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Regulatory Matters | 12 Months Ended
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Dec. 31, 2013
Regulatory Matters [Abstract] |
Regulatory Matters [Text Block] | 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 allowed for a 10.38 percent return on common equity and a 54.29 percent equity ratio. FERC-Approved Wholesale Rates. In 2013, Minnesota Power’s non-affiliated municipal customers consisted of 16 municipalities in Minnesota and 1 Wisconsin utility which terminated its contract effective December 31, 2013. The 17 MW of average monthly demand provided to this wholesale customer is expected to be used to supply power for prospective additional retail and municipal load. SWL&P, a wholly-owned subsidiary of ALLETE, is also a Wisconsin utility and a customer of Minnesota Power. Minnesota Power’s formula-based rate contract with the Nashwauk Public Utilities Commission is effective through June 30, 2024, and the restated formula-based rate contracts 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 contract, no termination notice may be given prior to July 1, 2021. Under the restated contracts, 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 allowed 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. On November 12, 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 anticipate filing a petition in the first quarter of 2014 to include additional transmission investments and expenditures in customer billing rates. (See Note 1. Operations and Significant Accounting Policies.) 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 an order dated December 3, 2013. On September 25, 2013, the NDPSC approved the site permit for construction of Bison 4, a 205 MW wind project in North Dakota, which is an addition to our Bison Wind Energy Center. As a result, construction has 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 $55.6 million was spent through December 31, 2013. On January 17, 2014, the MPUC approved Minnesota Power’s petition seeking cost recovery for investments and expenditures related to Bison 4. We anticipate including Bison 4 as part of our renewable resources rider factor filing along with the Company’s other renewable projects in the first quarter of 2014, which upon approval, authorizes updated rates to be included on customer bills. (See Note 1. Operations and Significant Accounting Policies.) Rapids Energy Center. In December 2012, Minnesota Power filed with the MPUC for approval to transfer the assets of Rapids Energy Center from non-rate base generation to Minnesota Power’s Regulated Operations. Rapids Energy Center is a generation facility that is located at the UPM, Blandin Paper Mill. On October 9, 2013, the MPUC issued an order denying, without prejudice, the transfer of assets from non-rate base generation to Minnesota Power’s Regulated Operations. This decision had no impact on the Company’s consolidated financial position, results of operations, or cash flows. ALLETE Clean Energy. In August 2011, the Company filed with the MPUC for approval of certain affiliated interest agreements between ALLETE and ALLETE Clean Energy. These agreements relate to various relationships with ALLETE, including the accounting for certain shared services, as well as the transfer of transmission and wind development rights in North Dakota to ALLETE Clean Energy. These transmission and wind development rights are separate and distinct from those needed by Minnesota Power to meet Minnesota’s renewable energy standard requirements. In July 2012, the MPUC issued an order approving certain administrative items related to accounting for shared services and the transfer of meteorological towers, while deferring decisions related to transmission and wind development rights pending the MPUC’s further review of Minnesota Power’s future retail electric service needs. NOTE 5. REGULATORY MATTERS (Continued) Integrated Resource Plan. In an order dated November 12, 2013, 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 our Boswell Unit 4, planning for the proposed GNTL, conversion of Laskin from coal to cleaner-burning natural gas in 2015 and retiring Taconite Harbor Unit 3 in 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 proposes that Minnesota Power install pollution controls by early 2016 to address both the Minnesota mercury emissions reduction 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 $310 million. On November 5, 2013, the MPUC issued an order approving the Boswell Unit 4 mercury emissions reduction plan and cost recovery, establishing an environmental improvement rider. On November 25, 2013, environmental intervenors filed a petition for reconsideration with the MPUC which was subsequently denied in an order dated January 17, 2014. On December 20, 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 is expected to be approved in the second quarter of 2014. (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 240-mile 500 kV transmission line between Manitoba and Minnesota’s Iron Range. The GNTL is subject to various federal and state regulatory approvals. On October 21, 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. Manitoba Hydro must also obtain regulatory and governmental approvals related to new transmission lines and hydroelectric generation development in Canada. Upon receipt of all applicable permits and approvals, construction is anticipated to begin in 2016, and to be completed in 2020. (See Note 12. Commitments, Guarantees and Contingencies.) The Patient Protection and Affordable Care Act of 2010 (PPACA). In March 2010, the PPACA was signed into law. One of the provisions changed the tax treatment for retiree prescription drug expenses by eliminating the tax deduction for expenses that are reimbursed under Medicare Part D, beginning January 1, 2013. Based on this provision, we are subject to additional taxes in the future and were required to reverse previously recorded tax benefits which resulted in a non-recurring charge to net income of $4.0 million in 2010. In October 2010, we submitted a filing with the MPUC requesting deferral of the retail portion of the tax charge taken in 2010 resulting from the PPACA. In May 2011, the MPUC approved our request for deferral until the next rate case and as a result we recorded an income tax benefit of $2.9 million and a related regulatory asset of $5.0 million in the second quarter of 2011. 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 commission or over the corresponding period related to the asset or liability. NOTE 5. REGULATORY MATTERS (Continued)
Regulatory Assets and Liabilities |  |
As of December 31 | 2013 |  | 2012 |
Millions |  |
Current Regulatory Assets (a) |  |
Deferred Fuel |  | $23.0 |  |  | $22.5 |
Total Current Regulatory Assets | 23.0 |  | 22.5 |
Non-Current Regulatory Assets |  |
Future Benefit Obligations Under |  |
Defined Benefit Pension and Other Postretirement Plans (b) | 164.1 |  | 260.7 |
Income Taxes | 35.3 |  | 36.0 |
Asset Retirement Obligation | 16.0 |  | 12.1 |
Cost Recovery Riders (c) | 39.6 |  | 18.5 |
PPACA Income Tax Deferral | 5.0 |  | 5.0 |
Conservation Improvement Program | — |  | 4.3 |
Other | 3.8 |  | 3.7 |
Total Non-Current Regulatory Assets | 263.8 |  | 340.3 |
Total Regulatory Assets |  | $286.8 |  |  | $362.8 |
Non-Current Regulatory Liabilities |  |
Income Taxes |  | $17.0 |  |  | $19.5 |
Plant Removal Obligations | 19.7 |  | 18.1 |
Wholesale and Retail Contra AFUDC | 19.7 |  | 15.5 |
Defined Benefit Pension and Other Postretirement Plans (b) | 16.3 |  | — |
Other | 8.3 |  | 7.0 |
Total Non-Current Regulatory Liabilities |  | $81.0 |  |  | $60.1 |
(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 our Consolidated Balance Sheet (See Note 17. 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.

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