REGULATORY MATTERS

Electric Rates. Entities within our Regulated Operations segment file for periodic rate revisions with the MPUC, the FERC or the PSCW.

2010 Minnesota Rate Case. Minnesota Power’s current retail rates are based on a 2011 MPUC retail rate order, effective June 1, 2011, that allows for a 10.38 percent return on common equity and a 54.29 percent equity ratio.

Energy-Intensive Trade-Exposed Customer Rates. The Minnesota Legislature enacted and the Governor of Minnesota signed Energy-Intensive Trade-Exposed customer ratemaking legislation in June 2015. The intent of this legislation is to enable the MPUC to address elements in rate design to better support the competitiveness of manufacturers with electrically intensive operations which compete in global markets. The Company is working with all stakeholders to develop a rate schedule and contract proposals to be filed with the MPUC. It is expected that any rate design outcomes will be implemented on a revenue neutral basis.

FERC-Approved Wholesale Rates. Minnesota Power has 16 non-affiliated municipal customers in Minnesota. SWL&P is a Wisconsin utility and a customer of Minnesota Power. On April 21, 2015, Minnesota Power amended its formula-based wholesale electric sales contract with the Nashwauk Public Utilities Commission, extending the term through June 30, 2028. The electric service agreements with the remaining 15 municipal customers and SWL&P are effective through June 30, 2019. The rates included in these 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 our 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. The contract terms include a termination clause requiring a three-year notice to terminate. Under the Nashwauk Public Utilities Commission agreement, no termination notice may be given prior to June 30, 2025. Under the agreements with the remaining 15 municipal customers and SWL&P, no termination notices may be given prior to June 30, 2016.

2012 Wisconsin Rate Case. SWL&P’s current retail rates are based on a 2012 PSCW retail rate order, effective January 1, 2013, that allows for a 10.9 percent return on common equity.

Transmission Cost Recovery Rider. Minnesota Power has an approved cost recovery rider in place for certain transmission investments and expenditures. In an order dated February 23, 2015, the MPUC approved Minnesota Power’s updated billing factor 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. On May 22, 2015, we filed a transmission factor filing which includes updated costs associated with certain transmission facilities. Upon approval of the filing, we will be authorized to include updated billing rates on customer bills. As a result of the MPUC approval of the Certificate of Need for the GNTL on June 30, 2015, the project is eligible for cost recovery under our existing transmission cost recovery rider. We anticipate including our portion of the investments and expenditures for the GNTL as part of future transmission factor filings to include updated billing rates on customer bills.

Renewable Cost Recovery Rider. Minnesota Power has an approved cost recovery rider in place for investments and expenditures related to the 497 MW Bison Wind Energy Center in North Dakota. Customer billing rates for our Bison Wind Energy Center were approved by the MPUC in an order dated May 22, 2015. In November 2014, we filed a renewable resources factor filing which includes updated costs associated with Bison. Upon approval of the filing, we will be authorized to include updated billing rates on customer bills.

On February 13, 2015, Minnesota Power supplemented its November 2014 renewable resources factor filing to include costs associated with the restoration and repair of Thomson. In an order dated March 5, 2015, the MPUC approved our petition seeking cost recovery for investments and expenditures related to the restoration and repair of Thomson through a renewable resources rider.

Integrated Resource Plan. In a November 2013 order, the MPUC approved Minnesota Power’s 2013 Integrated Resource Plan which details our EnergyForward strategic plan and includes an analysis of a variety of existing and future energy resource alternatives and a projection of customer cost impact by class. Significant elements of the EnergyForward plan include major wind investments in North Dakota which were completed in the fourth quarter of 2014, installation of emissions control technology underway at Boswell Unit 4, planning for the proposed GNTL, the conversion of Laskin from coal to natural gas completed in June 2015 and the retirement of Taconite Harbor Unit 3 completed in May 2015. On July 9, 2015, Minnesota Power announced the next steps in its EnergyForward plan including the economic idling of Taconite Harbor Units 1 and 2 in the fall of 2016, the ceasing of coal-fired operations there in 2020, and the addition of between 200 MW and 300 MW of natural gas generation in the next decade. We are required to submit our 2015 Integrated Resource Plan with the MPUC no later than September 1, 2015.

NOTE 8. REGULATORY MATTERS (Continued)

Boswell Mercury Emissions Reduction Plan. Minnesota Power is implementing a mercury emissions reduction project for Boswell Unit 4 in order to comply with the Minnesota Mercury Emissions Reduction Act and the Federal MATS rule. In August 2012, Minnesota Power filed its mercury emissions reduction plan for Boswell Unit 4 with the MPUC and the MPCA. Costs to implement the Boswell Unit 4 mercury emissions reduction plan are included in the estimated capital expenditures required for compliance with the MATS rule and are estimated to be approximately $260 million, of which approximately $184 million was spent through June 30, 2015. In a November 2013 order, the MPUC approved the Boswell Unit 4 mercury emissions reduction plan and cost recovery, establishing an environmental improvement rider. Customer billing rates for the environmental improvement rider were approved by the MPUC in a July 2014 order. In November 2014, we filed an updated environmental improvement factor filing which included updated costs associated with Boswell Unit 4. Upon approval of this filing, we will be authorized to include updated billing rates on customer bills.

Great Northern Transmission Line (GNTL). 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. The GNTL is subject to various federal and state regulatory approvals. In October 2013, a Certificate of Need application was filed with the MPUC which was approved in an order dated June 30, 2015. Based on this order, our portion of the investments and expenditures for the project are eligible for cost recovery under our existing transmission cost recovery rider and are anticipated to be included in future transmission factor filings. In April 2014, Minnesota Power filed a route permit application with the MPUC and a request for a presidential permit to cross the U.S.-Canadian border with the U.S. Department of Energy. In a July 2014 order, the MPUC determined the route permit application to be complete. On June 19, 2015, the Minnesota Department of Commerce and the U.S. Department of Energy released the draft EIS for the GNTL. Public hearings on the draft EIS were held in July 2015 and comments are due by August 10, 2015. Hearings on the route permit will be held before an Administrative Law Judge in August 2015 with comments due by September 1, 2015. Manitoba Hydro must also obtain regulatory and governmental approvals related to a new transmission line in Canada. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in the third quarter of 2014. Upon receipt of all applicable permits and approvals, construction of the GNTL is anticipated to begin in 2016 and to be completed in 2020.

MISO Return on Equity Complaints. In November 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, to 9.15 percent. On February 12, 2015, an additional complaint was filed with the FERC seeking an order to further reduce the base return on equity to 8.67 percent. As a result of these complaints filed with the FERC, we have recorded an estimated refund obligation for MISO revenue of $5.6 million and an estimated refund for MISO transmission expense of $3.7 million, resulting in a reserve of $1.9 million as of June 30, 2015; $1.5 million was attributable to prior years.

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.

NOTE 8. REGULATORY MATTERS (Continued)



Regulatory Assets and Liabilities	June 30, 2015		December 31, 2014
Millions
Current Regulatory Assets (a)
Deferred Fuel		$11.8		$16.3
Total Current Regulatory Assets	11.8		16.3
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	216.1		223.9
Cost Recovery Riders (c)	68.3		59.7
Income Taxes	46.9		46.6
Asset Retirement Obligations	19.2		17.8
PPACA Income Tax Deferral	5.0		5.0
Other	4.1		4.3
Total Non-Current Regulatory Assets	359.6		357.3
Total Regulatory Assets		$371.4		$373.6

Non-Current Regulatory Liabilities
Wholesale and Retail Contra AFUDC		$50.6		$42.9
Plant Removal Obligations	19.6		22.8
Income Taxes	13.7		13.4
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	2.4		3.5
Other	18.5		11.6
Total Non-Current Regulatory Liabilities		$104.8		$94.2


(a)	Current regulatory assets are included in Prepayments and Other 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, are recognized as regulatory assets or regulatory liabilities on the Consolidated Balance Sheet. (See Note 15. Pension and Other Postretirement Benefit Plans.)


(c)	The cost recovery rider regulatory assets are primarily due to capital expenditures related to our Bison Wind Energy Center, investment in CapX2020 projects, and the Boswell Unit 4 environmental upgrade and are recognized in accordance with the accounting standards for alternative revenue programs.