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Regulatory Matters | 12 Months Ended
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Dec. 31, 2018
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 and Environmental Improvement Rider.) Revenue from cost recovery riders was $103.8 million in 2018 ($96.9 million in 2017; $97.1 million in 2016). With the implementation of final rates in Minnesota Power’s general rate case, certain revenue previously recognized under cost recovery riders was incorporated into base rates. (See 2016 Minnesota General Rate Case.) NOTE 4. REGULATORY MATTERS (Continued) Electric Rates (Continued) 2016 Minnesota General Rate Case. In November 2016, Minnesota Power filed a retail rate increase request with the MPUC which sought an average increase of approximately 9 percent for retail customers. The rate filing sought a return on equity of 10.25 percent and a 53.81 percent equity ratio. The MPUC issued an order dated March 12, 2018, in Minnesota Power’s general rate case approving a return on common equity of 9.25 percent and a 53.81 percent equity ratio. Final rates went into effect on December 1, 2018, which is expected to result in additional revenue of approximately $13 million on an annualized basis. Interim rates were collected from January 1, 2017, through November 30, 2018, which were fully offset by the recognition of a corresponding reserve. Minnesota Power has recorded a reserve for an interim rate refund, net of discounts provided to EITE customers, of $40.0 million as of December 31, 2018 ($23.7 million as of December 31, 2017) which is expected to be refunded in 2019. The MPUC also disallowed Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs due to the anticipated adoption of a forward-looking fuel adjustment clause methodology resulting in a $19.5 million pre-tax charge to Fuel, Purchased Power and Gas – Utility in 2017. As part of its decision in Minnesota Power’s 2016 general rate case, the MPUC also extended the depreciable lives of Boswell Unit 3, Unit 4 and common facilities to 2050 primarily to mitigate rate increases for our customers, and shortened the depreciable lives of Boswell Unit 1 and Unit 2 to 2022, resulting in a net decrease to depreciation expense of approximately $25 million in the fourth quarter of 2017. On April 2, 2018, Minnesota Power filed a petition with the MPUC requesting reconsideration of certain decisions in the MPUC’s order dated March 12, 2018. In an order dated May 29, 2018, the MPUC denied Minnesota Power’s petition for reconsideration and accepted a Minnesota Department of Commerce request for reconsideration reducing the depreciable lives of Boswell Unit 3, Unit 4 and common facilities to 2035 while utilizing the benefits of the lower federal income tax rate enacted as part of the TCJA to mitigate the impact on customer rates. Energy-Intensive Trade-Exposed Customer Rates. An EITE customer ratemaking law was enacted in 2015 establishing a Minnesota energy policy to have competitive rates for certain industries such as mining and forest products. The MPUC approved a reduction in rates for EITE customers in a December 2016 order and subsequently approved cost recovery in an April 2017 order. Minnesota Power expects the discount to EITE customers to be approximately $16 million annually based on EITE customer current operating levels. While interim rates were in effect for Minnesota Power’s 2016 general rate case, discounts provided to EITE customers offset interim rate refund reserves for non-EITE customers. Minnesota Power provided $16.7 million of discounts to EITE customers during the year ended December 31, 2018 ($8.6 million and none for the years ended December 31, 2017, and 2016, respectively). FERC-Approved Wholesale Rates. Minnesota Power has 16 non-affiliated municipal customers in Minnesota. SWL&P is a Wisconsin utility and a wholesale customer of Minnesota Power. All 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 is effective through at least December 31, 2032. No termination notice may be given for this contract prior to July 1, 2029. The wholesale electric service contracts with SWL&P and another municipal customer are effective through at least February 28, 2022, and through June 30, 2019, respectively. Under the agreement with SWL&P, no termination notice has been given. The other municipal customer provided termination notice for its contract in 2016. Minnesota Power currently provides approximately 29 MW of average monthly demand to this customer. The rates included in these three 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 14 municipal customers are effective through varying dates ranging from 2024 through 2029. No termination notices may be given prior to three years before maturity. These contracts include fixed capacity charges through 2018; beginning in 2019, the capacity charge will be 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 will be set each January 1, subject to monthly adjustment, and will also be determined using a cost-based formula methodology. Transmission Cost Recovery Rider. Minnesota Power has an approved cost recovery rider for certain transmission investments and expenditures. In a 2016 order, the MPUC approved Minnesota Power’s updated customer billing rates which allows Minnesota Power to charge retail customers on a current basis for the costs of constructing certain transmission facilities plus a return on the capital invested. As a result of the MPUC approval of the certificate of need for the GNTL in 2015, the project is eligible for cost recovery under the existing transmission cost recovery rider. Minnesota Power is funding the construction of the GNTL with a subsidiary of Manitoba Hydro (see Great Northern Transmission Line), and anticipates including its portion of the investments and expenditures for the GNTL in future transmission bill factor filings. NOTE 4. REGULATORY MATTERS (Continued) Electric Rates (Continued) Renewable Cost Recovery Rider. Minnesota Power has an approved cost recovery rider for certain renewable investments and expenditures. The cost recovery rider allows Minnesota Power to charge retail customers on a current basis for the costs of certain renewable investments plus a return on the capital invested. Updated customer billing rates for the renewable cost recovery rider were approved by the MPUC in an order dated November 19, 2018. Minnesota Power also has approval for current cost recovery of investments and expenditures related to compliance with the Minnesota Solar Energy Standard. (See Minnesota Solar Energy Standard.) Currently, there is no approved customer billing rate for solar costs. In a November 2016 order, the MPUC directed Minnesota Power to attribute all North Dakota investment tax credits realized from Bison to Minnesota Power regulated retail customers. As a result of the adverse regulatory outcome, Minnesota Power recorded a regulatory liability and a reduction in Operating Revenue of $15.0 million in 2016. The North Dakota investment tax credits previously recognized as income tax credits in Corporate and Other were reversed in 2016 resulting in an $8.8 million charge to net income in 2016. In December 2016, Minnesota Power submitted a request for reconsideration with the MPUC. In a December 2017 order, the MPUC modified its November 2016 order to allow Minnesota Power to account for North Dakota investment tax credits based on the long-standing regulatory precedents of stand-alone allocation methodology of accounting for income taxes. As a result of the favorable regulatory outcome, Minnesota Power recorded a reduction in its regulatory liability and an increase in Operating Revenue of $14.0 million in 2017. The North Dakota investment tax credits previously recorded were reestablished as income tax credits in Corporate and Other, resulting in a $7.9 million increase to net income in 2017. The stand-alone method provides that income taxes (and credits) are calculated as if Minnesota Power was the only entity included in ALLETE’s consolidated federal and unitary state income tax returns. Minnesota Power has recorded a regulatory liability for North Dakota investment tax credits generated by its jurisdictional activity and expected to be realized in the future. North Dakota investment tax credits attributable to ALLETE’s apportionment and income of ALLETE’s other subsidiaries are included in Corporate and Other operations. 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 an order dated November 19, 2018. Fuel Adjustment Clause Reform. In a December 2017 order, the MPUC adopted a program to implement certain procedural reforms to the Minnesota utilities’ automatic fuel adjustment clause (FAC) for fuel and purchased power. The order will change the method of accounting for all Minnesota electric utilities to a monthly budgeted, forwarded-looking FAC with an annual prudence review and true-up to actual allowed costs. The MPUC is seeking input from Minnesota electric utilities and other stakeholders on the implementation and transition accounting needed to adopt the change. At a hearing on January 18, 2018, the MPUC disallowed recovery of Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs due to the anticipated adoption of the forward-looking fuel adjustment clause methodology resulting in a $19.5 million pre-tax charge to Fuel, Purchased Power and Gas – Utility in 2017. In an order dated December 12, 2018, the MPUC deferred the implementation date to January 1, 2020. Tax Cuts and Jobs Act of 2017. In December 2017, the MPUC opened a docket to review the effects of the TCJA on electric and natural gas rates and services in Minnesota, including the legislation’s impact on tax rates and utilities’ deferred income tax assets and liabilities. On March 2, 2018, Minnesota Power submitted an initial filing to the MPUC regarding the impacts of the TCJA on Minnesota Power. As part of Minnesota Power’s rate case, in an order dated May 29, 2018, the MPUC directed Minnesota Power to utilize the benefits of the lower federal income tax rate enacted as part of the TCJA to offset an increase in depreciation expense, effective January 1, 2018, resulting from the reduction in the depreciable lives of Boswell Unit 3, Unit 4 and common facilities to 2035 that would have otherwise resulted in an increase in customer rates. The impact of the TCJA on Minnesota Power’s deferred income tax assets and liabilities was not addressed in the rate case order. In an order dated December 5, 2018, the MPUC determined the regulatory treatment for the impact of the TCJA on Minnesota Power’s deferred income tax assets and liabilities. The MPUC authorized Minnesota Power to amortize the income tax benefits from the remeasurement of deferred income tax assets and liabilities resulting from the TCJA primarily over the life of the related property, plant and equipment with the remainder amortized over a 10-year period. The MPUC directed Minnesota Power to return these excess deferred income tax benefits as a monthly bill credit beginning with the implementation of final rates on December 1, 2018. Additionally, Minnesota Power customers will receive a one-time bill credit in 2019 for the benefit of the excess deferred income taxes from January 1, 2018, through November 30, 2018. NOTE 4. REGULATORY MATTERS (Continued) Electric Rates (Continued) On January 10, 2018, the PSCW opened a docket to review the effects of the TCJA and directed Wisconsin utilities to defer its impacts until further direction was provided by the PSCW. In an order dated May 24, 2018, the PSCW directed SWL&P to refund the benefits of the lower federal income tax rates enacted as part of the TCJA on customer bills beginning in July 2018. In an order dated December 20, 2018, the PSCW directed SWL&P to return the excess deferred income tax benefits for 2018 in 2019 and 2020, and include the return of excess deferred income tax benefits going forward in final rates effective January 1, 2019, with a true-up in its next rate case. (See 2018 Wisconsin General Rate Case.) These excess deferred income tax benefits for SWL&P will be returned primarily over the life of the related property, plant and equipment with the remainder amortized over a 4-year period. 2016 Wisconsin General Rate Case. SWL&P’s retail rates in 2018 were based on a 2017 PSCW retail rate order effective August 2017 that allowed for a 10.5 percent return on common equity and a 55 percent equity ratio. SWL&P’s retail rates prior to August 2017, were based on a 2012 PSCW retail rate order that provided for a 10.9 percent return on equity. 2018 Wisconsin General Rate Case. On May 25, 2018, SWL&P filed a rate increase request with the PSCW requesting an average increase of 2.7 percent for retail customers (2.0 percent increase in electric rates; 2.3 percent increase in natural gas rates; and 8.3 percent increase in water rates). The filing sought an overall return on equity of 10.5 percent and a 55.41 percent equity ratio. In an order dated December 20, 2018, the PSCW approved a rate increase for SWL&P including a return on equity of 10.4 percent and a 55.0 percent equity ratio. Final rates went into effect January 1, 2019, which is expected to result in additional revenue of approximately $1.3 million on an annualized basis. Integrated Resource Plan. In 2015, Minnesota Power filed its 2015 IRP with the MPUC which included an analysis of a variety of existing and future energy resource alternatives and a projection of customer cost impact by class. The 2015 IRP also contained steps in Minnesota Power’s EnergyForward strategic plan including the economic idling of Taconite Harbor Units 1 and 2 which occurred in 2016, the ceasing of coal-fired operations at Taconite Harbor in 2020, and the addition of between 200 MW and 300 MW of natural gas-fired generation. In a 2016 order, the MPUC approved Minnesota Power’s 2015 IRP with modifications. The order accepted Minnesota Power’s plans for Taconite Harbor, directed Minnesota Power to retire Boswell Units 1 and 2 no later than 2022, required an analysis of generation and demand response alternatives to be filed with a natural gas resource proposal, and required Minnesota Power to conduct request for proposals for additional wind, solar and demand response resource additions subject to further MPUC approvals. Minnesota Power retired Boswell Units 1 and 2 in the fourth quarter of 2018. In July 2017, Minnesota Power submitted a resource package to the MPUC requesting approval of PPAs for the output of a 250 MW wind energy facility and a 10 MW solar energy facility as well as approval of a 250 MW natural gas capacity dedication agreement. These agreements were subject to MPUC approval of the construction of NTEC, a 525 MW to 550 MW combined-cycle natural gas‑fired generating facility which will be jointly owned by Dairyland Power Cooperative and a subsidiary of ALLETE. Minnesota Power would purchase approximately 50 percent of the facility's output starting in 2025. In an order dated January 24, 2019, the MPUC approved Minnesota Power’s request for approval of the NTEC natural gas capacity dedication agreement. Separately, the MPUC required a baseload retirement evaluation in Minnesota Power’s next IRP filing analyzing its existing fleet including potential early retirement scenarios of Boswell Units 3 and 4, including a securitization plan. The MPUC also approved Minnesota Power’s request to extend the next IRP filing deadline until October 1, 2020. On January 8, 2019, an application for a certificate of public convenience and necessity for NTEC was submitted to the PSCW. A decision on the application is expected in 2020. On June 18, 2018, Minnesota Power filed a separate petition for approval of the PPA for the output of the 10 MW solar energy facility to be located in central Minnesota, which was approved by the MPUC in an order dated October 2, 2018. On August 22, 2018, Minnesota Power filed a separate petition for approval of an amended PPA for the output of the 250 MW wind energy facility to be located in southwestern Minnesota which was approved in an order dated January 23, 2019. (See Note 5. Equity Investments.) Great Northern Transmission Line. Minnesota Power is constructing the GNTL, an approximately 220-mile 500-kV transmission line between Manitoba and Minnesota’s Iron Range that was proposed by Minnesota Power and Manitoba Hydro. In a 2016 order, the MPUC approved the route permit for the GNTL, and in 2016, the U.S. Department of Energy issued a presidential permit to cross the U.S.-Canadian border, which was the final major regulatory approval needed before construction in the U.S. could begin. Site clearing and pre-construction activities commenced in the first quarter of 2017 with construction expected to be completed in 2020. To date, most of the right-of-way has been cleared while foundation installation and transmission tower construction have commenced. The total project cost in the U.S., including substation work, is estimated to be between $560 million and $710 million, of which Minnesota Power’s portion is expected to be between $300 million and $350 million; the difference will be recovered from a subsidiary of Manitoba Hydro as non-shareholder contributions to capital. Total project costs of $380.8 million have been incurred through December 31, 2018, of which $203.7 million has been recovered from a subsidiary of Manitoba Hydro. NOTE 4. REGULATORY MATTERS (Continued) Great Northern Transmission Line (Continued) Manitoba Hydro must obtain regulatory and governmental approvals related to the MMTP, a new transmission line in Canada that will connect with the GNTL. (See Note 11. Commitments, Guarantees and Contingencies.) Minnesota Power’s portion of the investments and expenditures for the project are eligible for cost recovery under its existing transmission cost recovery rider and are anticipated to be included in future transmission cost recovery filings. (See Transmission Cost Recovery Rider.) Minnesota Power also has FERC approval to recover on construction work in progress related to the GNTL from Minnesota Power’s wholesale customers. 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. In November 2017, the Minnesota Department of Commerce approved Minnesota Power’s modified CIP triennial filing for 2017 through 2019, which outlined Minnesota Power’s CIP spending and energy-saving goals for those years. Minnesota Power’s CIP investment goal was $10.3 million for 2018 ($10.3 million for 2017; $7.3 million for 2016), with actual spending of $9.0 million in 2018 ($8.1 million in 2017; $7.4 million in 2016). The investment goal for 2019 is $10.5 million. On April 2, 2018, Minnesota Power submitted its 2017 CIP consolidated filing, which detailed Minnesota Power’s CIP program results and requested a CIP financial incentive of $3.0 million based on MPUC procedures. In an order dated September 4, 2018, the MPUC approved Minnesota Power’s CIP consolidated filing, including the requested CIP financial incentive which was recorded as revenue and as a regulatory asset in 2018. The approved financial incentive will be recovered in customer billing rates in 2018 and 2019. In 2017 and 2016, the CIP financial incentives recognize were $5.5 million and $7.5 million, respectively. CIP financial incentives are recognized in the period in which the MPUC approves the filing. MISO Return on Equity Complaint. MISO transmission owners, including ALLETE and ATC, have an authorized return on equity of 10.32 percent, or 10.82 percent including an incentive adder for participation in a regional transmission organization. In 2016, a federal administrative law judge ruled on a complaint proposing a reduction in the base return on equity to 9.70 percent, or 10.20 percent including an incentive adder for participation in a regional transmission organization, subject to approval or adjustment by the FERC. A final decision from the FERC on the administrative law judge’s recommendation is pending, which is not expected to have a material impact on our Consolidated Financial Statements. 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 by the end of 2020. 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’s solar energy supply consists of Camp Ripley, a 10 MW solar energy facility at the Camp Ripley Minnesota Army National Guard base and training facility near Little Falls, Minnesota, and a community solar garden project in northeastern Minnesota, which is comprised of a 1 MW solar array owned and operated by a third party with the output purchased by Minnesota Power and a 40 kW solar array that is owned and operated by Minnesota Power. In an order dated October 2, 2018, the MPUC approved a PPA for the output of the 10 MW Blanchard solar energy facility to be located in central Minnesota. Minnesota Power expects that Camp Ripley, the community solar garden arrays, the PPA for the output of the 10 MW Blanchard solar energy facility, and an increase in solar rebates will allow Minnesota Power to meet both parts of the solar mandate. Regulatory Assets and Liabilities. Our regulated utility operations are subject to accounting guidance for the effect 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, 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 | 2018 |  | 2017 |
Millions |  |
Non-Current Regulatory Assets |  |
Defined Benefit Pension and Other Postretirement Benefit Plans (b) |  | $218.5 |  |  | $220.3 |
Income Taxes (c) | 105.5 |  | 112.8 |
Asset Retirement Obligations (d) | 32.6 |  | 29.6 |
Boswell 1 & 2 (l) | 16.3 |  | — |
Manufactured Gas Plant (e) | 8.0 |  | 8.1 |
PPACA Income Tax Deferral | 5.0 |  | 5.0 |
Conservation Improvement Program (f) | — |  | 3.3 |
Other | 3.6 |  | 5.6 |
Total Non-Current Regulatory Assets |  | $389.5 |  |  | $384.7 |
Current Regulatory Liabilities (a) |  |
Provision for Interim Rate Refund (i) |  | $40.0 |  | — |
Provision for Tax Reform Refund (j) | 10.7 |  | — |
Transmission Formula Rates | 4.4 |  | — |
Total Current Regulatory Liabilities | 55.1 |  | — |
Non-Current Regulatory Liabilities |  |
Income Taxes (c) | 396.4 |  |  | $411.2 |
Wholesale and Retail Contra AFUDC (h) | 64.4 |  | 57.9 |
Provision for Interim Rate Refund (i) | — |  | 23.7 |
Plant Removal Obligations | 25.1 |  | 20.3 |
North Dakota Investment Tax Credits (k) | 14.7 |  | 14.1 |
Cost Recovery Riders (g) | 6.9 |  | 2.2 |
Transmission Formula Rates | 1.6 |  | — |
Other | 3.0 |  | 2.6 |
Total Non-Current Regulatory Liabilities | 512.1 |  | 532.0 |
Total Regulatory Liabilities |  | $567.2 |  |  | $532.0 |
(a) | Current regulatory liabilities are presented within Other Current Liabilities on the Consolidated Balance Sheet.
(b) | 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 15. Pension and Other Postretirement Benefit Plans.)
(c) | 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 and flow through current income taxes.
(d) | Asset retirement obligations will accrete and be amortized over the lives of the related property with asset retirement obligations.
(e) | 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.
(f) | The conservation improvement program regulatory asset represents CIP expenditures, any financial incentive earned for cost-effective program achievements and a carrying charge deferred for future cost recovery over the next year following MPUC approval.
(g) | The cost recovery rider regulatory liabilities are cash collections from our customers in excess of revenue recognized, primarily due to capital expenditures related to Bison, investment in CapX2020 projects, the Boswell Unit 4 environmental upgrade and the GNTL. The cost recovery rider regulatory liabilities as of December 31, 2018, will be returned within the next two years.
(h) | 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.
(i) | This amount is expected to be refunded to Minnesota Power’s regulated retail customers in 2019 and includes $23.8 million of discounts provided to EITE customers as of December 31, 2018, that will be offset against interim rate refunds ($8.6 million as of December 31, 2017). (See 2016 Minnesota General Rate Case and Energy-Intensive Trade‑Exposed Customer Rates.)
(j) | Provision for tax reform refund is expected to be refunded to Minnesota Power customers in the first quarter of 2019 and SWL&P customers in 2019 and 2020. (See Tax Cuts and Jobs Act of 2017.)
(k) | North Dakota investment tax credits expected to be realized from Bison that will be credited to Minnesota Power’s regulated retail customers through future renewable cost recovery rider filings as the tax credits are utilized.
(l) | In December 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.

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