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’s non-affiliated municipal customers consist of 16 municipalities in Minnesota. SWL&P, a wholly-owned subsidiary of ALLETE, is a private utility in Wisconsin and also 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 agreements 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 July 1, 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.

Renewable Cost Recovery Rider. The Bison Wind Energy Center in North Dakota currently consists of 292 MW of nameplate capacity and was completed in various phases through 2012. Customer billing rates for our Bison Wind Energy Center were approved by the MPUC in a December 2013 order. Construction of Bison 4, a 205 MW wind project in North Dakota, which is an addition to our Bison Wind Energy Center, commenced and is expected to be completed by the end of 2014. The total project investment for Bison 4 is estimated to be approximately $345 million, of which $288 million was spent through September 30, 2014. On January 17, 2014, the MPUC approved Minnesota Power’s petition seeking cost recovery for investments and expenditures related to Bison 4. We included Bison 4 as part of our renewable resources rider factor filing along with the Company’s other renewable projects in a filing on April 29, 2014, which, upon approval, will authorize updated rates to be included on customer bills.

Minnesota Power has also filed a petition on July 3, 2014 with the MPUC seeking cost recovery for investments and expenditures related to the restoration and repair of Thomson which was damaged during 2012. The total project investment for Thomson is estimated to be approximately $90 million, of which $80 million, net of insurance, was spent through September 30, 2014. (See Note 15. 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, 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.

NOTE 7. 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. The plan proposes 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 $120 million was spent through September 30, 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. Intervenors have appealed this order and the Company has filed a response to the appeal. The Minnesota Court of Appeals heard oral argument in September 2014 with a decision expected before the end of 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.

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 that 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 new transmission line and hydroelectric generation development in Canada. Upon receipt of all applicable permits and approvals, construction of the GNTL is anticipated to begin in 2016, and to be completed in 2020.

Conservation Improvement Program (CIP). Minnesota has enacted legislation establishing an annual energy-savings goal for each utility of 1.5 percent of annual retail energy sales. On April 1, 2014, Minnesota Power submitted its 2013 CIP filing that requested a CIP financial incentive of $8.7 million based upon MPUC procedures. The requested CIP financial incentive was approved by the MPUC in a hearing held on July 24, 2014, and was recorded as revenue and as a regulatory asset. The approved financial incentive will be recovered through customer billing rates in 2014 and 2015. In 2013, the CIP financial incentive of $7.1 million was recognized in the fourth quarter. CIP financial incentives are recognized in the period in which the MPUC approves the filing.

Regulatory Assets and Liabilities. Our regulated utility operations are subject to the accounting guidance for Regulated Operations. We capitalize incurred costs which are probable of recovery in future utility rates as regulatory assets. Regulatory liabilities represent amounts expected to be refunded or credited to customers in rates. 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 7. REGULATORY MATTERS (Continued)



Regulatory Assets and Liabilities	September 30, 2014		December 31, 2013
Millions
Current Regulatory Assets (a)
Deferred Fuel		$18.5		$23.0
Total Current Regulatory Assets	18.5		23.0
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	158.6		164.1
Cost Recovery Riders (c)	54.5		39.6
Income Taxes	37.9		35.3
Asset Retirement Obligations	17.2		16.0
PPACA Income Tax Deferral	5.0		5.0
Other	3.9		3.8
Total Non-Current Regulatory Assets	277.1		263.8
Total Regulatory Assets		$295.6		$286.8

Non-Current Regulatory Liabilities
Plant Removal Obligations		$22.7		$19.7
Wholesale and Retail Contra AFUDC	37.6		19.7
Income Taxes	17.6		17.0
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	15.1		16.3
Other	10.1		8.3
Total Non-Current Regulatory Liabilities		$103.1		$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 14. Pension and Other Postretirement Benefit Plans.)


(c)	The cost recovery rider regulatory asset is primarily due to capital expenditures related to our Bison Wind Energy Center and is recognized in accordance with the accounting standards for alternative revenue programs.