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.

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. In April 2014, Minnesota Power amended its formula-based wholesale electric sales contract with the Nashwauk Public Utilities Commission, extending the term through June 30, 2026. The electric service agreements with the remaining 15 Minnesota 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, 2023. 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 November 2013, 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. We filed a petition on April 24, 2014, to include additional transmission investments and expenditures in customer billing rates, which was approved by the MPUC on January 29, 2015. (See Note 1. Operations and Significant Accounting Policies.)

NOTE 5. REGULATORY MATTERS (Continued)

Renewable Cost Recovery Rider. Construction on the 205 MW Bison 4 wind facility in North Dakota was completed with project costs totaling approximately $333 million through December 31, 2014. With the completion of Bison 4, the Bison Wind Energy Center in North Dakota consists of 497 MW of nameplate capacity. On January 17, 2014, the MPUC approved Minnesota Power’s petition seeking cost recovery for investments and expenditures related to Bison 4. Customer billing rates for our Bison 1, 2, & 3 wind facilities were approved by the MPUC in a December 2013 order. On April 29, 2014 and November 10, 2014, we filed renewable resources factor filings which include updated costs associated with the Bison Wind Energy Center. Upon approval of the filings, we will be authorized to include updated billing rates on customer bills. (See Note 1. Operations and Significant Accounting Policies.)

On January 29, 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. The total project investment for Thomson is estimated to be approximately $90 million, net of insurance. (See Note 12. Commitments, Guarantees and Contingencies.)

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 at Boswell Unit 4, planning for the proposed GNTL, conversion of Laskin from coal to natural gas in the second quarter of 2015 and retiring Taconite Harbor Unit 3 in the second quarter of 2015. We are required to submit our 2015 Integrated Resource Plan with the MPUC no later than September 1, 2015.

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. The plan proposed that Minnesota Power install pollution controls by early 2016 to address both the Minnesota Mercury Emissions Reduction Act requirements and the Federal MATS rule. 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 $250 million, of which $145 million was spent through December 31, 2014. In November 2013, the MPUC issued an order approving the Boswell Unit 4 mercury emissions reduction plan and cost recovery, establishing an environmental improvement rider. Also in November 2013, environmental intervenors filed a petition for reconsideration with the MPUC which was subsequently denied in an order dated January 17, 2014. The MPUC’s order was affirmed by the Minnesota Court of Appeals on November 3, 2014. In December 2013, Minnesota Power filed a petition with the MPUC to establish customer billing rates for the approved environmental improvement rider based on actual and estimated investments and expenditures, which was approved in an order dated July 2, 2014. On November 26, 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. (See Note 1. Operations and Significant Accounting Policies.)

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 with respect to the GNTL. In an order dated January 8, 2014, the MPUC determined the Certificate of Need application was complete and referred the docket to an administrative law judge for a contested case proceeding. On April 15, 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 an order dated July 2, 2014, the MPUC determined the route permit application to be complete. 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. (See Note 12. Commitments, Guarantees and Contingencies.)

Regulatory Assets and Liabilities. Our regulated utility operations are subject to the 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 5. REGULATORY MATTERS (Continued)



Regulatory Assets and Liabilities
As of December 31	2014		2013
Millions
Current Regulatory Assets (a)
Deferred Fuel Adjustment Clause		$16.3		$23.0
Total Current Regulatory Assets	16.3		23.0
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	223.9		164.1
Cost Recovery Riders (c)	59.7		39.6
Income Taxes	46.6		35.3
Asset Retirement Obligations	17.8		16.0
PPACA Income Tax Deferral	5.0		5.0
Other	4.3		3.8
Total Non-Current Regulatory Assets	357.3		263.8
Total Regulatory Assets		$373.6		$286.8

Non-Current Regulatory Liabilities
Wholesale and Retail Contra AFUDC		$42.9		$19.7
Plant Removal Obligations	22.8		19.7
Income Taxes	13.4		17.0
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	3.5		16.3
Other	11.6		8.3
Total Non-Current Regulatory Liabilities		$94.2		$81.0


(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 17. Pension and Other Postretirement Benefit Plans.)


(c)	The cost recovery rider regulatory assets are 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.