On an annualized basis, the requested final rate increase would have generated approximately $66 million in additional revenue. In December 2019 orders, the MPUC accepted the filing as complete and authorized an annual interim rate increase of $36.1 million beginning January 1, 2020. In April 2020, Minnesota Power filed a request with the MPUC that proposed a resolution of Minnesota Power’s 2020 general rate case. Key components of our proposal included removing the power marketing margin credit in base rates and reflecting actual power marketing margins in the fuel adjustment clause effective May 1, 2020; refunding to customers interim rates collected through April 2020; increasing customer rates 4.1 percent compared to the 5.8 percent increase reflected in interim rates; and a provision that Minnesota Power would not file another rate case until at least November 1, 2021, unless certain events occur. In a June 2020 order, the MPUC approved Minnesota Power’s petition and proposal to resolve and withdraw the general rate case. Effective May 1, 2020, customer rates were set at an increase of 4.1 percent with the removal of the power marketing margin credit from base rates. Actual power marketing margins will be reflected in the fuel adjustment clause. Reserves for interim rates of $11.7 million were recorded in the second quarter of 2020 and refunded in the third and fourth quarters of 2020. 2022 Minnesota General Rate Case. On November 1, 2021, Minnesota Power filed a retail rate increase request with the MPUC seeking an average increase of approximately 18 percent for retail customers. The rate filing seeks a return on equity of 10.25 percent and a 53.81 percent equity ratio. On an annualized basis, the requested final rate increase would generate approximately $108 million in additional revenue. In orders dated December 30, 2021, the MPUC accepted the filing as complete and authorized an annual interim rate increase beginning January 1, 2022, with approximately $80 million expected to be collected in cash and approximately $8 million of interim rates for residential customers deferred with a final determination on recovery at the end of the rate case. NOTE 4. REGULATORY MATTERS (Continued) Electric Rates (Continued) Minnesota Power Land Sales. In August 2020, Minnesota Power filed a petition with the MPUC for approval to sell land that surrounds several reservoirs on its hydroelectric system and is no longer required to maintain its operations. The land has an estimated value of approximately $100 million, and Minnesota Power proposed to credit ratepayers the net proceeds from the sales in a future rate case or through its renewable resources rider to mitigate future rate increases. In an order dated November 18, 2021, the MPUC authorized the land sales and directed the net proceeds to be refunded to ratepayers subject to certain conditions and required compliance filings. FERC-Approved Wholesale Rates. Minnesota Power has wholesale contracts with 15 non-affiliated municipal customers in Minnesota and SWL&P. Three of the wholesale contracts include a termination clause requiring a three-year notice to terminate. Minnesota Power’s wholesale electric contract with the Nashwauk Public Utilities Commission was extended in October 2020 and is effective through December 31, 2037. The wholesale electric service contract with SWL&P is effective through February 28, 2025. Under the agreement with SWL&P, no termination notice has been given. The rates included in these two contracts are set each July 1 based on a cost-based formula methodology, using estimated costs and a rate of return that is equal to Minnesota Power’s authorized rate of return for Minnesota retail customers. The formula-based rate methodology also provides for a yearly true-up calculation for actual costs incurred. Minnesota Power’s wholesale electric contracts with 13 other municipal customers were extended in January 2022 and are effective through 2029. These contracts are based on fixed prices for capacity and energy. The base energy charge for each year is adjusted annually for updated fuel and purchased power costs. The wholesale electric contract with one other municipal customer is effective through 2024. The capacity charge is determined using a cost-based formula methodology with limits on the annual change from the previous year’s capacity charge. The base energy charge for each year of the contract term is set each January 1, subject to monthly adjustment, and is determined using a cost-based formula methodology. Transmission Cost Recovery Rider. Minnesota Power has an approved cost recovery rider in place to charge retail customers on a current basis for certain transmission investments and expenditures, including a return on the capital invested. Current customer billing rates are based on a December 2020 order. In December 2020, Minnesota Power filed a petition seeking MPUC approval to update customer billing rates for additional investments made for the GNTL. On December 28, 2021, Minnesota Power submitted its annual factor filing seeking MPUC approval to further update customer billing rates under the transmission cost recovery rider. Renewable Cost Recovery Rider. Minnesota Power has an approved cost recovery rider in place to charge retail customers on a current basis for the costs of certain renewable investments and expenditures, including a return on the capital invested. Current customer billing rates for the renewable cost recovery rider were approved by the MPUC in a December 2020 order. On February 2, 2022, Minnesota Power submitted its 2022 renewable factor filing. Upon approval of the filing, Minnesota Power will be authorized to include updated billing rates on customer bills. Solar Cost Recovery Rider. In June 2020, Minnesota Power filed a petition seeking MPUC approval of a customer billing rate for solar costs related to investments and expenditures for meeting the state of Minnesota’s solar energy standard, which was approved by the MPUC in an order dated April 20, 2021. New customer billing rates for the solar cost recovery rider were implemented on June 1, 2021. On October 21, 2021, Minnesota Power submitted its 2022 solar factor filing. Upon approval of the filing, Minnesota Power will be authorized to include updated billing rates on customer bills. Environmental Improvement Rider. Minnesota Power has an approved environmental improvement rider for investments and expenditures related to the implementation of the Boswell Unit 4 mercury emissions reduction plan completed in 2015. Updated customer billing rates for the environmental improvement rider were approved by the MPUC in a November 2018 order. On January 19, 2021, Minnesota Power filed a petition seeking MPUC approval to end the environmental improvement rider, which was approved in an order dated April 20, 2021. The environmental improvement rider ended effective October 1, 2021. Electric Vehicle Charging Infrastructure Petition. On April 8, 2021, Minnesota Power filed a petition seeking approval to install and own DC fast charger stations for electric vehicles across its service territory, implement accompanying rates for those stations, and track and recover investments and expenses for the project. In an order dated October 22, 2021, the MPUC approved Minnesota Power’s petition. NOTE 4. REGULATORY MATTERS (Continued) Electric Rates (Continued) Fuel Adjustment Clause. The costs of fuel and related transportation costs for Minnesota Power’s generation as well as costs of purchased power for Minnesota Power are recoverable from Minnesota Power’s utility retail customers through the fuel adjustment clause (FAC). The FAC for Minnesota electric utilities is a monthly budgeted, forward-looking process with annual prudence review and true-up to actual allowed costs. In May 2020, Minnesota Power filed its fuel adjustment forecast for 2021, which was approved by the MPUC in a December 2020 order, subject to the annual prudence review and true-up filing in 2022. During 2021, Minnesota Power incurred higher fuel and purchased power costs than those forecasted in its May 2020 filing, which resulted in the recognition of an approximately $56 million regulatory asset as of December 31, 2021. Minnesota Power will make its annual true-up filing and a significant events filing in March 2022 requesting recovery of these under-collected fuel adjustment clause recoveries. In March 2020, Minnesota Power filed its FAC report covering the period July 2018 through December 2019. In a September 2020 order, the MPUC referred the review of Minnesota Power’s forced outage costs during the period of the report, which totaled approximately $8 million, to an administrative law judge (ALJ) for a contested case hearing to recommend to the MPUC if any of those costs should be returned to customers. On August 11, 2021, the ALJ recommended that Minnesota Power refund approximately $5 million to ratepayers. Minnesota Power submitted exceptions to the ALJ’s report to the MPUC stating that it disagreed with the ALJ’s recommendation and that no refund should be made as the Company operated its facilities in accordance with good utility practice. At a hearing on January 13, 2022, the MPUC agreed with the ALJ’s recommendation and ordered the refund of approximately $5 million to ratepayers, which was recorded as a reserve as of December 31, 2021. COVID-19 Related Deferred Accounting. In a March 2020 order, the PSCW authorized public utilities, including SWL&P, to defer expenditures incurred by the utility resulting from its compliance with state government or regulator orders during Wisconsin’s declared public health emergency for COVID-19. In a May 2020 order, the MPUC required Minnesota Power along with other regulated electric and natural gas service providers in Minnesota to track cost and revenue impacts resulting from the COVID-19 pandemic with review for recovery in a future rate proceeding. As of December 31, 2021, Minnesota Power has not deferred any costs or lost revenue, and SWL&P has deferred an immaterial amount of costs. Minnesota Power submitted a petition in November 2020 to the MPUC requesting authority to track and record as a regulatory asset lost large industrial customer revenue resulting from the idling of USS Corporation’s Keetac plant and Verso Corporation’s paper mill in Duluth, Minnesota. In an order dated May 13, 2021, the MPUC denied Minnesota Power’s request. 2018 Wisconsin General Rate Case. SWL&P’s current retail rates are based on a December 2018 order by the PSCW that allows for a return on equity of 10.4 percent and a 55.0 percent equity ratio. The PSCW had directed SWL&P to file its next general rate case in 2020; however, the PSCW granted an extension request made by SWL&P to delay filing its next general rate case until on or before December 20, 2022. SWL&P requested the extension primarily due to impacts of the COVID-19 pandemic. Integrated Resource Plan. In a 2016 order, the MPUC approved Minnesota Power’s 2015 IRP with modifications. The order accepted Minnesota Power’s plans for the economic idling of Taconite Harbor Units 1 and 2 and the ceasing of coal-fired operations at Taconite Harbor in 2020, directed Minnesota Power to retire Boswell Units 1 and 2, required an analysis of generation and demand response alternatives to be filed with a natural gas resource proposal, and required Minnesota Power to conduct requests for proposal for additional wind, solar and demand response resource additions. Minnesota Power retired Boswell Units 1 and 2 in the fourth quarter of 2018. 2021 Integrated Resource Plan. On February 1, 2021, Minnesota Power filed its latest IRP with the MPUC, which outlines its clean-energy transition plans through 2035. These plans include expanding its renewable energy supply, achieving coal-free operations at its facilities by 2035, and investing in a resilient and flexible transmission and distribution grid. As part of these plans, Minnesota Power anticipates adding approximately 400 MW of new wind and solar energy resources, retiring Boswell Unit 3 by 2030 and transforming Boswell Unit 4 to be coal-free by 2035. Minnesota Power’s plans recognize that advances in technology will play a significant role in completing its transition to carbon-free energy supply, reliably and affordably. A final decision on the IRP is expected in the second half of 2022. NOTE 4. REGULATORY MATTERS (Continued) Nemadji Trail Energy Center. In 2017, Minnesota Power submitted a resource package to the MPUC which included requesting approval of a natural gas capacity dedication and other affiliated-interest agreements for NTEC, an approximately 600 MW proposed combined-cycle natural gas-fired generating facility to be built in Superior, Wisconsin, which will be jointly owned by Dairyland Power Cooperative, Basin and South Shore Energy, ALLETE’s non-rate regulated, Wisconsin subsidiary. Minnesota Power is expected to purchase approximately 20 percent of the facility's output starting in 2025 pursuant to the capacity dedication agreement. (See Note 1. Operations and Significant Accounting Policies.) In a January 2019 order, the MPUC approved Minnesota Power’s request for approval of the NTEC natural gas capacity dedication and other affiliated-interest agreements. In 2019, the Minnesota Court of Appeals reversed and remanded the MPUC’s decision to approve certain affiliated-interest agreements. On April 21, 2021, the Minnesota Supreme Court reversed the Minnesota Court of Appeal’s decision by ruling that the MPUC is not required to conduct a review under the Minnesota Environmental Policy Act before approving affiliated-interest agreements that govern construction and operation of a Wisconsin power plant by a Minnesota utility, and remanded the case back to the Minnesota Court of Appeals for review of remaining issues on appeal. On August 23, 2021, the Minnesota Court of Appeals affirmed the decision by the MPUC to approve certain affiliated-interest agreements. Conservation Improvement Program. Minnesota requires electric utilities to spend a minimum of 1.5 percent of gross operating revenues, excluding revenue received from exempt customers, from service provided in the state on energy CIPs each year. On April 1, 2021, Minnesota Power submitted its 2020 consolidated filing detailing Minnesota Power’s CIP program results and requesting a CIP financial incentive of $2.4 million based upon MPUC procedures, which was recognized in the third quarter of 2021 upon approval by the MPUC in an order dated September 7, 2021. In 2020, a CIP financial incentive of $2.4 million was recognized in the third quarter upon approval by the MPUC of Minnesota Power’s 2019 CIP consolidated filing. CIP financial incentives are recognized in the period in which the MPUC approves the filing. In July 2020, Minnesota Power submitted its CIP triennial filing for 2021 through 2023 to the MPUC and Minnesota Department of Commerce, which outlines Minnesota Power’s CIP spending and energy-saving goals for those years. Minnesota Power’s CIP investment goals are $10.7 million for 2022 and $10.9 million for 2023. MISO Return on Equity Complaint. MISO transmission owners, including ALLETE and ATC, have an authorized return on equity of 10.02 percent, or 10.52 percent including an incentive adder for participation in a regional transmission organization based on a 2020 FERC order that granted rehearing of a 2019 FERC order. These FERC orders are subject to various outstanding legal challenges related to the refund period ordered by the FERC. Minnesota Solar Energy Standard. Minnesota law requires at least 1.5 percent of total retail electric sales, excluding sales to certain customers, to be generated by solar energy. At least 10 percent of the 1.5 percent mandate must be met by solar energy generated by or procured from solar photovoltaic devices with a nameplate capacity of 40 kW or less and community solar garden subscriptions. Minnesota Power has met both parts of the solar mandate to date. In May 2020, the MPUC issued a notice requesting all regulated gas and electric utilities provide a list of all ongoing, planned, or possible investments that support Minnesota’s energy policy objectives and aid economic recovery in Minnesota, among other items. In June 2020, Minnesota Power filed proposal with the MPUC to accelerate its plans for purchasing solar energy from approximately 20 MW of solar energy projects in Minnesota which was approved in a June 2021 order. These solar energy projects will be constructed and owned through an ALLETE subsidiary with an estimated investment of $40 million. Construction of these solar energy projects is expected to commence in 2022. Regulatory Assets and Liabilities. Our regulated utility operations are subject to accounting standards for the effects of certain types of regulation. Regulatory assets represent incurred costs that have been deferred as they are probable for recovery in customer rates. Regulatory liabilities represent obligations to make refunds to customers and amounts collected in rates for which the related costs have not yet been incurred. The Company assesses quarterly whether regulatory assets and liabilities meet the criteria for probability of future recovery or deferral. With the exception of the regulatory asset for Boswell Units 1 and 2 net plant and equipment, no other regulatory assets are currently earning a return. The recovery, refund or credit to rates for these regulatory assets and liabilities will occur over the periods either specified by the applicable regulatory authority or over the corresponding period related to the asset or liability. NOTE 4. REGULATORY MATTERS (Continued)
Regulatory Assets and Liabilities |  |
As of December 31 | 2021 | 2020
Millions |  |
Non-Current Regulatory Assets |  |
Defined Benefit Pension and Other Postretirement Benefit Plans (a) | $226.4 |  | $259.7 |
Income Taxes (b) | 104.7 |  | 113.7 |
Cost Recovery Riders (c) | 63.2 |  | 54.0 |
Fuel Adjustment Clause (d) | 56.4 |  | — |
Asset Retirement Obligations (e) | 33.1 |  | 31.6 |
Manufactured Gas Plant (f) | 17.0 |  | 8.8 |
PPACA Income Tax Deferral | 4.3 |  | 4.5 |
Conservation Improvement Program (g) | 2.4 |  | — |
Boswell Units 1 and 2 Net Plant and Equipment (h) | — |  | 5.0 |
Other | 4.3 |  | 3.6 |
Total Non-Current Regulatory Assets | $511.8 |  | $480.9 |
Current Regulatory Liabilities (i) |  |
Fuel Adjustment Clause (d) | $5.0 |  | $3.7 |
Transmission Formula Rates | 3.1 |  | 2.9 |
Other | 0.5 |  | 1.0 |
Total Current Regulatory Liabilities | 8.6 |  | 7.6 |
Non-Current Regulatory Liabilities |  |
Income Taxes (b) | 353.4 |  | 375.3 |
Wholesale and Retail Contra AFUDC (j) | 83.7 |  | 86.6 |
Plant Removal Obligations (k) | 52.6 |  | 41.2 |
Defined Benefit Pension and Other Postretirement Benefit Plans (a) | 28.1 |  | 4.4 |
North Dakota Investment Tax Credits (l) | 12.2 |  | 12.0 |
Boswell Units 1 and 2 Net Plant and Equipment (h) | 0.4 |  | — |
Conservation Improvement Program (g) | — |  | 1.5 |
Other | 5.7 |  | 3.8 |
Total Non-Current Regulatory Liabilities | 536.1 |  | 524.8 |
Total Regulatory Liabilities | $544.7 |  | $532.4 |
(a)Defined benefit pension and other postretirement items included in our Regulated Operations, which are otherwise required to be recognized in accumulated other comprehensive income as actuarial gains and losses as well as prior service costs and credits, are recognized as regulatory assets or regulatory liabilities on the Consolidated Balance Sheet. The asset or liability will decrease as the deferred items are amortized and recognized as components of net periodic benefit cost. (See Note 11. Pension and Other Postretirement Benefit Plans.) (b)These costs represent the difference between deferred income taxes recognized for financial reporting purposes and amounts previously billed to our customers. The balances will primarily decrease over the remaining life of the related temporary differences. (c)The cost recovery rider regulatory assets and liabilities are revenue not yet collected from our customers and cash collections from our customers in excess of the revenue recognized, respectively, primarily due to capital expenditures related to Bison, the Boswell Unit 4 environmental upgrade and the GNTL as well as differences between production tax credits recognized and those assumed in Minnesota Power’s base rates. The cost recovery rider regulatory assets as of December 31, 2021, will be recovered within the next two years. (d)Fuel adjustment clause regulatory asset and liability represent the amount expected to be recovered from or refunded to customers for the under- or over-collection of fuel adjustment clause recoveries. (See Fuel Adjustment Clause.) (e)Asset retirement obligations will accrete and be amortized over the lives of the related property with asset retirement obligations. (f)The manufactured gas plant regulatory asset represents costs of remediation for a former manufactured gas plant site located in Superior, Wisconsin, and formerly operated by SWL&P. We expect recovery of these remediation costs to be allowed by the PSCW in rates over time. (g)The conservation improvement program regulatory liability represents CIP expenditures, any financial incentive earned for cost-effective program achievements and a carrying charge deferred for future refund over the next year following MPUC approval. (h)In 2018, Minnesota Power retired Boswell Units 1 and 2 and reclassified the remaining net book value from property, plant and equipment to a regulatory asset on the Consolidated Balance Sheet. The remaining net book value is currently included in Minnesota Power’s rate base and Minnesota Power is earning a return on the outstanding balance. (i)Current regulatory liabilities are presented within Other Current Liabilities on the Consolidated Balance Sheet. (j)Wholesale and retail contra AFUDC represents amortization to offset AFUDC Equity and Debt recorded during the construction period of our cost recovery rider projects prior to placing the projects in service. The regulatory liability will decrease over the remaining depreciable life of the related asset. (k)Non-legal plant removal obligations included in retail customer rates that have not yet been incurred. (l)North Dakota investment tax credits expected to be realized from Bison that will be credited to Minnesota Power’s retail customers through future renewable cost recovery rider filings as the tax credits are utilized.

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