Regulatory Matters

3 Months Ended

Mar. 31, 2020

REGULATORY MATTERS

Regulatory matters are summarized in Note 4. Regulatory Matters to the Consolidated Financial Statements in our 2019 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, 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. Revenue from cost recovery riders was $9.6 million for the three months ended March 31, 2020 ($7.4 million for three months ended March 31, 2019).

2020 Minnesota General Rate Case. On November 1, 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 seeks 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 generate approximately $66 million in additional revenue. In orders dated December 23, 2019, the MPUC accepted the filing as complete and authorized an annual interim rate increase of $36.1 million that began January 1, 2020. We cannot predict the level of final rates that may be authorized by the MPUC.

On April 23, 2020, Minnesota Power filed a request with the MPUC that proposes a resolution for Minnesota Power’s 2020 general rate case. Key components of our proposal include removing the current 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 of approximately $12 million ($9 million as of March 31, 2020,); increasing ongoing customer rates 4.1 percent compared to the 5.8 percent increase reflected in current interim rates; and a provision that Minnesota Power would not file another rate case until at least March 1, 2021, unless certain events occur. Minnesota Power would withdraw its general rate case upon approval of this filing and proposed resolution by the MPUC. At a hearing on April 30, 2020, the MPUC approved lowering current interim rates to 4.1 percent effective May 1, 2020, as requested by Minnesota Power in this filing. A final decision on Minnesota Power’s full proposal in this filing is expected in June 2020. At this time, we are unable to predict whether the MPUC will ultimately approve this filing and proposed resolution, and thus, as of March 31, 2020, we have not recorded reserves for interim rates.

NOTE 2. REGULATORY MATTERS (Continued)

Electric Rates (Continued)

Transmission Cost Recovery Rider. Minnesota Power has an approved cost recovery rider in place for certain transmission investments and expenditures. In a 2016 order, the MPUC approved Minnesota Power’s updated customer billing rates allowing 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. On July 9, 2019, Minnesota Power filed a petition seeking MPUC approval to update the customer billing factor to include investments made for the GNTL. (See Note 6. Commitments, Guarantees and Contingencies.)

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. Current customer billing rates for the renewable cost recovery rider were approved by the MPUC in a November 2018 order. On August 15, 2019, Minnesota Power filed a petition seeking MPUC approval to update the customer billing factor.

Fuel Adjustment Clause Reform. In a 2017 order, the MPUC adopted a program to implement certain procedural reforms to Minnesota utilities’ automatic fuel adjustment clause (FAC) for fuel and purchased power. With this order, the method of accounting for all Minnesota electric utilities changed to a monthly budgeted, forward-looking FAC with annual prudence review and true-up to actual allowed costs. On May 1, 2019, Minnesota Power filed its fuel adjustment forecast for 2020, which was accepted by the MPUC in an order dated November 14, 2019, for purposes of setting fuel adjustment clause rates for 2020, subject to a true-up filing in 2021.

COVID-19 Related Costs. In an order dated March 24, 2020, the PSCW authorized public utilities, which includes SWL&P, to defer expenditures incurred by the utility resulting from its compliance with state government or regulator orders, and as otherwise required to ensure the provision of safe, reliable and affordable access to utility services during Wisconsin’s declared public health emergency for COVID-19. On April 20, 2020, Minnesota Power along with other regulated electric and natural gas service providers in Minnesota filed a joint petition to request MPUC authorization to track incremental costs and expenses incurred as a result of COVID-19, and to defer and record such costs as a regulatory asset, subject to recovery in a future proceeding.

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 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 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. Minnesota Power’s next IRP filing is due October 1, 2020.

Nemadji Trail Energy Center. In 2017, Minnesota Power submitted a resource package to the MPUC which included requesting approval of a 250 MW natural gas capacity dedication agreement. The natural gas capacity dedication agreement was 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, as well as a securitization plan. On December 23, 2019, the Minnesota Court of Appeals reversed and remanded the MPUC’s decision to approve certain affiliated-interest agreements. The MPUC was ordered to determine whether NTEC may have the potential for significant environmental effects and, if so, to prepare an environmental assessment worksheet before reassessing the agreements. On January 22, 2020, Minnesota Power filed a petition for further review with the Minnesota Supreme Court requesting that it review and overturn the Minnesota Court of Appeals decision, which petition was accepted for review by the Minnesota Supreme Court on March 18, 2020. On January 8, 2019, an application for a certificate of public convenience and necessity for NTEC was submitted to the PSCW, which was approved by the PSCW at a hearing on January 16, 2020. Construction of NTEC is subject to obtaining additional permits from local, state and federal authorities. The total project cost is estimated to be approximately $700 million, of which ALLETE’s portion is expected to be approximately $350 million. ALLETE’s portion of NTEC project costs incurred through March 31, 2020, is approximately $13 million.

MISO Return on Equity Complaint. MISO transmission owners, including ALLETE and ATC, have an authorized return on equity of 9.88 percent, or 10.38 percent including an incentive adder for participation in a regional transmission organization, based on a November 2019 FERC order. In this order, the FERC reduced the base return on equity for regional transmission organizations as recommended by an administrative law judge with refunds ordered for prior periods, which are immaterial to ALLETE. Multiple parties to the complaint have filed requests for rehearing of the FERC order.

NOTE 2. 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. 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.



Regulatory Assets and Liabilities	March 31, 2020		December 31, 2019
Millions
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans		$211.1		$212.9
Income Taxes	121.0		123.4
Cost Recovery Riders	34.1		24.7
Asset Retirement Obligations	31.8		32.0
Boswell Units 1 and 2 Net Plant and Equipment	9.3		10.7
Manufactured Gas Plant	8.3		8.2
PPACA Income Tax Deferral	4.7		4.8
Other	3.5		3.8
Total Non-Current Regulatory Assets		$423.8		$420.5

Current Regulatory Liabilities (a)
Transmission Formula Rates Refund		$1.3		$1.7
Provision for Tax Reform Refund	0.2		0.2
Total Current Regulatory Liabilities	1.5		1.9
Non-Current Regulatory Liabilities
Income Taxes	397.1		407.2
Wholesale and Retail Contra AFUDC	84.2		79.3
Plant Removal Obligations	37.4		35.5
Defined Benefit Pension and Other Postretirement Benefit Plans	15.6		17.0
North Dakota Investment Tax Credits	12.3		12.3
Fuel Adjustment Clause (b)	8.4		—
Conservation Improvement Program	7.4		5.4
Other	4.0		3.6
Total Non-Current Regulatory Liabilities	566.4		560.3
Total Regulatory Liabilities		$567.9		$562.2


(a)	Current regulatory liabilities are presented within Other Current Liabilities on the Consolidated Balance Sheet.

(b)

Fuel adjustment clause regulatory liability represents the amount expected to be refunded to customers for the over-collection of fuel adjustment clause recoveries. (See Fuel Adjustment Clause Reform.)