Commitments, Guarantees and Contingencies

12 Months Ended

Dec. 31, 2018

Commitments and Contingencies Disclosure [Abstract]

Commitments, Guarantees and Contingencies [Text Block]

COMMITMENTS, GUARANTEES AND CONTINGENCIES

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



As of December 31, 2018
Millions	2019		2020		2021		2022		2023		Thereafter
Coal, Rail and Shipping Contracts		$20.8		$9.0		$7.5	—		—		—
Operating Leases		$9.9		$7.9		$6.1		$4.9		$3.1		$9.4
Easements		$4.8		$4.9		$4.9		$5.0		$5.1		$136.3
Other (a)		$31.6		$0.3		$0.3	—		—			$0.1
PPAs (b)		$107.3		$115.3		$145.4		$145.7		$145.8		$1,550.7


(a)	Consists of long-term service agreements for wind energy facilities.


(b)	Does not include the agreement with Manitoba Hydro expiring in 2022, as this contract is for surplus energy only; Oliver Wind I and Oliver Wind II, as Minnesota Power only pays for energy as it is delivered; and the agreement with Nobles 2 commencing in 2020 as it is subject to construction of a wind energy facility. (See Power Purchase Agreements.)

Power Purchase and Sales 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 capacity and energy payments.

These agreements have also been evaluated under the accounting guidance for derivatives. We have determined that either these agreements are not derivatives, or if they are derivatives, the agreements qualify for the normal purchases and normal sales exemption to the accounting guidance; therefore, derivative accounting is not required.

Square Butte PPA. Minnesota Power has a PPA with Square Butte that extends through 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, 2018, Square Butte had total debt outstanding of $304.0 million. Annual debt service for Square Butte is expected to be approximately $48.7 million in each of the next five years, 2019 through 2023, 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 2018 was $78.0 million ($75.7 million in 2017; $73.3 million in 2016). 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 $9.1 million in 2018 ($9.4 million in 2017; $9.6 million in 2016). 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 and Sales Agreements (Continued)

Minnesota Power has also entered into the following PPAs for the purchase or sale of capacity and energy as of December 31, 2018:



Counterparty	Quantity	Product	Commencement	Expiration	Pricing
PPAs
Calpine Corporation	25 MW	Capacity	June 2019	May 2026	Fixed
Cypress Creek Renewables (a)	(a)	Capacity / Energy	(a)	(a)	Fixed
Great River Energy
PPA 1	50 MW	Capacity / Energy	June 2016	May 2020	(b)
PPA 2	50 MW	Capacity	June 2016	May 2020	Fixed
PPA 3	50 MW	Capacity	June 2017	May 2020	Fixed
Manitoba Hydro
PPA 1	(c)	Energy	May 2011	April 2022	Forward Market Prices
PPA 2	50 MW	Capacity / Energy	June 2015	May 2020	(d)
PPA 3	50 MW	Capacity	June 2017	May 2020	Fixed
PPA 4 (e)	250 MW	Capacity / Energy	June 2020	May 2035	(f)
PPA 5 (e)	133 MW	Energy	(g)	(g)	Forward Market Prices
Minnkota Power	50 MW	Capacity / Energy	June 2016	May 2020	(h)
Nobles 2 (i)	(i)	Capacity / Energy	(i)	(i)	Fixed
Oliver Wind I	(j)	Energy	December 2006	December 2040	Fixed
Oliver Wind II	(j)	Energy	December 2007	December 2040	Fixed
Shell Energy	50 MW	Energy	January 2017	December 2019	Fixed
TransAlta	(k)	Energy	January 2017	December 2019	Fixed


(a)	The PPA provides for the purchase of all output from the 10 MW Blanchard solar energy facility to be located in central Minnesota. Construction of the Blanchard solar energy facility is expected to be completed in 2020 and the contract is effective for 25 years beginning upon commercial operation.


(b)	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.


(c)	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.


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


(e)	Agreements are subject to the construction of the GNTL and MMTP. (See Great Northern Transmission Line.)


(f)	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.


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


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


(i)	The PPA provides for the purchase of all output from a 250 MW wind energy facility to be constructed in southwest Minnesota for 20 years beginning upon commercial operation of the wind energy facility which is currently expected in fourth quarter of 2020. (See Note 4. Regulatory Matters and Note 5. Equity Investments.)


(j)	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.


(k)	Minnesota Power is purchasing 50 MW of energy during off-peak hours and 100 MW of energy during on-peak hours.

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Power Purchase and Sales Agreements (Continued)

Minnesota Power has also entered into the following PSAs for the purchase or sale of capacity and energy as of December 31, 2018:



Counterparty	Quantity	Product	Commencement	Expiration	Pricing
PSAs
Basin
PSA 1	100 MW	Capacity / Energy	May 2010	April 2020	(a)
PSA 2	50 MW	Capacity	June 2017	May 2019	Fixed
PSA 3	(b)	Capacity	June 2022	May 2025	Fixed
PSA 4	100 MW	Capacity	June 2025	May 2028	Fixed
Minnkota Power	(c)	Capacity / Energy	June 2014	December 2026	(c)
Oconto Electric Cooperative	25 MW	Capacity / Energy	January 2019	May 2026	Fixed
Silver Bay Power	(d)	Energy	January 2017	December 2031	(e)


(a)	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.


(b)	The agreement provides for 75 MW of capacity from June 1, 2022, through May 31, 2023, and increases to 125 MW of capacity from June 1, 2023, through May 31, 2025.

(c)

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 2018 (28 percent in 2017 and in 2016). (See Square Butte PPA.)

(d)

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. Through 2019, Minnesota Power will supply Silver Bay Power with at least 50 MW of energy and Silver Bay Power has the option to purchase additional energy. By December 31, 2019, Silver Bay Power is expected to cease self-generation and Minnesota Power is expected to supply the energy requirements for Silver Bay Power.


(e)	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.

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 2019 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 2021. The costs of fuel and related transportation costs 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 a majority of terms expiring through 2024. Total lease expense was $14.6 million in 2018 ($17.5 million in 2017; $17.1 million in 2016).

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

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Transmission (Continued)

In a 2016 order, the MPUC approved the route permit for the GNTL, and in 2016, the U.S. Department of Energy issued a presidential permit to cross the U.S.‑Canadian border, which was the final major regulatory approval needed before construction in the U.S. could begin. Site clearing and pre‑construction activities commenced in the first quarter of 2017 with construction expected to be completed in 2020. To date, most of the right-of-way has been cleared while foundation installation and transmission tower construction have commenced. The total project cost in the U.S., including substation work, is estimated to be between $560 million and $710 million, of which Minnesota Power’s portion is expected to be between $300 million and $350 million; the difference will be recovered from a subsidiary of Manitoba Hydro as non-shareholder contributions to capital. Total project costs of $380.8 million have been incurred through December 31, 2018, of which $203.7 million has been recovered from a subsidiary of Manitoba Hydro.

Manitoba Hydro must obtain regulatory and governmental approvals related to the MMTP, a new transmission line in Canada that will connect with the GNTL. In 2015, Manitoba Hydro submitted the final preferred route and EIS for the MMTP to the Manitoba Conservation and Water Stewardship for siting and environmental approval, which remains pending. In 2016, Manitoba Hydro filed an application with the Canadian National Energy Board (NEB) requesting authorization to construct and operate the MMTP, which was recommended for approval on November 15, 2018. Approval of the Canadian federal cabinet is also required.

The MMTP is subject to legal and regulatory challenges which Minnesota Power is actively monitoring. Manitoba Hydro has informed Minnesota Power that it continues to work towards completing the MMTP on schedule. In order to meet the transmission in‑service requirements in PPAs with Minnesota Power, Manitoba Hydro has indicated that it would need to start construction of the MMTP by June 2019. We are unable to predict the outcome of the Canadian regulatory review process, including the timing thereof or whether any onerous conditions may be imposed, or the timing of the completion of the MMTP, including the impact of any delays that may result in construction schedule adjustments. Any significant delays in the MMTP construction schedule may result in Minnesota Power adjusting the GNTL construction schedule and impact the timing of capital expenditures and associated cost recovery under our transmission cost recovery rider.

Construction of Manitoba Hydro’s Keeyask hydroelectric generation facility, which will provide the power to be sold under PPAs with Minnesota Power and transmitted on the MMTP and the GNTL, commenced in 2014 and is anticipated to be in service by early 2021.

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 been promulgated by both the EPA and state authorities over the past several years. Minnesota Power’s facilities are subject to additional requirements under many of 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 have been obtained. We anticipate that with many state and federal environmental regulations and requirements finalized, or to be finalized in the near future, potential expenditures for future environmental matters may be material and 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 2014, Minnesota Power reached a settlement with the EPA and entered into a Consent Decree regarding certain Notices of Violation received in 2008 and 2011 that asserted violations of the NSR requirements of the Clean Air Act, which was approved by the U.S. District Court for the District of Minnesota. The Consent Decree provided for, among other requirements, more stringent emissions limits at all affected units, the option of refueling, retrofitting or retiring 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. Minnesota Power retired Boswell Units 1 and 2 in the fourth quarter of 2018. Minnesota Power is allowed to recover the remaining net book value for Boswell Units 1 and 2 through 2022. We believe that costs to retire Boswell Units 1 and 2 will be eligible for recovery in rates over time, subject to regulatory approval in a rate proceeding.

Mercury and Air Toxics Standards (MATS) 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 final MATS rule addressed such emissions from coal-fired utility units greater than 25 MW and established categories of HAPs, including mercury, trace metals other than mercury, and acid gases. The EPA established emission limits for these categories of HAPs and work practice standards for the remaining categories. Construction on the project to implement the Boswell Unit 4 mercury emissions reduction plan to position the unit for MATS compliance was completed in 2015. Investments and compliance work previously completed at Boswell Unit 3, including emission reduction investments completed in 2009, meet the requirements of the MATS rule. The conversion of Laskin Units 1 and 2 to operate on natural gas in 2015 positioned those units for MATS compliance. On December 27, 2018, the EPA issued a proposed revised Supplemental Cost Finding for MATS that determined it is not appropriate and necessary to regulate HAP emissions from power plants under section 112 of the Clean Air Act.

Minnesota Mercury Emissions Reduction Act/Rule. 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.

Cross-State Air Pollution Rule (CSAPR). The CSAPR requires certain 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 but does require 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. Based on our review of the NO_x and SO₂ allowances issued and pending issuance, we currently expect generation levels and emission rates will result in continued compliance with the CSAPR.

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. None of the compliance costs for proposed or current NAAQS revisions are expected to be material.

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 renewable power supply for both our operations and the operations of others;


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


•	Improving efficiency of our generating facilities;


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


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


•	Managing vegetation on right-of-way corridors to reduce potential wildfire or storm damage risks; and


•	Practicing sound forestry management in our service territories to create landscapes more resilient to disruption from climate-related changes, including planting and managing long-lived conifer species.

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

EPA Regulation of GHG 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 2015, together with a proposed federal implementation plan and a model rule for emissions trading. In 2016, the U.S. Supreme Court issued an order staying the effectiveness of the rule until after the appellate court process is complete. In 2016, the U.S. Court of Appeals for the District of Columbia Circuit heard oral arguments and is currently deliberating. If the CPP is upheld at the completion of the appellate process, all of the CPP regulatory deadlines are expected to be reset based on the length of time that the appeals process takes. The EPA is precluded from enforcing the CPP while the U.S. Supreme Court stay is in force.

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 filed a motion with the U.S. Court of Appeals for the District of Columbia Circuit to hold CPP-related litigation in suspension while the EPA is reviewing the rule. In October 2017, the EPA issued a notice of proposed rulemaking, proposing to repeal the CPP. In December 2017, an Advanced Notice of Proposed Rulemaking for a CPP replacement rule was published in the Federal Register.

On August 31, 2018, the EPA published the proposed Affordable Clean Energy Rule in the Federal Register, which is intended to replace the CPP with revised emission guidelines that inform the development, submittal, and implementation of State Implementation Plans (SIP) to reduce GHG emissions for existing steam generating units. If a state does not submit a SIP or submits a plan that is unacceptable to the EPA, the EPA would develop a Federal Implementation Plan (FIP). Minnesota Power generating facilities affected by this proposal include Boswell, Laskin, Taconite Harbor and Hibbard.

The proposed Affordable Clean Energy Rule seeks to reduce carbon intensity at existing steam generation units by prescribing Best System of Emission Reduction (BSER), primarily through Heat Rate Improvement (HRI) technologies. Under the proposal, states will have up to three years to develop a SIP, which is subject to EPA approval. While many of the HRIs proposed by the EPA in the proposed rule have already been installed in Minnesota Power’s largest coal-fired generating units, compliance specifics would be detailed in either Minnesota’s SIP or a FIP.

Minnesota has already initiated several measures consistent with those called for under the CPP and proposed Affordable Clean Energy Rule. 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 6. Regulatory Matters.) 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 additional costs through a rate proceeding.

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.

Steam Electric Power Generating Effluent Limitations Guidelines. In 2015, the EPA issued revised federal effluent limitation guidelines (ELG) for steam electric power generating stations under the Clean Water Act. It set effluent limits and prescribed BACT for several wastewater streams, including flue gas desulphurization (FGD) water, bottom ash transport water and coal combustion landfill leachate. In September 2017, the EPA announced a two-year postponement of the ELG compliance date of November 1, 2018, to November 1, 2020, while the agency reconsiders the bottom ash transport water and FGD wastewater provisions.

The final ELG rule’s potential impact on Minnesota Power operations is 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 discharge to surface waters, but may do so in the future. Under the existing ELG rule, bottom ash transport water discharge to surface waters must cease no later than December 31, 2023. Bottom ash contact water will either need to be re-used in a closed-loop process, routed to a FGD scrubber, or the bottom ash handling system will need to be converted to a dry process. If FGD wastewater is discharged in the future, it will require additional wastewater treatment. The ELG rule provision regarding these two waste-streams are being reconsidered and may change prior to November 1, 2020. Efforts have been underway at Boswell to reduce the amount of water discharged and evaluate potential re‑use options in its plant processes.

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 re-use. Minnesota Power would seek recovery of 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 reports to the EPA.

Coal Ash Management Facilities. Minnesota Power stores or disposes coal ash at four of its electric generating facilities by the following methods: storing ash in lined onsite impoundments (ash ponds), disposing of dry ash in a lined dry ash landfill, applying ash to land as an approved beneficial use and trucking ash to state permitted landfills.

Coal Combustion Residuals from Electric Utilities (CCR). In 2015, the EPA published the final rule regulating CCR as nonhazardous waste under Subtitle D of the Resource Conservation and Recovery Act (RCRA) in the Federal Register. 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 15 years and be between approximately $65 million and $120 million. The EPA has indicated to Minnesota Power that the landfill at Taconite Harbor, which has been idled and has a temporary landfill cover in place, is a CCR unit based on the 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. Compliance costs for CCR at Taconite Harbor are not expected to be material. Minnesota Power would seek recovery of additional costs through a rate proceeding.

Minnesota Power continues to work on minimizing costs through evaluation of beneficial re-use and recycling of CCR and CCR‑related waters. In September 2017, the EPA announced its intention to formally reconsider the CCR rule under Subtitle D of the RCRA and on March 15, 2018, published the first phase of the proposed rule revisions in the Federal Register. On July 17, 2018, the EPA finalized revisions to elements of the CCR rule, including extending certain deadlines by two years, the establishment of alternative groundwater protection standards for certain constituents and the potential for risk‑based management options at facilities based on site characteristics. On August 22, 2018, a U.S. District Court for the District of Columbia decision vacated specific provisions of the CCR rule. The court decision changes the status of three existing impoundments at Boswell that must now be considered unlined. Compliance costs at Boswell due to the court decision are unknown at this time. Minnesota Power would seek recovery of additional costs through a rate proceeding.

Other Environmental Matters

Manufactured Gas Plant Site. We are reviewing and addressing environmental conditions at a former manufactured gas plant site located in Superior, Wisconsin, and formerly operated by SWL&P. SWL&P has been working with the Wisconsin Department of Natural Resources (WDNR) in determining the extent and location of contamination at the site and surrounding properties. In December 2017, the WDNR authorized SWL&P to transition from site investigation into the remedial design process. As of December 31, 2018, we have recorded a liability of approximately $7 million for remediation costs at this site (approximately $8 million as of December 31, 2017), and an associated regulatory asset as we expect recovery of these remediation costs to be allowed by the PSCW. We expect to incur these costs over the next four years.

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 2019 and 2032. As of December 31, 2018, ALLETE Clean Energy has $21.0 million outstanding in standby letters of credit.

U.S. Water Services. As of December 31, 2018, U.S. Water Services has no outstanding standby letters of credit.

BNI Energy. As of December 31, 2018, BNI Energy had surety bonds outstanding of $49.9 million and a letter of credit for an additional $0.6 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. BNI Energy’s total reclamation liability 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.

NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Other Matters (Continued)

ALLETE Properties. As of December 31, 2018, ALLETE Properties 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 $6.1 million. ALLETE Properties does not believe it is likely that any of these outstanding surety bonds or letters of credit will be drawn upon.

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 ALLETE Properties still owns land at the time of the assessment, it will incur the cost of its portion of these assessments, based upon its ownership of benefited property.

As of December 31, 2018, we owned 68 percent of the assessable land in the Town Center District (70 percent as of December 31, 2017) and 19 percent of the assessable land in the Palm Coast Park District (33 percent as of December 31, 2017). As of December 31, 2018, ownership levels, our annual assessments related to capital improvement and special assessment bonds for the ALLETE Properties projects within these districts are $1.4 million for Town Center at Palm Coast and $0.6 million for Palm Coast Park. 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 our 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.

U.S. Water Services is involved in on-going patent defense litigation it brought against a company for infringement of two patents held by U.S. Water Services. As of December 31, 2018, U.S. Water Services has recognized approximately $2.6 million of patent defense costs as an intangible asset. Management expects that U.S. Water Services will prevail, but in the event of an unfavorable outcome, the patent defense costs would be recognized as an expense in the period of resolution.