Commitments, Guarantees and Contingencies

12 Months Ended

Dec. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments, Guarantees and Contingencies [Text Block]

COMMITMENTS, GUARANTEES AND CONTINGENCIES

The following table details the estimated minimum annual payments for certain long-term commitments:

As of December 31, 2016
Millions	2017		2018		2019		2020		2021		Thereafter
Coal, Rail and Shipping Contracts		$27.9		$27.0		$1.8	—		—		—
Leasing Agreements		$13.7		$12.0		$10.7		$7.5		$5.9		$18.3
PPAs (a)		$98.0		$102.9		$105.5		$113.4		$143.3		$1,803.9

(a) Excludes the agreement with Manitoba Hydro expiring in 2022, as this contract is for surplus energy only, and the 133 MW agreement with Manitoba Hydro commencing in 2020, as our obligation under this contract is subject to construction of additional transmission capacity. Also excludes Oliver Wind I and Oliver Wind II, as Minnesota Power only pays for energy as it is delivered.

Coal, Rail and Shipping Contracts. Minnesota Power has coal supply agreements providing for the purchase of a significant portion of its coal requirements through December 2017 and a portion of its coal requirements through December 2021. Minnesota Power also has coal transportation agreements in place for the delivery of a significant portion of its coal requirements through December 2018. The delivered costs of fuel for Minnesota Power’s generation are recoverable from Minnesota Power’s utility customers through the fuel adjustment clause.

Leasing Agreements. BNI Energy is obligated to make lease payments for a dragline totaling $2.8 million annually during the lease term, which expires in 2027. BNI Energy has the option at the end of the lease term to renew the lease at fair market value, to purchase the dragline at fair market value, or to surrender the dragline and pay a $3.0 million termination fee. We also lease other properties and equipment under operating lease agreements with terms expiring through 2023. Total lease expense was $17.1 million in 2016 ($17.3 million in 2015; $14.8 million in 2014).

Power Purchase Agreements. Our long-term PPAs have been evaluated under the accounting guidance for variable interest entities. We have determined that either we have no variable interest in the PPAs, or where we do have variable interests, we are not the primary beneficiary; therefore, consolidation is not required. These conclusions are based on the fact that we do not have both control over activities that are most significant to the entity and an obligation to absorb losses or receive benefits from the entity’s performance. Our financial exposure relating to these PPAs is limited to our capacity and energy payments.

Square Butte PPA. Minnesota Power has a PPA with Square Butte that extends through December 2026 (Agreement). Minnesota Power is obligated to pay its pro rata share of Square Butte’s costs based on its entitlement to the output of Square Butte’s 455 MW coal-fired generating unit. Minnesota Power’s output entitlement under the Agreement is 50 percent for the remainder of the Agreement, subject to the provisions of the Minnkota Power PSA described in the following table. Minnesota Power’s payment obligation will be suspended if Square Butte fails to deliver any power, whether produced or purchased, for a period of one year. Square Butte’s costs consist primarily of debt service, operating and maintenance, depreciation and fuel expenses. As of December 31, 2016, Square Butte had total debt outstanding of $327.7 million. Annual debt service for Square Butte is expected to be approximately $45 million in each of the next five years, 2017 through 2021, of which Minnesota Power’s obligation is 50 percent. Fuel expenses are recoverable through Minnesota Power’s fuel adjustment clause and include the cost of coal purchased from BNI Energy under a long-term contract.

Minnesota Power’s cost of power purchased from Square Butte during 2016 was $73.3 million ($77.8 million in 2015; $70.1 million in 2014). This reflects Minnesota Power’s pro rata share of total Square Butte costs based on the 50 percent output entitlement. Included in this amount was Minnesota Power’s pro rata share of interest expense of $9.6 million in 2016 ($10.1 million in 2015; $10.5 million in 2014). Minnesota Power’s payments to Square Butte are approved as a purchased power expense for ratemaking purposes by both the MPUC and the FERC.

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Power Purchase Agreements (Continued)

Minnesota Power has also entered into the following agreements for the purchase or sale of capacity and energy as of December 31, 2016:

Counterparty	Quantity	Product	Commencement	Expiration	Pricing
PPAs
Great River Energy
PPA 1	50 MW	Capacity / Energy	June 2016	May 2020	(a)
PPA 2	50 MW	Capacity	June 2016	May 2020	Fixed
PPA 3	50 MW	Capacity	June 2017	May 2020	Fixed
Manitoba Hydro
PPA 1	(b)	Energy	May 2011	April 2022	Forward Market Prices
PPA 2	50 MW	Capacity / Energy	June 2015	May 2020	(c)
PPA 3	50 MW	Capacity	June 2017	May 2020	Fixed
PPA 4 (d)	250 MW	Capacity / Energy	June 2020	May 2035	(e)
PPA 5 (d)	133 MW	Energy	(f)	(f)	Forward Market Prices
Minnkota Power	50 MW	Capacity / Energy	June 2016	May 2020	(g)
Oliver Wind I	(h)	Energy	December 2006	December 2031	Fixed
Oliver Wind II	(h)	Energy	December 2007	December 2032	Fixed
Shell Energy	50 MW	Energy	January 2017	December 2019	Fixed
TransAlta	(i)	Energy	January 2017	December 2019	Fixed
PSAs
Basin
PSA 1	100 MW	Capacity / Energy	May 2010	April 2020	(j)
PSA 2	100 MW	Capacity	June 2016	June 2018	Fixed
Minnkota Power	(k)	Capacity / Energy	June 2014	December 2026	(k)
Silver Bay Power	(l)	Energy	January 2017	December 2031	(m)

(a) The capacity price is fixed and the energy price is based on a formula that includes an annual fixed price component adjusted for changes in a natural gas index, as well as market prices.

(b) The energy purchased consists primarily of surplus hydro energy on Manitoba Hydro's system and is delivered on a non-firm basis. Minnesota Power will purchase at least one million MWh of energy over the contract term.

(c) The capacity and energy prices are adjusted annually by the change in a governmental inflationary index.

(d) Agreements are subject to the construction of additional transmission capacity between Manitoba and the U.S., along with construction of new hydroelectric generating capacity in Manitoba. (See Great Northern Transmission Line.)

(e) The capacity price is adjusted annually until 2020 by the change in a governmental inflationary index. The energy price is based on a formula that includes an annual fixed component adjusted for the change in a governmental inflationary index and a natural gas index, as well as market prices.

(f) The contract term shall be the 20-year period beginning on the in-service date for the GNTL. (See Great Northern Transmission Line.)

(g) The agreement includes a fixed capacity charge and energy prices that escalate at a fixed rate annually over the term.

(h) The PPAs provide for the purchase of all output from the 50 MW Oliver Wind I and 48 MW Oliver Wind II wind energy facilities.

(i) The energy purchased under the 50 MW PPA is during off-peak hours and the 100 MW PPA is during on-peak hours.

(j) The capacity charge is based on a fixed monthly schedule with a minimum annual escalation provision. The energy charge is based on a fixed monthly schedule and provides for annual escalation based on the cost of fuel. The agreement also allows Minnesota Power to recover a pro rata share of increased costs related to emissions that occur during the last five years of the contract.

(k) Minnesota Power is selling a portion of its entitlement from Square Butte to Minnkota Power, resulting in Minnkota Power’s net entitlement increasing and Minnesota Power’s net entitlement decreasing until Minnesota Power’s share is eliminated at the end of 2025. Of Minnesota Power’s 50 percent output entitlement, it sold to Minnkota Power approximately 28 percent in 2016 (28 percent in 2015; 23 percent in 2014). (See Square Butte PPA.)

(l) Silver Bay Power supplies approximately 90 MW of load to Northshore Mining, an affiliate of Silver Bay Power, which has been served predominately through self-generation by Silver Bay Power. In the years 2016 through 2019, Minnesota Power will supply Silver Bay Power with at least 50 MW of energy and Silver Bay Power will have the option to purchase additional energy from Minnesota Power as it transitions away from self-generation. On December 31, 2019, Silver Bay Power will cease its self-generation and Minnesota Power will supply the energy requirements for Silver Bay Power.

(m) The energy pricing is fixed through 2019 with pricing in later years escalating at a fixed rate annually and adjusted for changes in a natural gas index.

Transmission. We continue to make investments in transmission opportunities that strengthen or enhance the transmission grid or take advantage of our geographical location between sources of renewable energy and end users. These include the GNTL, investments to enhance our own transmission facilities, investments in other transmission assets (individually or in combination with others) and our investment in ATC.

Great Northern Transmission Line. As a condition of the 250 MW long-term PPA entered into with Manitoba Hydro, construction of additional transmission capacity is required. As a result, Minnesota Power and Manitoba Hydro proposed construction of the GNTL, an approximately 220-mile 500-kV transmission line between Manitoba and Minnesota’s Iron Range in order to strengthen the electric grid, enhance regional reliability and promote a greater exchange of sustainable energy.

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. (See Note 4. Regulatory Matters.) 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. Construction is expected to be completed in 2020, and total project cost in the U.S., including substation work, is estimated to be between $560 million and $710 million. Minnesota Power is expected to have majority ownership of the transmission line.

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.

Environmental Matters.

Our businesses are subject to regulation of environmental matters by various federal, state and local authorities. A number of regulatory changes to the Clean Air Act, the Clean Water Act and various waste management requirements have recently been promulgated by both the EPA and state authorities. Minnesota Power’s facilities are subject to additional regulation under many of these regulations. In response to these regulations, Minnesota Power is reshaping its generation portfolio over time to reduce its reliance on coal, has installed cost-effective emission control technology, and advocates for sound science and policy during rulemaking implementation.

We consider our businesses to be in substantial compliance with currently applicable environmental regulations and believe all necessary permits to conduct such operations have been obtained. We anticipate that with many state and federal environmental regulations finalized, or to be finalized in the near future, potential expenditures for future environmental matters may be material and may require significant capital investments. Minnesota Power has evaluated various environmental compliance scenarios using possible outcomes of environmental regulations to project power supply trends and impacts on customers.

We review environmental matters on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated based on current law and existing technologies. Accruals are adjusted as assessment and remediation efforts progress, or as additional technical or legal information becomes available. Accruals for environmental liabilities are included in the Consolidated Balance Sheet at undiscounted amounts and exclude claims for recoveries from insurance or other third parties. Costs related to environmental contamination treatment and cleanup are expensed unless recoverable in rates from customers.

Air. The electric utility industry is regulated both at the federal and state level to address air emissions. Minnesota Power’s generating facilities mainly burn low-sulfur western sub-bituminous coal. All of Minnesota Power’s coal-fired generating facilities are equipped with pollution control equipment such as scrubbers, baghouses and low NO_X technologies. Under currently applicable environmental regulations, these facilities are substantially compliant with emission requirements.

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

New Source Review (NSR). In 2008, Minnesota Power received a Notice of Violation (NOV) from the EPA asserting violations of the NSR requirements of the Clean Air Act at Boswell and Laskin Unit 2 between the years of 1981 and 2001. Minnesota Power received an additional NOV in April 2011 alleging that two projects undertaken at Rapids Energy Center in 2004 and 2005 should have been reviewed under the NSR requirements and that the Rapids Energy Center’s Title V permit was violated. Minnesota Power reached a settlement with the EPA regarding these NOVs and entered into a Consent Decree which was approved by the U.S. District Court for the District of Minnesota in 2014. The Consent Decree provided for, among other requirements, more stringent emissions limits at all affected units, the option of refueling, retrofits or retirements at certain small coal units, and the addition of 200 MW of wind energy. Provisions of the Consent Decree require that, by no later than December 31, 2018, Boswell Units 1 and 2 must be retired, refueled, repowered, or emissions rerouted through existing emission control technology at Boswell. On October 19, 2016, Minnesota Power announced that Boswell Units 1 and 2 will be retired in 2018 as the latest step in its EnergyForward strategic plan. We believe that costs to retire will be eligible for recovery in rates over time, subject to regulatory approval in a rate proceeding.

Cross-State Air Pollution Rule (CSAPR). The CSAPR requires a total of 28 states in the eastern half of the U.S., including Minnesota, to reduce power plant emissions that contribute to ozone or fine particulate pollution in other states. The CSAPR does not require installation of controls; rather it requires that facilities have sufficient allowances to cover their emissions on an annual basis. These allowances are allocated to facilities from each state’s annual budget, and can be bought and sold.

In 2014, the EPA distributed the CSAPR allowances to CSAPR-subject units for the Phase I years (2015 and 2016). Phase II allowances (2017 and beyond) for 2017 and 2018 were distributed on June 29, 2016. Based on our review of the NO_x and SO₂ Phase I and Phase II allowances already issued, and Phase II allowances not yet issued, we currently expect projected generation levels and emission rates will result in compliance in both Phase I and Phase II.

Mercury and Air Toxics Standards (MATS) Rule (formerly known as the Electric Generating Unit Maximum Achievable Control Technology (MACT) Rule). Under Section 112 of the Clean Air Act, the EPA is required to set emission standards for hazardous air pollutants (HAPs) for certain source categories. The EPA published the final MATS rule in the Federal Register in 2012, addressing such emissions from coal-fired utility units greater than 25 MW. There are currently 187 listed HAPs that the EPA is required to evaluate for establishment of MACT standards. In the final MATS rule, the EPA established categories of HAPs, including mercury, trace metals other than mercury, acid gases, dioxin/furans and organics other than dioxin/furans. The EPA also established emission limits for the first three categories of HAPs and work practice standards for the remaining categories. Affected sources were required to be in compliance with the rule by April 2015. States had the authority to grant sources a one-year extension. The MPCA approved Minnesota Power’s request for an extension of the date of compliance for the Boswell Unit 4 environmental upgrade to April 1, 2016. Construction on the project to implement the Boswell Unit 4 mercury emissions reduction plan was completed in 2015. Boswell Unit 3 is also subject to the MATS rule; however, investments and compliance work completed at Boswell Unit 3, including the emission reduction investments completed in 2009, meet the requirements of the MATS rule. The conversion of Laskin Units 1 and 2 to natural gas in June 2015 positioned those units for MATS compliance.

In June 2015, the U.S. Supreme Court reversed and remanded an earlier U.S. Court of Appeals for the D.C. Circuit decision on the MATS rule. The U.S. Supreme Court ruled that it was unreasonable for the EPA to deem cost of compliance irrelevant in determining that regulation of emissions of hazardous air pollutants from power plants was “appropriate and necessary” under Section 112 of the Clean Air Act. The MATS rule remains in effect until the U.S. Court of Appeals for the D.C. Circuit acts on the remand. In December 2015, the U.S. Court of Appeals for the D.C. Circuit rejected a motion by utilities and states to vacate the MATS rule, instead ordering the rule to remain in effect while the EPA completes its review. On April 15, 2016, the EPA announced its determination that the MATS rule is appropriate and necessary, even after considering cost of compliance. The outcome of these proceedings is not expected to have a material impact on Minnesota Power generation due to emission reduction obligations under the Minnesota Mercury Emissions Reduction Act and the Consent Decree. (See New Source Review.)

Minnesota Mercury Emissions Reduction Act/Rule. In order to comply with the 2006 Minnesota Mercury Emissions Reduction Act, which was incorporated into rules promulgated by the MPCA in September 2014, Minnesota Power was required to implement a mercury emissions reduction project for Boswell Unit 4 by December 31, 2018. The Boswell Unit 4 environmental upgrade discussed above (see Mercury and Air Toxics Standards (MATS) Rule) fulfills the requirements of the Minnesota Mercury Emissions Reduction Act.

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

EPA National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial and Institutional Boilers and Process Heaters. A final rule issued by the EPA for Industrial Boiler MACT became effective in 2012. Major existing sources had until January 31, 2016, to achieve compliance with the final rule and July 29, 2016, to perform initial compliance demonstrations. Minnesota Power’s Hibbard Renewable Energy Center and Rapids Energy Center are subject to this rule and are currently in compliance. Compliance consists largely of adjustments to our operating practices; therefore, the costs for complying with the final rule are not expected to be material.

National Ambient Air Quality Standards (NAAQS). The EPA is required to review the NAAQS every five years. If the EPA determines that a state’s air quality is not in compliance with the NAAQS, the state is required to adopt plans describing how it will reduce emissions to attain the NAAQS. These state plans often include more stringent air emission limitations on sources of air pollutants than the NAAQS. Four NAAQS have either recently been revised or are currently proposed for revision, as described below.

Ozone NAAQS. The EPA has proposed more stringent control related to emissions that result in ground level ozone. In 2010, the EPA proposed to revise the 2008 eight-hour ozone standard of 75 parts per billion (ppb) and to adopt a secondary standard for the protection of sensitive vegetation from ozone-related damage. In October 2015, the EPA published the final rule in the Federal Register revising the eight-hour ozone standard to 70 ppb with a secondary standard also set at 70 ppb. All areas of Minnesota currently meet the new standard based on the most recent available ambient monitoring data; however, some areas in the metropolitan Twin Cities and southwest portion of the state are close to exceeding the standard. As a result, voluntary efforts to reduce ozone continue in the state. No additional costs for compliance are anticipated at this time.

Particulate Matter NAAQS. The EPA finalized the Particulate Matter NAAQS in 2006. Since then, the EPA has established more stringent 24-hour and annual average fine particulate matter (PM_2.5) standards; the 24-hour coarse particulate matter standard has remained unchanged. In 2012, the EPA issued a final rule implementing a more stringent annual PM_2.5 standard, while retaining the current 24-hour PM_2.5 standard. To implement the new annual PM_2.5 standard, the EPA is revising aspects of relevant monitoring, designation and permitting requirements. New projects and permits must comply with the new standard, which is generally demonstrated by modeling at the facility level.

Under the final rule, states will be responsible for additional PM_2.5 monitoring, which will likely be accomplished by relocating or repurposing existing monitors. The EPA asked states to submit attainment designations by 2013, based on already available monitoring data, and issued designations of the 2012 revised primary annual fine particulate attainment status in 2014. The EPA designated the entire state of Minnesota as unclassifiable/attainment; however, Minnesota sources may ultimately be required to reduce their emissions to assist with attainment in neighboring states. On September 27, 2016, environmental groups filed a lawsuit against the EPA in the United States District Court for the Northern District of California alleging the EPA had failed to fully implement the PM_2.5 standards in 24 states, including Minnesota, by not enforcing states’ submittals of required infrastructure SIPs for the 2012 PM_2.5 NAAQS. The outcome of this litigation is uncertain, and as such any costs for complying with the final Particulate Matter NAAQS cannot be estimated at this time.

SO₂ and NO₂ NAAQS. During 2010, the EPA finalized one-hour NAAQS for SO₂ and NO₂. Ambient monitoring data indicates that Minnesota is likely in compliance with these standards; however, the one-hour SO₂ NAAQS also requires the EPA to evaluate additional modeling and monitoring considerations to determine attainment. In 2012, the MPCA notified Minnesota Power that modeling had been suspended as a result of the EPA’s announcement that the SIP submittals would not require modeling demonstrations for states, such as Minnesota, where ambient monitors indicate compliance with the standard. The EPA notified states that their infrastructure SIPs for maintaining attainment of the standard were required to be submitted to the EPA for approval by 2013. However, the State of Minnesota delayed completing the documents pending EPA guidance to states for preparing the SIP submittal.

In 2013, the EPA provided guidance to states regarding implementation of the one-hour NO₂ NAAQS and in 2014, as clarified in February 2015, the MPCA submitted a SIP revision to the EPA addressing the infrastructure requirements of Sections 110(a)(1) and 110(a)(2) of the Clean Air Act in regards to the one-hour NO₂ and SO₂ NAAQS, among other standards. The SIP stated that since the EPA determined in 2012 that no area in the country is in violation of the one-hour NO₂ NAAQS, there are no nonattainment areas in the country for this pollutant, and therefore Minnesota’s NO₂ emissions cannot be significantly contributing to nonattainment in any other state. In October 2015, the EPA published in the Federal Register an approval and partial disapproval of the 2014 SIP revision. According to the MPCA, the partial disapproval is regarding state delegation of a program unrelated to the one-hour NAAQS for SO₂ and NO_2, and is not expected to require further action. As such, additional compliance costs for the one-hour NO₂ NAAQS are not expected at this time. 

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

In August 2015, the EPA finalized the SO₂ data requirements rule (DRR) for the 2010 one-hour NAAQS to assist the states in implementing the standard. The rule sets emissions thresholds and exemptions for facilities that trigger modeling requirements. On January 8, 2016, the MPCA informed the EPA of the Minnesota sources subject to the rule, confirming that Boswell and Taconite Harbor are the only Minnesota Power generating facilities subject to the DRR. The MPCA was required to notify the EPA as to how each source will evaluate air quality by July 1, 2016. Compliance options include ambient monitoring, modeling existing enforceable emission limits, or modeling actual emissions. The MPCA initially informed Minnesota Power that compliant SO₂ modeling recently completed at these facilities would satisfy the DRR obligations and no further modeling would be required; however, the DRR also requires facilities have federally-enforceable permit limits at which the one-hour SO₂ NAAQS compliance was modeled by January 13, 2017. Taconite Harbor was issued an amended air permit on September 1, 2016, containing the new modeling limits at that facility. The MPCA did not meet the January 13, 2017, deadline to amend the Boswell permit. The MPCA is in discussions with the EPA on alternate compliance pathways to use existing completed modeling at current limits. Compliance costs for the one-hour SO₂ NAAQS are not expected to be material.

Class I Air Quality Petitions and Requests. In 2014, the Fond du Lac Band of Lake Superior Chippewa (Fond du Lac Band) announced its intent to petition the EPA to redesignate its reservation air shed from Class II to Class I air quality pursuant to Section 164(c) of the Clean Air Act. The Fond du Lac Band does not currently possess authority to directly regulate air quality. Class I air shed status, if granted, would allow the Fond du Lac Band to impose more stringent Clean Air Act protections within the boundaries of the Fond du Lac reservation, including the reservation air shed, near Cloquet, Minnesota. Five other reservations across the U.S. have received Class I status. A public hearing was held by the Fond du Lac Band in October 2014, and the extended public comment period on the petition expired in November 2014. After the Fond du Lac Band prepares responses to the comments, it is anticipated to make a formal submittal request to the EPA. 

In 2013, the Bad River Band of Lake Superior Chippewa (Bad River Band) announced its intent to petition the EPA to redesignate its reservation air shed, which is located approximately 100 miles east of Duluth, Minnesota, from Class II to Class I air quality pursuant to Section 164(c) of the Clean Air Act. The Class I analysis report was issued by the Bad River Band in January 2015 which was followed by public hearings in March 2015 and a public comment period ending in May 2015. After the Bad River Band prepares responses to the comments, it is also anticipated to make a formal submittal request to the EPA.

There is no deadline for the approval, denial, or modification of these requests by the EPA. We are unable to determine the impact of potential Class I status on the Company’s operations at this time. 

Climate Change. The scientific community generally accepts that emissions of GHG are linked to global climate change which creates physical and financial risks. Physical risks could include, but are not limited to: increased or decreased precipitation and water levels in lakes and rivers; increased temperatures; and changes in the intensity and frequency of extreme weather events. These all have the potential to affect the Company’s business and operations. We are addressing climate change by taking the following steps that also ensure reliable and environmentally compliant generation resources to meet our customers’ requirements:

• Expanding our renewable energy supply;

• Providing energy conservation initiatives for our customers and engaging in other demand side efforts;

• Improving efficiency of our energy generating facilities;

• Supporting research of technologies to reduce carbon emissions from generation facilities and carbon sequestration efforts; and

• Evaluating and developing less carbon intensive future generating assets such as efficient and flexible natural gas generating facilities.

President Obama’s Climate Action Plan. In 2015, President Obama announced an updated Climate Action Plan (CAP) that calls for implementation of measures that reduce GHG emissions in the U.S., emphasizing means such as expanded deployment of renewable energy resources, energy and resource conservation, energy efficiency improvements and a shift to fuel sources that have lower emissions. Certain portions of the CAP directly address electric utility GHG emissions.

EPA Regulation of GHG Emissions. In 2010, the EPA issued the Prevention of Significant Deterioration (PSD) and Title V Greenhouse Gas Tailoring Rule (Tailoring Rule). The Tailoring Rule establishes permitting thresholds required to address GHG emissions for new facilities, existing facilities that undergo major modifications and other facilities characterized as major sources under the Clean Air Act’s Title V program. For our existing facilities, the rule does not require amending our existing Title V operating permits to include GHG requirements. However, GHG requirements are likely to be added to our existing Title V operating permits by the MPCA as these permits are renewed or amended.

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

In late 2010, the EPA issued guidance to permitting authorities and affected sources to facilitate incorporation of the Tailoring Rule permitting requirements into the Title V and PSD permitting programs. The guidance stated that the project-specific, top‑down Best Available Control Technology (BACT) determination process used for other pollutants will also be used to determine BACT for GHG emissions. Through sector-specific white papers, the EPA also provided examples and technical summaries of GHG emission control technologies and techniques the EPA considers available or likely to be available to sources. It is possible that these control technologies could be determined to be BACT on a project-by-project basis.

In 2014, the U.S. Supreme Court invalidated the aspect of the Tailoring Rule that established higher permitting thresholds for GHG than for other pollutants subject to PSD. However, the court also upheld the EPA’s power to require BACT for GHG from sources already subject to regulation under PSD. Minnesota Power’s coal-fired generating facilities are already subject to regulation under PSD, so we anticipate that ultimately PSD for GHG will apply to our facilities, but the timing of the promulgation of a replacement for the Tailoring Rule is uncertain. The PSD applies to existing facilities only when they undertake a major modification that increases emissions. At this time, we are unable to predict the compliance costs that we might incur.

On October 3, 2016, the EPA published a proposed rule in the Federal Register to revise its PSD and Title V regulatory provisions concerning GHG emissions. In this proposed rule, the EPA proposes to amend its regulations to clarify that a source’s obligation to obtain a PSD or Title V permit is triggered only by non-GHG pollutants. If the PSD or Title V permitting requirements are triggered by non-GHG, NSR pollutants, then these programs will also apply to the source’s GHG emissions. The proposed rule, as currently written, is not expected to have a material impact on the Title V permitting for current operations.

In 2012, the EPA announced a proposed rule to apply CO₂ emission New Source Performance Standards (NSPS), under Section 111(b) of the Clean Air Act, to new fossil fuel-fired electric generating units. The proposed NSPS would have applied only to new or re-powered units. Based on the volume of comments received, the EPA announced its intent to re-propose the rule. In 2013, the EPA retracted its 2012 proposal and announced the release of a revised NSPS for new or re-powered utility CO₂ emissions.

In 2014, the EPA announced a proposed rule under Section 111(d) of the Clean Air Act for existing power plants entitled “Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Generating Units”, also referred to as the Clean Power Plan (CPP). The EPA issued the final CPP in August 2015, together with a proposed federal implementation plan and a model rule for emissions trading. Petitions for review of the rule were filed with the U.S. Court of Appeals for the District of Columbia Circuit. On February 9, 2016, the U.S. Supreme Court issued an order staying the effectiveness of the rule until after the appellate court process is complete. On September 27, 2016, the U.S. Court of Appeals for the District of Columbia heard oral arguments and is currently deliberating. The EPA is precluded from enforcing the CPP while the U.S. Supreme Court stay is in force; however, the MPCA has been holding a series of meetings on the CPP for educational and planning purposes in the interim. Minnesota Power has been actively involved in these MPCA meetings, and is closely monitoring the appeals process.

If upheld, the CPP would establish uniform CO₂ emission performance rates for existing fossil fuel-fired and natural gas-fired combined cycle generating units, setting state-specific goals for CO₂ emissions from the power sector. State goals were determined based on CPP source-specific performance emission rates and each state’s mix of power plants. The EPA maintains such goals are achievable if a state undertakes a combination of measures across its power sector that constitutes the EPA’s guideline for a Best System of Emission Reductions (BSER). BSER is comprised of three building blocks: 1) improved fossil fuel power plant efficiency, 2) increased reliance on low-emitting power sources by generating more electricity from existing natural gas combined cycle units, and 3) building more zero- and low-emitting power sources, including renewable energy. States may also choose to include avoided CO₂ emissions from customer energy efficiency measures for credit towards meeting state goals.

State goals under the CPP are expressed as both mass-based and rate-based, and include interim goals to be met over the years 2022 through 2029, as well as a final goal to be met in 2030 and thereafter. Under the original schedule for the CPP, each state would have been required to develop a SIP by September 6, 2016, or by September 6, 2018, if granted an extension. Due to the U.S. Supreme Court order staying the effectiveness of the CPP, those SIP submittal dates are not currently in effect. If the CPP is upheld at the completion of the appellate court process, all of the CPP regulatory deadlines are expected to be reset based on the length of time that the appeals process takes.

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

In developing its plan, a state may choose to meet either the mass-based or the rate-based goals. Minnesota Power is currently evaluating the CPP as it relates to the State of Minnesota as well as its potential impact on the Company and is actively discussing potential compliance scenarios with regulatory agencies and in public stakeholder meetings. Minnesota has already initiated several measures consistent with those called for under the CAP and CPP. Minnesota Power is implementing its EnergyForward strategic plan that provides for significant emission reductions and diversifying its electricity generation mix to include more renewable and natural gas energy. (See Note 4. Regulatory Matters.)

The EPA accepted comments through November 1, 2016, on the proposed Clean Energy Incentive Program (CEIP) that may be facilitated as part of the CPP. The CEIP would reassign CPP emission rate credits or allowances for certain early action or designated deployments of renewable energy and energy efficiency measures.

We are unable to predict the GHG emission compliance costs we might incur; however, the costs could be material. Minnesota Power would seek recovery of any additional costs through a rate proceeding.

Minnesota’s Next Generation Energy Act of 2007. In April 2014, the U.S. District Court for the District of Minnesota ruled that part of Minnesota’s Next Generation Energy Act of 2007 (NEGA) violated the Commerce Clause of the U.S. Constitution. The portions of the law which were ruled unconstitutional prohibited the importation of power from a new CO₂-producing facility outside of Minnesota and prohibited the entry into new long-term PPAs that would increase CO₂ emissions in Minnesota. The State of Minnesota appealed the decision to the U.S. Court of Appeals for the Eighth Circuit in 2014. On June 15, 2016, the U.S. Court of Appeals for the Eighth Circuit upheld the federal district court’s decision that part of the NEGA violated the Commerce Clause of the U.S. Constitution. Minnesota Governor Dayton subsequently announced that the State of Minnesota would cease pursuing further appeals of the U.S. Court of Appeals for the Eighth Circuit’s decision.

Water. The Clean Water Act requires NPDES permits be obtained from the EPA (or, when delegated, from individual state pollution control agencies) for any wastewater discharged into navigable waters. We have obtained all necessary NPDES permits, including NPDES storm water permits for applicable facilities, to conduct our operations.

Clean Water Act - Aquatic Organisms. In 2011, the EPA announced proposed regulations under Section 316(b) of the Clean Water Act that set standards applicable to cooling water intake structures for the protection of aquatic organisms. The proposed regulations would require existing large power plants and manufacturing facilities that withdraw greater than 25 percent of water from adjacent water bodies for cooling purposes, and have a design intake flow of greater than 2 million gallons per day, to limit the number of aquatic organisms that are impacted by the facility’s intake structure or cooling system. The Section 316(b) rule was effective in 2014. The Section 316(b) standards will be implemented through NPDES permits issued to the covered facilities with compliance timing dependent on individual NPDES renewal schedules. No NPDES permits for Minnesota Power generating facilities have been re-issued containing Section 316(b) requirements since the final rule was published, so at this time we are unable to determine the final cost of compliance. Should the MPCA require significant modifications to Minnesota Power’s intake structures, a preliminary assessment suggests costs of compliance up to $15 million over the next 5 years. Minnesota Power would seek recovery of any additional costs through a general rate case.

Steam Electric Power Generating Effluent Guidelines. In 2013, the EPA announced proposed revisions to the federal effluent limit guidelines (ELG) for steam electric power generating stations under the Clean Water Act. The final ELG was issued in September 2015. It sets effluent limits and prescribes BACT for several wastewater streams, including flue gas desulphurization (FGD) water and coal combustion landfill leachate. The ELG rule also prohibits the discharge of bottom and fly ash contact waters. Compliance with the final rule is required between November 1, 2018, and December 31, 2023.

We are reviewing the final rule and evaluating its potential impact on Minnesota Power’s operations, primarily at Boswell. Boswell currently discharges bottom ash contact water through its NPDES permit, and also has a closed-loop FGD system that does not currently discharge, but may do so in the future. Under the final ELG rule, bottom ash discharge would not be allowed and bottom ash contact water would either need to be re-used in a closed-loop process, routed to a FGD scrubber, or the bottom ash handling system would need to be converted to a dry process. If the FGD wastewater is discharged in the future, it would require additional wastewater treatment. Efforts have been underway at Boswell for several years to reduce the amount of water discharged and evaluate potential re-use options in its plant processes. Additional efforts are underway to determine if land application of certain wastewater streams under a state disposal system may be feasible.

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

At this time, we cannot estimate what compliance costs we might incur related to these or other potential future water discharge regulations; however, the costs could be material, including costs associated with retrofits for bottom ash handling, pond dewatering, pond closure, and wastewater treatment and/or reuse. Minnesota Power would seek recovery of any additional costs through a rate proceeding.

Solid and Hazardous Waste. The Resource Conservation and Recovery Act of 1976 regulates the management and disposal of solid and hazardous wastes. We are required to notify the EPA of hazardous waste activity and, consequently, routinely submit the necessary reports to the EPA.

Coal Ash Management Facilities. Minnesota Power generates or disposes coal ash at four of its electric generating facilities. One facility stores ash in onsite impoundments (ash ponds) with engineered liners and containment dikes. Another facility’s ash is beneficially re-used. The other two facilities generate a combined wood and coal ash that is either land applied as an approved beneficial use or trucked to state permitted landfills. In 2010, the EPA proposed regulations for coal combustion residuals (CCR) generated by the electric utility sector. The proposal sought comments on three general regulatory schemes for coal ash under Subtitle D of Resource Conservation and Recovery Act (RCRA) (non-hazardous) or Subtitle C of RCRA (hazardous).

The EPA issued the final CCR rule in 2014 under Subtitle D (non-hazardous) of RCRA and it was published in the Federal Register in April 2015. The rule includes additional requirements for new landfill and impoundment construction as well as closure activities related to certain existing impoundments. Costs of compliance for Boswell and Laskin are expected to occur primarily over the next 10 years and be between approximately $65 million and $100 million. Recently, the EPA has indicated to Minnesota Power that the Taconite Harbor landfill is a CCR unit, based on EPA’s interpretation of the CCR Rule language. Minnesota Power has agreed to post the required CCR information for the Taconite Harbor landfill on Minnesota Power’s website while the CCR issue is resolved. Minnesota Power continues to work on minimizing costs through evaluation of beneficial re-use and recycling of CCR and CCR-related waters. Compliance costs, if any for CCR at Taconite Harbor are not expected to be material. Minnesota Power would seek recovery of any additional costs through a general rate case.

Other Environmental Matters. On November 28, 2016, U.S. Water Services received notice from the EPA regarding potential violations under the Federal Insecticide, Fungicide and Rodenticide Act for the sale of certain chemicals without registration or that were misbranded. The potential violations primarily relate to sales in 2013 by a U.S. Water Services subsidiary acquired in 2013. U.S. Water Services is cooperating with the EPA in its investigation of these potential violations. We are unable to predict the outcome of this matter at this time, but we do not expect that any potential fines will have a material effect on our financial position, results of operations or cash flows.

Other Matters

ALLETE Clean Energy. ALLETE Clean Energy’s wind energy facilities have PSAs in place for their entire output and expire in various years between 2018 and 2032. As of December 31, 2016, ALLETE Clean Energy has $14.6 million outstanding in standby letters of credit.

U.S. Water Services. As of December 31, 2016, U.S. Water Services has $0.8 million outstanding in standby letters of credit.

BNI Energy. As of December 31, 2016, BNI Energy had surety bonds outstanding of $49.9 million related to the reclamation liability for closing costs associated with its mine and mine facilities. Although its coal supply agreements obligate the customers to provide for the closing costs, additional assurance is required by federal and state regulations. In addition to the surety bonds, BNI Energy has secured a letter of credit for an additional $0.6 million to provide for BNI Energy’s total reclamation liability, which is currently estimated at $47.5 million. BNI Energy does not believe it is likely that any of these outstanding surety bonds or the letter of credit will be drawn upon.

ALLETE Properties. As of December 31, 2016, ALLETE Properties, through its subsidiaries, had surety bonds outstanding and letters of credit to governmental entities totaling $8.6 million primarily related to development and maintenance obligations for various projects. The estimated cost of the remaining development work is approximately $5.4 million. ALLETE Properties does not believe it is likely that any of these outstanding surety bonds or letters of credit will be drawn upon.

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Other Matters (Continued)

Community Development District Obligations. In 2005, the Town Center District issued $26.4 million of tax-exempt, 6.0 percent capital improvement revenue bonds, and in 2006, the Palm Coast Park District issued $31.8 million of tax-exempt, 5.7 percent special assessment bonds. The capital improvement revenue bonds and the special assessment bonds are payable over 31 years (by May 1, 2036 and 2037, respectively) and are secured by special assessments on the benefited land. The bond proceeds were used to pay for the construction of a portion of the major infrastructure improvements in each district and to mitigate traffic and environmental impacts. The assessments were billed to the landowners beginning in 2006 for the Town Center District and 2007 for the Palm Coast Park District. To the extent that we still own land at the time of the assessment, we will incur the cost of our portion of these assessments, based upon our ownership of benefited property. As of December 31, 2016, we owned 72 percent of the assessable land in the Town Center District (72 percent as of December 31, 2015) and 92 percent of the assessable land in the Palm Coast Park District (92 percent as of December 31, 2015). At these ownership levels, our annual assessments related to capital improvement and special assessment bonds for the ALLETE Properties projects within these districts are approximately $1.4 million for the Town Center District and $2.1 million for the Palm Coast Park District. As we sell property at these projects, the obligation to pay special assessments will pass to the new landowners. In accordance with accounting guidance, these bonds are not reflected as debt on the Consolidated Balance Sheet.

Legal Proceedings.

We are involved in litigation arising in the normal course of business. Also in the normal course of business, we are involved in tax, regulatory and other governmental audits, inspections, investigations and other proceedings that involve state and federal taxes, safety, and compliance with regulations, rate base and cost of service issues, among other things. We do not expect the outcome of these matters to have a material effect on our financial position, results of operations or cash flows.