REGULATORY MATTERS

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

2010 Minnesota General Rate Case. Minnesota Power’s current retail rates are based on a 2011 MPUC retail rate order that allows for a 10.38 percent return on common equity and a 54.29 percent equity ratio. As authorized by the MPUC, Minnesota Power also recognizes revenue under cost recovery riders for transmission, renewable and environmental investments and expenditures. (See Transmission Cost Recovery Rider, Renewable Cost Recovery Rider and Environmental Improvement Rider.) Revenue from cost recovery riders was $97.1 million in 2016 ($89.6 million in 2015; $71.8 million in 2014).

2016 Minnesota General Rate Case. On November 2, 2016, Minnesota Power filed a retail rate increase request with the MPUC seeking an average increase of approximately 9 percent for retail customers. The rate filing seeks a return on equity of 10.25 percent and a 53.8 percent equity ratio. On an annualized basis, the requested final rate increase would generate approximately $55 million in additional revenue. On December 12, 2016, due to a change in its electric sales forecast, Minnesota Power filed a request to modify its original interim rate proposal reducing its requested interim rate increase to $34.7 million from the original request of approximately $49 million; Minnesota Power will file to update its final retail rate increase request by February 28, 2017, and expects the final retail rate increase request to decrease similar to the interim rate proposal. In orders dated December 30, 2016, the MPUC accepted the filing as complete and authorized an annual interim rate increase of $34.7 million beginning January 1, 2017. As part of this rate increase request, we are seeking an extension of the recovery period for Boswell to better reflect recent environmental investments at the facility and mitigate rate increases for our customers. If approved, annual depreciation expense will be reduced by approximately $25 million. If the requested recovery period extension is not approved, we would expect final rates to be increased by a similar amount. We cannot predict the level of final rates that may be authorized by the MPUC.

Energy-Intensive Trade-Exposed (EITE) Customer Rates. The Minnesota Legislature enacted EITE customer ratemaking law in June 2015 which established that it is the energy policy of the state to have competitive rates for certain industries such as mining and forest products. In November 2015, Minnesota Power filed a rate schedule petition with the MPUC for EITE customers and a corresponding rider for EITE cost recovery. The rate proposal was revenue and cash flow neutral to Minnesota Power. In an order dated March 23, 2016, the MPUC dismissed the petition without prejudice, providing Minnesota Power the option to refile the petition with additional information or file a new petition. On June 30, 2016, Minnesota Power filed a revised EITE petition with the MPUC which included additional information on the net benefits analysis, limits on eligible customers and term lengths for the EITE discount. In an order dated December 21, 2016, the MPUC approved a reduction in rates for EITE customers and determined that cost recovery will be addressed in a separate proceeding. Minnesota Power provided additional information on cost recovery allocation methods in a December 30, 2016, compliance filing.

FERC-Approved Wholesale Rates. Minnesota Power has 16 non-affiliated municipal customers in Minnesota. SWL&P is a Wisconsin utility and a wholesale customer of Minnesota Power. All wholesale contracts include a termination clause requiring a three-year notice to terminate.

NOTE 4. REGULATORY MATTERS (Continued)

Electric Rates (Continued)

In April 2015, Minnesota Power amended its formula-based wholesale electric sales contract with the Nashwauk Public Utilities Commission, extending the term through June 30, 2028. No termination notice may be given for this contract prior to June 30, 2025. The electric service agreements with SWL&P and one other municipal customer are effective through January 31, 2020 and June 30, 2019, respectively. Under the agreement with SWL&P, no termination notice may be given prior to January 31, 2017. The other municipal customer provided termination notice for its contract on June 30, 2016. Minnesota Power currently provides approximately 29 MW of average monthly demand to this customer. The rates included in these three 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 Minnesota Power’s 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.

In September 2015, Minnesota Power amended its wholesale electric contracts with 14 municipal customers, extending the contract terms through December 31, 2024. No termination notices may be given prior to December 31, 2021. These contracts include fixed capacity charges through 2018; beginning in 2019, the capacity charge will not increase by more than two percent or decrease by more than one percent from the previous year’s capacity charge and will be determined using a cost-based formula methodology. The base energy charge for each year of the contract term will be set each January 1, subject to monthly adjustment, and will also be determined using a cost-based formula methodology.

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 3, 2016, 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. As a result of the MPUC approval of the certificate of need for the GNTL in June 2015, the project is eligible for cost recovery under the existing transmission cost recovery rider. Minnesota Power is funding the construction of the GNTL with Manitoba Hydro (see Great Northern Transmission Line), and anticipates including its portion of the investments and expenditures for the GNTL in future transmission factor filings.

Renewable Cost Recovery Rider. Minnesota Power has an approved cost recovery rider in place for investments and expenditures related to Bison and the restoration and repair of Thomson. Updated customer billing rates for the renewable cost recovery rider were approved by the MPUC in an order dated December 21, 2016, which allows Minnesota Power to charge retail customers on a current basis for the costs of constructing certain renewable investments plus a return on the capital invested. The approval is on a provisional basis pending the outcome of Minnesota Power’s 2016 general rate case.

In an order dated November 30, 2016, the MPUC directed Minnesota Power to attribute all North Dakota investment tax credits realized from Bison to Minnesota Power regulated retail customers. As a result of the adverse regulatory outcome, Minnesota Power has created a regulatory liability, and recorded a reduction in operating revenue for $15.0 million. The North Dakota investment tax credits previously recognized as income tax credits in Corporate and Other were reversed in 2016 resulting in an $8.8 million charge to net income. On December 20, 2016, Minnesota Power submitted a request for reconsideration with the MPUC. On February 9, 2017, the MPUC decided to reconsider its November 30, 2016 order and will be requesting further comments. Minnesota Power will provide further support on its position.

Prior to the November 30, 2016, MPUC order, Minnesota Power accounted for North Dakota investment tax credits based on the long-standing regulatory precedents of stand-alone allocation methodology of accounting for income taxes. The stand-alone method provides that income taxes (and credits) are calculated as if Minnesota Power was the only entity included in ALLETE’s consolidated federal and unitary state income tax returns. Minnesota Power had recorded a regulatory liability for North Dakota investment tax credits generated by its jurisdictional activity and expected to be realized in the future. North Dakota investment tax credits attributable to ALLETE’s apportionment and income of ALLETE’s other subsidiaries were included in the ALLETE consolidated group.

Minnesota Power also has approval for current cost recovery of investments and expenditures related to compliance with the Minnesota Solar Energy Standard. (See Minnesota Solar Energy Standard.) Currently, there is no approved customer billing rate for solar costs, but Minnesota Power expects to file its first solar factor filing in 2017 for recovery of costs related to the Camp Ripley solar project and community solar garden project.

NOTE 4. REGULATORY MATTERS (Continued)

Electric Rates (Continued)

Environmental Improvement Rider. Minnesota Power has an approved environmental improvement rider in place for investments and expenditures related to the implementation of the Boswell Unit 4 mercury emissions reduction plan completed in 2015. Updated customer billing rates for the environmental improvement rider were approved by the MPUC in an order dated December 21, 2016; however, Minnesota Power plans to delay implementation of the updated rates until resolution of its 2016 general rate case. (See 2016 Minnesota General Rate Case.)

Boswell Remaining Life Petition. In November 2015, Minnesota Power filed a petition with the MPUC for approval to extend Boswell’s remaining life to 2050 for all units and utilize the existing environmental improvement rider to credit a portion of the depreciation expense savings to customers. The extension request was based on the significant multi-emissions retrofit work done at Boswell Unit 3 and Boswell Unit 4. For efficiency, Minnesota Power withdrew its petition to extend Boswell’s remaining life as Minnesota Power decided to incorporate the life extension in its 2016 general rate case. In an order dated September 23, 2016, the MPUC approved Minnesota Power’s request to withdraw the petition. On February 1, 2017, Minnesota Power filed its 2017 remaining life depreciation petition in which it requested extending Boswell’s remaining life to 2050.

Annual Automatic Adjustment (AAA) of Charges. In an order dated June 2, 2016, the MPUC approved Minnesota Power’s AAA filings made in 2012 and 2013. The MPUC deferred action for 90 days on the AAA filing made in 2014 to review and confirm coal transportation costs and terms of service, which was subsequently completed on September 6, 2016, resulting in final approval of the filing. Minnesota Power’s AAA filings made in 2015 and 2016 are pending MPUC approval, and represent approximately $350 million in retail fuel cost recovery collected but subject to refund. These filings have historically been approved, and Minnesota Power currently expects full recovery of amounts represented by the AAA filings, although we cannot predict the outcome of the filings at the MPUC.

2016 Wisconsin General Rate Case. SWL&P’s current retail rates are based on a 2012 PSCW retail rate order that allows for a 10.9 percent return on common equity. On June 28, 2016, SWL&P filed a rate increase request with the PSCW requesting an average overall increase of 3.1 percent for retail customers (a 3.5 percent increase in electric rates, a 1.3 percent decrease in natural gas rates and a 7.8 percent increase in water rates). The rate filing seeks an overall return on equity of 10.9 percent and a 55 percent equity ratio. On an annualized basis, the requested rate increase would generate approximately $2.7 million in additional revenue. Hearings are expected to be scheduled in the first half of 2017. The Company anticipates new rates will take effect during the second quarter of 2017. We cannot predict the level of rates that may be approved by the PSCW.

Integrated Resource Plan (IRP). In 2013, the MPUC approved Minnesota Power’s 2013 IRP which detailed its EnergyForward strategic plan. Significant elements of the EnergyForward plan include major wind investments in North Dakota completed in 2014, the installation of emissions control technology at Boswell Unit 4 completed in December 2015, 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. In September 2015, Minnesota Power filed its 2015 IRP with the MPUC which included an analysis of a variety of existing and future energy resource alternatives and a projection of customer cost impact by class. The 2015 IRP also contained the next steps in Minnesota Power’s EnergyForward plan including the economic idling of Taconite Harbor Units 1 and 2 which occurred in September 2016, the ceasing of coal-fired operations at Taconite Harbor in 2020, and the addition of between 200 MW and 300 MW of natural gas-fired generation in the next decade.

In an order dated July 18, 2016, the MPUC approved Minnesota Power’s 2015 IRP with modifications. The order accepts Minnesota Power’s plans for Taconite Harbor, directs Minnesota Power to retire Boswell Units 1 and 2 no later than 2022, requires an analysis of generation and demand response alternatives to be filed with a natural gas resource proposal, and requires Minnesota Power to conduct request for proposals for additional wind, solar and demand response resource additions subject to further MPUC approvals. On October 19, 2016, Minnesota Power announced Boswell Units 1 and 2 will be retired in 2018 as the latest step in its EnergyForward strategic plan. Minnesota Power’s next IRP must be filed by February 1, 2018.

NOTE 4. REGULATORY MATTERS (Continued)

Great Northern Transmission Line. 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 2013, a certificate of need application was filed with the MPUC which was approved in a June 2015 order. Based on this order, Minnesota Power’s portion of the investments and expenditures for the project are eligible for cost recovery under its existing transmission cost recovery rider and are anticipated to be included in future transmission factor filings. In a December 2015 order, the FERC approved our request to recover on construction work in progress related to the GNTL from Minnesota Power’s wholesale customers. In 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 April 11, 2016, the MPUC approved the route permit which largely follows Minnesota Power’s preferred route, including the international border crossing, and on November 16, 2016, the U.S. Department of Energy issued a presidential permit, which was the final major regulatory approval needed before construction in the U.S. can begin in early 2017.

Manitoba Hydro must obtain regulatory and governmental approvals related to a new transmission line in Canada. In September 2015, Manitoba Hydro submitted the final preferred route and EIS for the transmission line in Canada to the Manitoba Conservation and Water Stewardship for regulatory approval. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in 2014.

Conservation Improvement Program (CIP). Minnesota requires electric utilities to spend a minimum of 1.5 percent of net gross operating revenues from service provided in the state on energy CIPs each year. These investments are recovered from certain retail customers through a combination of the conservation cost recovery charge included in retail base rates and a conservation program adjustment, which is adjusted annually through the CIP consolidated filing. The MPUC allows utilities to accumulate, in a deferred account for future cost recovery, all CIP expenditures, any financial incentive earned for cost-effective program achievements, and a carrying charge on the deferred account balance. Minnesota Power refers to its conservation programs collectively as the “Power of One”. On November 3, 2016, the Minnesota Department of Commerce approved Minnesota Power’s CIP triennial filing for 2017 through 2019, which outlines Minnesota Power’s CIP spending and energy-saving goals for 2017 through 2019. Minnesota Power’s CIP investment goal was $7.3 million for 2016 ($7.1 million for 2015; $6.9 million for 2014), with actual spending of $7.4 million in 2016 ($6.6 million in 2015; $7.2 million in 2014). The investment goals for 2017, 2018 and 2019 are $10.6 million, $10.8 million and $10.9 million, respectively.

Minnesota requires each utility to establish an annual energy-savings goal of 1.5 percent of annual retail energy sales. On April 1, 2016, Minnesota Power submitted its 2015 CIP consolidated filing, which detailed Minnesota Power’s CIP program results and requested a CIP financial incentive of $7.5 million based upon MPUC procedures. In an order dated July 19, 2016, the MPUC approved Minnesota Power’s CIP consolidated filing, including the requested CIP financial incentive which was recorded as revenue and as a regulatory asset. The approved financial incentive will be recovered through customer billing rates in 2016 and 2017. In 2015 and 2014, the CIP financial incentives recognized were $6.2 million and $8.7 million, respectively. CIP financial incentives are recognized in the period in which the MPUC approves the filing.

MISO Return on Equity Complaints. In 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 and ATC, to 9.15 percent. In December 2015, a federal administrative law judge ruled on the complaint proposing a reduction in the base return on equity to 10.32 percent, or 10.82 percent including an incentive adder for participation in a regional transmission organization. On September 28, 2016, the FERC issued an order affirming the administrative law judge’s recommendation.

In February 2015, an additional complaint was filed with the FERC seeking an order to further reduce the base return on equity to 8.67 percent. On June 30, 2016, a federal administrative law judge ruled on the February 2015, complaint proposing a further reduction in the base return on equity to 9.70 percent, or 10.20 percent including an incentive adder for participation in a regional transmission organization, subject to approval or adjustment by the FERC. A final decision from the FERC on the administrative law judge’s recommendation is expected in 2017. The final decision from the FERC is not expected to have a material impact on ALLETE’s Consolidated Financial Statements.

In January 2015, the FERC approved an incentive adder of up to 50 basis points on the allowed base return on equity for our participation in a regional transmission organization upon the resolution of each individual return on equity complaint.

NOTE 4. REGULATORY MATTERS (Continued)

Minnesota Solar Energy Standard. In 2013, legislation was enacted by the state of Minnesota requiring at least 1.5 percent of total retail electric sales, excluding sales to certain customers, to be generated by solar energy by the end of 2020. At least 10 percent of the 1.5 percent mandate must be met by solar energy generated by or procured from solar photovoltaic devices with a nameplate capacity of 20 kW or less. Minnesota Power has one completed solar project and another under development. In August 2015, Minnesota Power filed for MPUC approval of a 10 MW utility scale solar project at the Camp Ripley Minnesota Army National Guard base and training facility near Little Falls, Minnesota. In an order dated February 24, 2016, the MPUC approved the Camp Ripley solar project as eligible to meet the solar energy standard and for current cost recovery, which was subsequently finalized by the MPUC in an order dated December 12, 2016. The Camp Ripley solar project was completed in the fourth quarter of 2016. In September 2015, Minnesota Power filed for MPUC approval of a community solar garden project in northeastern Minnesota, which is comprised of a 1 MW solar array to be owned and operated by a third party with the output purchased by Minnesota Power and a 40 kW solar array that will be owned and operated by Minnesota Power. In an order dated July 27, 2016, the MPUC approved the community solar garden project and cost recovery, subject to certain compliance requirements. Minnesota Power believes these projects will meet approximately one-third of the overall mandate. Additionally, on January 19, 2017, the MPUC approved Minnesota Power’s proposal to increase the amount of solar rebates available for customer-sited solar installations and recover costs of the program through Minnesota Power’s renewable cost recovery rider. This proposal to incentivize customer-sited solar installations is expected to meet a portion of the required mandate related to solar photovoltaic devices with a nameplate capacity of 20 kW or less.

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 4. REGULATORY MATTERS (Continued)



Regulatory Assets and Liabilities
As of December 31	2016		2015
Millions
Current Regulatory Assets (a)
Deferred Fuel Adjustment Clause		$18.6		$10.6
Total Current Regulatory Assets	18.6		10.6
Non-Current Regulatory Assets
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	226.1		219.3
Income Taxes (c)	63.3		64.2
Cost Recovery Riders (d)	30.5		58.0
Asset Retirement Obligations (e)	26.0		21.6
PPACA Income Tax Deferral	5.0		5.0
Other	8.7		3.9
Total Non-Current Regulatory Assets	359.6		372.0
Total Regulatory Assets		$378.2		$382.6

Non-Current Regulatory Liabilities
Wholesale and Retail Contra AFUDC (f)		$56.8		$58.0
North Dakota Investment Tax Credits (g)	28.2		12.8
Income Taxes (c)	19.1		6.1
Plant Removal Obligations	19.1		22.1
Defined Benefit Pension and Other Postretirement Benefit Plans (b)	—		0.9
Other	2.6		5.1
Total Non-Current Regulatory Liabilities		$125.8		$105.0


(a)	Current regulatory assets are presented within 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 as actuarial gains and losses as well as prior service costs and credits, are recognized as regulatory assets or regulatory liabilities on the Consolidated Balance Sheet. The asset or liability will decrease as the deferred items are amortized and recognized as components of net periodic benefit cost. (See Note 15. Pension and Other Postretirement Benefit Plans.)


(c)	These costs represent the difference between deferred income taxes recognized for financial reporting purposes and amounts previously billed to our customers. This balance will decrease over the remaining life of the related temporary differences and flow through current income taxes.

(d)

The cost recovery rider regulatory assets are revenues not yet collected from our customers primarily due to capital expenditures related to Bison, investment in CapX2020 projects, and the Boswell Unit 4 environmental upgrade and are recognized in accordance with the accounting standards for alternative revenue programs. The cost recovery rider regulatory assets as of December 31, 2016, will be recovered within the next two years.


(e)	Asset retirement obligations will accrete and be amortized over the lives of the related property with asset retirement obligations.


(f)	Wholesale and Retail Contra AFUDC represents amortization to offset AFUDC Equity and Debt recorded during the construction period of our cost recovery rider projects prior to placing the projects in service. The regulatory liability will decrease over the remaining depreciable life of the related asset.


(g)	North Dakota investment tax credits expected to be realized from Bison that will be credited to Minnesota Power’s regulated retail customers over the remaining life of Bison through future renewable cost recovery rider fillings.