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Regulatory Matters | 9 Months Ended
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Sep. 30, 2017
Regulated Operations [Abstract] |
Regulatory Matters [Text Block] | REGULATORY MATTERS Regulatory matters are summarized in Note 4. Regulatory Matters to our Consolidated Financial Statements in our 2016 Form 10‑K, with additional disclosure provided in the following paragraphs. Electric Rates. Entities within our Regulated Operations segment file for periodic rate revisions with the MPUC, FERC or PSCW. 2010 Minnesota General Rate Case. Minnesota Power’s current retail rates are based on a 2011 MPUC retail rate order that allows for a 10.38 percent return on common equity and a 54.29 percent equity ratio. 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 $23.1 million and $71.7 million for the quarter and nine months ended September 30, 2017, respectively ($25.1 million and $73.9 million for the quarter and nine months ended September 30, 2016, respectively). 2016 Minnesota General Rate Case. In November 2016, Minnesota Power filed a retail rate increase request with the MPUC seeking an average increase of approximately 9 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 have generated approximately $55 million in additional revenue. In December 2016, Minnesota Power filed a request to modify its original interim rate proposal reducing its requested interim rate increase to $34.7 million from the original request of approximately $49 million due to a change in its electric sales forecast. In December 2016 orders, the MPUC accepted the November 2016 filing as complete and authorized an annual interim rate increase of $34.7 million beginning January 1, 2017. On February 23, 2017, Minnesota Power filed an additional request to further reduce its requested interim rate increase. In an order dated April 13, 2017, the MPUC approved Minnesota Power’s updated retail rate request resulting in a reduction in the annual interim rate increase to $32.2 million beginning May 1, 2017. As a result of working with intervenors and further developments as the rate review has progressed, Minnesota Power’s final rate request is approximately $49 million on an annualized basis. A report and recommendation from the administrative law judge is scheduled to be issued in November 2017, with a final decision from the MPUC expected in January 2018. Management has evaluated the need for a reserve for interim rate refunds and concluded that a reserve is not necessary as of September 30, 2017. Management evaluates the need for reserves for interim rates each reporting period. As part of its 2016 general rate case and through its 2017 remaining life depreciation petition filed on February 1, 2017, Minnesota Power is seeking an extension of the recovery period for Boswell to better reflect recent environmental investments at the facility and mitigate rate increases for our customers. If the requested recovery period extension is approved, annual depreciation expense will be reduced by approximately $25 million. If not approved, we would expect final rates to be increased by a similar amount, subject to regulatory approval. We cannot predict the level of final rates that may be authorized by the MPUC. Energy-Intensive Trade-Exposed (EITE) Customer Rates. The Minnesota Legislature enacted EITE customer ratemaking law in 2015 which established that it is the energy policy of the state to have competitive rates for certain industries such as mining and forest products. In 2015, Minnesota Power filed a rate schedule petition with the MPUC for EITE customers and a corresponding rider for EITE cost recovery. In a March 2016 order, the MPUC dismissed the petition without prejudice, providing Minnesota Power the option to refile the petition with additional information or file a new petition. In June 2016, Minnesota Power filed a revised EITE petition with the MPUC which included additional information on the net benefits analysis, limits on eligible customers and term lengths for the EITE discount. The rate adjustments are intended to be revenue and cash flow neutral to Minnesota Power. The MPUC approved a reduction in rates for EITE customers in a December 2016 order and subsequently approved cost recovery in an order dated April 20, 2017; collection of the discount was subject to the MPUC’s review of Minnesota Power’s compliance filing implementing approval of a recovery mechanism. On September 29, 2017, Minnesota Power informed its EITE customers that it has suspended the EITE discount due to a concern it is not revenue and cash flow neutral to Minnesota Power based on an MPUC decision at a hearing on September 7, 2017, as well as the interim rate reduction and upcoming decisions in its 2016 general rate case. NOTE 6. REGULATORY MATTERS (Continued) Electric Rates (Continued) 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 electric 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 December 31, 2032, subject to bankruptcy court approval. No termination notice may be given for this contract prior to June 30, 2025. The wholesale electric service contracts with SWL&P and another municipal customer are effective through October 31, 2020, and June 30, 2019, respectively. Under the agreement with SWL&P, no termination notice may be given prior to October 31, 2017. The other municipal customer provided termination notice for its contract in June 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 (currently 10.38 percent). 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 December 31, 2024. No termination notices may be given prior to December 31, 2021. These contracts include fixed capacity charges through 2018; beginning in 2019, the capacity charge will not increase by more than two percent or decrease by more than one percent from the previous year’s capacity charge and will be determined using a cost-based formula methodology. 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 in place for certain transmission investments and expenditures. In a February 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 cost recovery filings. Renewable Cost Recovery Rider. Minnesota Power has an approved cost recovery rider in place for investments and expenditures related to Bison and the restoration and repair of Thomson. The cost recovery rider allows Minnesota Power to charge retail customers on a current basis for the costs of constructing 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 at a hearing on September 28, 2017. 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 approximately $15 million in the third quarter of 2016. The North Dakota investment tax credits previously recognized as income tax credits in Corporate and Other were reversed in 2016 resulting in an approximately $9 million charge to net income in the third quarter of 2016. In December 2016, Minnesota Power submitted a request for reconsideration with the MPUC. In an order dated February 14, 2017, the MPUC decided to reconsider its November 2016 order. At a hearing on September 28, 2017, 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 approximately $14 million in the third quarter of 2017. The North Dakota investment tax credits were reestablished as income tax credits in Corporate and Other, resulting in an approximately $8 million increase to net income in the third quarter of 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. NOTE 6. REGULATORY MATTERS (Continued) Electric Rates (Continued) 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. Environmental Improvement Rider. Minnesota Power has an approved environmental improvement rider in place 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 December 2016 order; however, in an order dated March 22, 2017, the MPUC approved a request by Minnesota Power to delay implementation of the updated rates until resolution of its 2016 general rate case. (See 2016 Minnesota General Rate Case.) Fuel Adjustment Clause Reform Pilot. At a hearing on October 19, 2017, the MPUC adopted a three-year pilot program to implement certain procedural reforms to the Minnesota utilities’ automatic fuel adjustment clause (FAC) for fuel and purchased power. The decision, subject to an MPUC order, would change the method of accounting for all Minnesota electric utilities to a monthly budgeted, forwarded‑looking FAC with a subsequent prudence review and true-up to actual allowed costs on an annual basis. The annual budget projection filing would also include an adjustment to the base cost of fuel. The MPUC will seek input from the utilities and other stakeholders on the detailed implementation steps and transition accounting needed to adopt the change in regulatory accounting method from the current FAC. Transition considerations would need to include the recovery of the current regulatory asset for deferred fuel costs consistent with other regulatory accounting transition precedents for similar matters. Other details of the transition including budgeting methodology and approval, tracker accounting for the differences between actual costs and the budgeted amounts, and the annual true-up and collection or refund process to customers will be determined by the MPUC upon consideration of each utility’s compliance filings. Based on the discussion at the October 19, 2017 hearing, this pilot is not expected to start until mid-2019. 2016 Wisconsin General Rate Case. In June 2016, SWL&P filed a rate increase request with the PSCW requesting an average increase of 3.1 percent for retail customers. The filing sought an overall return on equity of 10.9 percent and a 55 percent equity ratio. In an order dated August 9, 2017, the PSCW approved SWL&P’s rate increase request allowing for a 10.5 percent return on common equity and a 55 percent equity ratio. The order authorizes SWL&P to collect on average a 2.9 percent increase in rates for retail customers (3.8 percent increase in electric rates; 4.8 percent decrease in natural gas rates; and 9.8 percent increase in water rates). Final rates became effective on August 14, 2017. On an annualized basis, SWL&P will collect additional revenue of approximately $2.5 million. 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 September 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 the next decade. In a July 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. In October 2016, Minnesota Power announced Boswell Units 1 and 2 will be retired in 2018. On July 28, 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 energy PPA. These agreements will be subject to MPUC approval of the construction of 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 September 19, 2017, the MPUC approved Minnesota Power’s request to extend the next IRP filing deadline until October 1, 2019, and Minnesota Power’s request that approval for the natural gas energy PPA be decided through an administrative law judge process. The administrative law judge is expected to provide a recommendation by July 2018, and the Company anticipates a MPUC decision in the second half of 2018. The MPUC did not take any action regarding the wind and solar energy PPAs which will be refiled separately from the natural gas energy PPA. NOTE 6. REGULATORY MATTERS (Continued) Great Northern Transmission Line. Minnesota Power and Manitoba Hydro have proposed construction of the GNTL, an approximately 220-mile 500-kV transmission line between Manitoba and Minnesota’s Iron Range. In 2015, a certificate of need was approved by the MPUC. Based on this approval, 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.) Also in 2015, the FERC approved our request to recover on construction work in progress related to the GNTL from Minnesota Power’s wholesale customers. In an April 2016 order, the MPUC approved the route permit for the GNTL which largely follows Minnesota Power’s preferred route, including the international border crossing, and in November 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. 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 contributions in aid of construction. Total project costs of $66.9 million have been incurred through September 30, 2017, of which $36.8 million has been recovered from a subsidiary of Manitoba Hydro. Manitoba Hydro must obtain regulatory and governmental approvals related to a new transmission line in Canada. In 2015, Manitoba Hydro submitted the final preferred route and EIS for the transmission line in Canada to the Manitoba Conservation and Water Stewardship for regulatory approval. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in 2014. Conservation Improvement Program. Minnesota requires electric utilities to spend a minimum of 1.5 percent of gross operating revenues from service provided in the state on energy CIPs each year. On April 3, 2017, Minnesota Power submitted its 2016 CIP consolidated filing, which detailed Minnesota Power’s CIP program results and requested a CIP financial incentive of $5.5 million based upon MPUC procedures. In an order dated June 22, 2017, 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 the second quarter of 2017. The approved financial incentive will be recovered through customer billing rates in 2017 and 2018. In 2016, the CIP financial incentive of $7.5 million was recognized in the third quarter. CIP financial incentives are recognized in the period in which the MPUC approves the filing. MISO Return on Equity Complaints. In 2013, several customer groups located within the MISO service area filed complaints with the FERC requesting, among other things, a reduction in the base return on equity used by MISO transmission owners, including ALLETE and ATC, to 9.15 percent. In 2015, a federal administrative law judge ruled on the complaint proposing a reduction in the base return on equity to 10.32 percent, or 10.82 percent including an incentive adder for participation in a regional transmission organization. In September 2016, the FERC issued an order affirming the administrative law judge’s recommendation. In 2015, an additional complaint was filed with the FERC seeking an order to further reduce the base return on equity to 8.67 percent. In June 2016, a federal administrative law judge ruled on the additional complaint proposing a further 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. In 2013, legislation was enacted by the state of Minnesota requiring 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. In a February 2016 order finalized in December 2016, the MPUC approved Camp Ripley, a 10 MW utility scale solar project at the Camp Ripley Minnesota Army National Guard base and training facility near Little Falls, Minnesota, as eligible to meet the solar energy standard and for current cost recovery. Camp Ripley was completed in the fourth quarter of 2016. In a July 2016 order, the MPUC approved a community solar garden project in northeastern Minnesota, which is comprised of a 1 MW solar array to be 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. Minnesota Power believes Camp Ripley and the community solar garden project will meet approximately one-third of the overall mandate. Additionally, in an order dated February 10, 2017, the MPUC approved Minnesota Power’s proposal to increase the amount of solar rebates available for customer-sited solar installations and recover costs of the program through Minnesota Power’s renewable cost recovery rider. This proposal to incentivize customer‑sited solar installations is expected to meet a portion of the required mandate related to solar photovoltaic devices with a nameplate capacity of 40 kW or less. NOTE 6. REGULATORY MATTERS (Continued) 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. No regulatory assets or liabilities 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.
Regulatory Assets and Liabilities | September 30, 2017 |  |  | December 31, 2016 |
Millions |  |  |
Current Regulatory Assets |  |  |
Deferred Fuel Adjustment Clause |  | $20.2 |  |  |  | $18.6 |
Total Current Regulatory Assets | 20.2 |  |  | 18.6 |
Non-Current Regulatory Assets |  |  |
Defined Benefit Pension and Other Postretirement Benefit Plans | 221.4 |  |  | 226.1 |
Income Taxes (a) | 35.7 |  |  | 33.8 |
Asset Retirement Obligations | 29.8 |  |  | 26.0 |
Cost Recovery Riders | 5.2 |  |  | 30.5 |
PPACA Income Tax Deferral | 5.0 |  |  | 5.0 |
Conservation Improvement Program | 4.9 |  |  | 4.0 |
Other | 8.6 |  |  | 4.7 |
Total Non-Current Regulatory Assets | 310.6 |  |  | 330.1 |
Total Regulatory Assets |  | $330.8 |  |  |  | $348.7 |
Non-Current Regulatory Liabilities |  |  |
Wholesale and Retail Contra AFUDC |  | $57.0 |  |  |  | $56.8 |
Plant Removal Obligations | 19.2 |  |  | 19.1 |
Income Taxes | 18.6 |  |  | 19.1 |
North Dakota Investment Tax Credits | 13.9 |  |  | 28.2 |
Other | 2.8 |  |  | 2.6 |
Total Non-Current Regulatory Liabilities |  | $111.5 |  |  |  | $125.8 |
(a) | See Note 1. Operations and Significant Accounting Policies – Revision of Prior Balance Sheet.

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