XML 71 R23.htm IDEA: XBRL DOCUMENT
v2.4.1.9

Commitments, Guarantees and Contingencies | 3 Months Ended
--- | ---
Mar. 31, 2015
Commitments, Guarantees and Contingencies [Abstract] |
Commitments, Guarantees and Contingencies [Text Block] | COMMITMENTS, GUARANTEES AND CONTINGENCIES 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 2026 (Agreement). It provides a long-term supply of energy to customers in our electric service territory and enables Minnesota Power to meet reserve requirements. Square Butte, a North Dakota cooperative corporation, owns a 455 MW coal-fired generating unit (Unit) near Center, North Dakota. The Unit is adjacent to a generating unit owned by Minnkota Power, a North Dakota cooperative corporation whose Class A members are also members of Square Butte. Minnkota Power serves as the operator of the Unit and also purchases power from Square Butte. Minnesota Power is obligated to pay its pro rata share of Square Butte’s costs based on Minnesota Power’s entitlement to Unit output. Our output entitlement under the Agreement is 50 percent for the remainder of the Agreement, subject to the provisions of the Minnkota Power sales agreement described below. 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 March 31, 2015, Square Butte had total debt outstanding of $390.9 million. Annual debt service for Square Butte is expected to be approximately $45 million in each of the next five years, 2015 through 2019, of which Minnesota Power’s obligation is 50 percent. Fuel expenses are recoverable through our fuel adjustment clause and include the cost of coal purchased from BNI Coal, under a long-term contract. Minnesota Power’s cost of power purchased from Square Butte during the three months ended March 31, 2015, was $19.2 million ($16.8 million for the three months ended March 31, 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 $2.5 million during the three months ended March 31, 2015 ($2.5 million for the three months ended March 31, 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. Minnkota Power Sales Agreement. In December 2009, Minnesota Power entered into a power sales agreement with Minnkota Power, which commenced in June 2014. Under the power sales agreement, Minnesota Power is selling a portion of its output 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. In 2015, Minnesota Power’s portion of output sold to Minnkota Power is approximately 28 percent (23 percent commencing on June 1, 2014). Minnkota Power PPA. In December 2012, Minnesota Power entered into a long-term PPA with Minnkota Power. Under this agreement, Minnesota Power will purchase 50 MW of capacity and the energy associated with that capacity from June 2016 through May 2020. The agreement includes a fixed capacity charge and energy pricing that escalates at a fixed rate annually over the term. Oliver Wind I and II PPAs. Minnesota Power entered into two long-term wind PPAs with an affiliate of NextEra Energy, Inc. to purchase the output from Oliver Wind I (50 MW) and Oliver Wind II (48 MW)—wind facilities located near Center, North Dakota that expire in 2031 and 2032, respectively. Each agreement provides for the purchase of all output from the facilities at fixed energy prices. There are no fixed capacity charges, and we only pay for energy as it is delivered to us. Manitoba Hydro PPAs. Minnesota Power has a long-term PPA with Manitoba Hydro that expires in May 2020. Under this agreement, Minnesota Power is purchasing 50 MW of capacity and the energy associated with that capacity. Both the capacity price and the energy price are adjusted annually by the change in a governmental inflationary index. In addition, Minnesota Power has a separate long-term PPA with Manitoba Hydro to purchase surplus energy through April 2022. This energy-only agreement primarily consists of surplus hydro energy on Manitoba Hydro’s system that is delivered to Minnesota Power on a non-firm basis. The pricing is based on forward market prices. Under this agreement, Minnesota Power will purchase at least one million MWh of energy over the contract term. NOTE 16. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued) Power Purchase Agreements (Continued) In May 2011, Minnesota Power and Manitoba Hydro signed an additional long-term PPA. The PPA provides for Minnesota Power to purchase 250 MW of capacity and energy from Manitoba Hydro for 15 years beginning in 2020. The agreement is subject to construction of additional transmission capacity between Manitoba and the U.S., along with construction of new hydroelectric generating capacity in Manitoba. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in the third quarter of 2014. 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 price component adjusted for the change in a governmental inflationary index and a natural gas index, as well as market prices. In July 2014, Minnesota Power and Manitoba Hydro signed a long-term PPA that provides for Minnesota Power to purchase up to 133 MW of energy from Manitoba Hydro for 20 years beginning in 2020. The pricing under this PPA is based on forward market prices. The agreement was approved by the MPUC in an order dated January 30, 2015, and is subject to the construction of the GNTL. (See Great Northern Transmission Line.) Great River Energy PPAs. In August 2014 and January 2015, Minnesota Power and Great River Energy signed long-term PPAs that provide for Minnesota Power to purchase 50 MW of capacity and energy under the first PPA and 50 MW of capacity only under the second PPA. The PPAs commence in June 2016 and expire in May 2020. Both contracts have fixed capacity pricing. The energy price in the first PPA 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. Coal, Rail and Shipping Contracts. We have coal supply agreements providing for the purchase of a significant portion of our coal requirements with expiration dates through December 2015. Minnesota Power is currently in discussions regarding the extension of our coal supply contracts beyond 2015. We also have coal transportation agreements in place for the delivery of a significant portion of our coal requirements with expiration dates through December 2018. Our minimum annual payment obligation under these supply and transportation agreements is $42.3 million for the remainder of 2015, $27.0 million in 2016, $27.6 million in 2017, and $28.4 million in 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 Coal is obligated to make lease payments for a dragline totaling $2.8 million annually for the lease term, which expires in 2027. BNI Coal 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 2022. The aggregate amount of minimum lease payments for all operating leases is $13.4 million in 2015, $11.4 million in 2016, $10.6 million in 2017, $9.5 million in 2018, $8.3 million in 2019 and $27.3 million thereafter. 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 and the CapX2020 initiative, as well as investments to enhance our own transmission facilities, investments in other transmission assets (individually or in combination with others), and our investment in ATC. Transmission Investments. Minnesota Power has an approved cost recovery rider in place for certain transmission investments and expenditures. In an order dated February 23, 2015, 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. CapX2020. Minnesota Power is a participant in the CapX2020 initiative which represents an effort to ensure electric transmission and distribution reliability in Minnesota and the surrounding region for the future. CapX2020, which consists of electric cooperatives and municipal and investor-owned utilities, including Minnesota’s largest transmission owners, has assessed the transmission system and projected growth in customer demand for electricity through 2020. NOTE 16. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued) Transmission (Continued) On April 2, 2015, the CapX2020 transmission line project from Fargo, North Dakota to St. Cloud, Minnesota was completed and placed into service. Minnesota Power previously participated in two additional CapX2020 projects which were completed and placed into service in 2011 and 2012. Minnesota Power invested approximately $100 million to complete the three transmission line projects. As future CapX2020 projects are identified, Minnesota Power may elect to participate on a project-by-project basis. Great Northern Transmission Line (GNTL). As a condition of the long-term PPA signed in May 2011 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 October 2013, a Certificate of Need application was filed with the MPUC with respect to the GNTL. In a January 2014 order, the MPUC determined the Certificate of Need application was complete and referred the docket to an administrative law judge for a contested case proceeding. On March 16, 2015, the administrative law judge recommended the MPUC grant a Certificate of Need for construction of the GNTL. In April 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 a July 2014 order, the MPUC determined the route permit application to be complete. Manitoba Hydro must also obtain regulatory and governmental approvals related to a new transmission line in Canada. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in the third quarter of 2014. Upon receipt of all applicable permits and approvals, construction of the GNTL is anticipated to begin in 2016 and to be completed in 2020. Total project cost in the U.S., including substation work, is estimated to be between $560 million and $710 million, depending on the final route of the line. Minnesota Power is expected to have majority ownership of the transmission line. Environmental Matters. Our businesses are subject to regulation of environmental matters by various federal, state and local authorities. Currently, a number of regulatory changes to the Clean Air Act, the Clean Water Act and various waste management requirements are under consideration by both Congress and the EPA. Minnesota Power’s fossil fuel facilities will likely be subject to regulation under these proposals. Our intention is to reduce our exposure to these requirements by reshaping our generation portfolio over time to reduce our reliance on coal. 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. Due to expected future restrictive environmental requirements imposed through legislation and/or rulemaking, we anticipate that potential expenditures for environmental matters will be material and will require significant capital investments. Minnesota Power has evaluated various environmental compliance scenarios using possible ranges of future 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 charged to expense 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 applicable emission requirements. NOTE 16. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued) Environmental Matters (Continued) New Source Review (NSR). In August 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 Units 1, 2, 3 and 4 and Laskin Unit 2 between the years of 1981 to 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 (Court) in September 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 to an existing Boswell scrubber. Minnesota Power estimates that if the units are not retired, capital expenditures could range between $20 million and $40 million. We are evaluating our options with regard to Boswell Units 1 and 2 to comply with the Consent Decree and future anticipated environmental regulations. We are required to notify the EPA no later than December 31, 2016, whether we will retire, refuel, repower or reroute Boswell Units 1 and 2. We believe that future capital expenditures or costs to retire would likely be eligible for recovery in rates over time subject to regulatory approval in a rate proceeding. Cross-State Air Pollution Rule (CSAPR). In April 2014, the U.S. Supreme Court issued an opinion reversing an August 2012 U.S. Court of Appeals for the D.C. Circuit decision that had vacated the CSAPR. The EPA filed a motion with the U.S. Court of Appeals for the D.C. Circuit in June 2014, to have the stay of CSAPR lifted and the CSAPR compliance deadlines tolled by three years. In October 2014, the U.S. Court of Appeals for the D.C. Circuit granted the EPA's motion, allowing the first compliance period, Phase I, to begin on January 1, 2015, with Phase II beginning in 2017. CSAPR requires five states in the eastern half of the United States, including Minnesota, to significantly improve air quality by reducing power plant emissions that contribute to ozone or fine particulate pollution in other states. These states are required to make summertime NO x reductions under the CSAPR ozone season control program. 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 will be allocated to facilities from each state’s annual budget and can be bought and sold. In December 2014, the EPA distributed the CSAPR allowances to CSAPR-subject units for the Phase I years (2015 and 2016). Phase II allowances (2017-2020) have not been distributed. Based on our initial accounting of the NO x and SO 2 Phase I allowances already issued, and our review of the CSAPR Phase II allowances not yet issued, we currently expect projected generation levels and emission rates will be 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 February 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 must be in compliance with the rule by April 2015. States have the authority to grant sources a one-year extension. Minnesota Power was notified by the MPCA that it has approved Minnesota Power’s request for an additional year extending the date of compliance for the Boswell Unit 4 environmental upgrade to April 1, 2016. Compliance at Boswell Unit 4 to address the final MATS rule is expected to result in capital expenditures of approximately $260 million through 2016, of which $162 million was spent through March 31, 2015. Boswell Unit 3 is also subject to the MATS rule; however, the emission reduction investments completed in 2009 at our Boswell Unit 3 generating unit substantially meet the requirements of the MATS rule. Our “EnergyForward” plan, which was approved as part of our 2013 Integrated Resource Plan by the MPUC in a November 2013 order, also includes the conversion of Laskin Units 1 and 2 to natural gas in 2015 to position the Company for MATS compliance. In January 2014, the MPCA approved Minnesota Power’s application to extend the deadline for Taconite Harbor Unit 3 to comply with MATS to June 1, 2015, in order to align the Unit 3 retirement with MISO’s resource planning year. 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 must implement a mercury emissions reduction project for Boswell Unit 4 by December 31, 2018. The Boswell Unit 4 environmental upgrade discussed above, which is required to be completed by April 1, 2016 (see Mercury and Air Toxics Standards (MATS) Rule), will fulfill the requirements of the Minnesota Mercury Emissions Reduction Act. NOTE 16. 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 Maximum Achievable Control Technology (Industrial Boiler MACT) became effective in December 2012. Major existing sources have until January 31, 2016, to achieve compliance with the final rule. Minnesota Power’s Hibbard Renewable Energy Center and Rapids Energy Center are subject to this rule. We expect compliance to consist largely of adjustments to our operating practices; therefore costs for complying with the final rule are not expected to be material at this time. Proposed and Finalized 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 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 to more stringently control emissions that result in ground level ozone. In January 2010, the EPA proposed to revise the 2008 eight-hour ozone standard and to adopt a secondary standard for the protection of sensitive vegetation from ozone-related damage. In November 2014, the EPA proposed a 65 to 70 parts per billion (ppb) NAAQS for ground level ozone. The EPA is proposing to update both the primary ozone standard and the secondary standard. Both standards would be 8-hour standards set within a range of 65 to 70 ppb. The EPA is also seeking comment on levels for the primary standard as low as 60 ppb. The EPA has announced it will accept comments on all aspects of the proposal, including retaining the existing standard. A final rule is expected to be issued in the fourth quarter of 2015. The costs for complying with the final ozone NAAQS cannot be estimated at this time. Particulate Matter NAAQS. The EPA finalized the Particulate Matter NAAQS in September 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 December 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 also 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 December 2013, based on already available monitoring data. The EPA issued designations of 2012 fine particulate attainment status in December 2014. Minnesota retained attainment status; however, Minnesota sources may ultimately be required to reduce their emissions to assist with attainment in neighboring states. Accordingly, the costs for complying with the final Particulate Matter NAAQS cannot be estimated at this time. SO 2 and NO 2 NAAQS. During 2010, the EPA finalized one-hour NAAQS for SO 2 and NO 2. Ambient monitoring data indicates that Minnesota will likely be in compliance with these new standards; however, the one-hour SO 2 NAAQS also may require the EPA to evaluate modeling data to determine attainment. In April 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 new 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 June 2013. However, the State of Minnesota has delayed completing the documents pending EPA guidance to states for preparing the SIP submittal. The MPCA has indicated it will communicate with affected sources once it has more information on how the state will meet the EPA’s SIP requirements. Guidance was expected in 2013 but has been delayed. Currently, compliance with these new NAAQS is expected to be required as early as 2017. The costs for complying with the final standards cannot be estimated at this time. NOTE 16. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued) Environmental Matters (Continued) In July 2014, the Fond du Lac Band of Lake Superior Chippewa (Band) announced that it had petitioned 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 Band does not currently possess authority to directly regulate air quality. Federal Class I air shed status, if granted, would allow the 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 applied for and received Class I status. A public hearing was held by the Band in October 2014, and the public comment period on the petition expired in November 2014. After the Band prepares responses to the comments, the Band will make a formal submittal request to the EPA. There is no deadline for the approval, denial, or modification of the request by the EPA. The Company has requested additional clarification from the Band and the MPCA on the final regulatory structure that may arise from a Class I redesignation. 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 June 2013, President Obama announced a 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 May 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. 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 June 2014, the U.S. Supreme Court invalidated the aspect of the Tailoring Rule that established lower 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. In March 2012, the EPA announced a proposed rule to apply CO 2 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 September 2013, the EPA retracted its March 2012 proposal and announced the release of a revised NSPS for new or re-powered utility CO 2 emissions. NOTE 16. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued) Environmental Matters (Continued) In June 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” (CPP). The EPA is expected to finalize such rules by the summer of 2015. In the CPP, the EPA proposes to set state-specific goals for CO 2 emissions from the power sector. The EPA maintains such goals are achievable if a state undertakes a combination of measures across its power sector that constitute the EPA’s guideline for a Best System of Emission Reductions (BSER). The EPA proposed that BSER is comprised of four 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, 3) building more or preserving existing zero- and low-emitting power sources, including renewable and nuclear energy, and 4) more efficient electricity use by consumers. The EPA then established state goals, expressed as a carbon intensity target in CO 2 tons per megawatt hour, by estimating the achievability of the building blocks in each state. Using 2012 emissions data, the EPA derived interim goals for states to be met over the years 2020-2029, as well as a final goal to be met in 2030 and thereafter. Under the CPP, each state would be required to develop a state implementation plan by June 30, 2016. Minnesota Power is currently evaluating the CPP as it relates to the State of Minnesota and its potential impact on the Company. We submitted comments on the CPP to the EPA. 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 8. Regulatory Matters.) We are unable to predict the GHG emission compliance costs we might incur; however, the costs could be material. We would seek recovery of any additional costs through cost recovery riders or in a general rate case. Minnesota’s Next Generation Energy Act of 2007. In April 2014, a U.S. District Court for the District of Minnesota ruled that part of Minnesota’s Next Generation Energy Act of 2007 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 CO 2-producing facility outside of Minnesota and prohibited the entry into new long-term power purchase agreements that would increase CO 2 emissions in Minnesota. The State of Minnesota appealed the decision to the U.S. Court of Appeals for the Eighth Circuit in May 2014. 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 April 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 published in the Federal Register in August 2014, with an effective date in October 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 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; however, our preliminary assessment suggests costs of compliance could be up to approximately $15 million. We would seek recovery of any additional costs through a general rate case. NOTE 16. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued) Environmental Matters (Continued) Steam Electric Power Generating Effluent Guidelines. In April 2013, the EPA announced proposed revisions to the federal effluent guidelines for steam electric power generating stations under the Clean Water Act. The proposed revisions would set limits on the level of toxic materials in wastewater discharged from seven waste streams: flue gas desulfurization wastewater, fly ash transport water, bottom ash transport water, combustion residual leachate, non-chemical metal cleaning wastes, coal gasification wastewater, and wastewater from flue gas mercury control systems. As part of this proposed rulemaking, the EPA is considering imposing rules to address “legacy” wastewater currently residing in ponds as well as rules to impose stringent best management practices for discharges from active coal combustion residual surface impoundments. The EPA’s proposed rulemaking would base effluent limitations on what can be achieved by available technologies. The proposed rule was published in the Federal Register in June 2013, and public comments were due in September 2013. The EPA is expected to issue the final rule by September 30, 2015. Compliance with the final rule, as proposed, would be required no later than July 1, 2022. We are reviewing the proposed rule and evaluating its potential impacts on our operations. We are unable to predict the 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. We would seek recovery of any additional costs through cost recovery riders or in a general rate case. 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 coal ash at all five of its coal-fired electric generating facilities. Two facilities store ash in onsite impoundments (ash ponds) with engineered liners and containment dikes. Another facility stores dry ash in a landfill with an engineered liner and leachate collection system. 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 June 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 December 2014 under Subtitle D (non-hazardous) of RCRA with a final publication date of April 27, 2015. The rule includes additional requirements for new landfill and impoundment construction as well as closure activities related to certain existing impoundments. The final rule also includes provisions that could incentivize early closure of existing impoundments within a three-year window. Costs of compliance, primarily for Boswell and Laskin, could be up to approximately $130 million. The Company continues to work on minimizing costs on behalf of customers through evaluation of beneficial re-use and recycling of CCR and CCR-related waters. We would seek recovery of any additional costs through a general rate case. Other Matters. ALLETE Clean Energy. In January 2014, ALLETE Clean Energy acquired three wind energy facilities–Lake Benton, Storm Lake II and Condon. All three wind energy facilities have PPAs in place for their entire output, which expire in various years between 2019 and 2032. In December 2014, ALLETE Clean Energy acquired a wind facility, Storm Lake I, which has a PPA in place for its entire output which expires in 2018. On April 15, 2015, ALLETE Clean Energy acquired wind facilities in southern Minnesota with PPAs in place for the entire output, which expire in 2018 and 2023. (See Note 4. Acquisitions.) U.S. Water Services. As of March 31, 2015, U.S. Water Services has $3.2 million outstanding in stand-by letters of credit. BNI Coal. As of March 31, 2015, BNI Coal had surety bonds outstanding of $49.5 million related to the reclamation liability for closing costs associated with its mine and mine facilities. Although the 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 Coal has secured a letter of credit for an additional $0.6 million to provide for BNI Coal’s total reclamation liability, which is currently estimated at $49.3 million. BNI Coal does not believe it is likely that any of these outstanding surety bonds or the letter of credit will be drawn upon. NOTE 16. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued) Other Matters (Continued) ALLETE Properties. As of March 31, 2015, ALLETE Properties, through its subsidiaries, had surety bonds outstanding and letters of credit to governmental entities totaling $10.2 million primarily related to development and maintenance obligations for various projects. The estimated cost of the remaining development work is approximately $7.1 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 March 2005, the Town Center District issued $26.4 million of tax-exempt, 6 percent capital improvement revenue bonds and in May 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 November 2006 for Town Center and November 2007 for Palm Coast Park. 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. At March 31, 2015, we owned 72 percent of the assessable land in the Town Center District (72 percent at December 31, 2014) and 93 percent of the assessable land in the Palm Coast Park District (93 percent at December 31, 2014). At these ownership levels, our annual assessments are approximately $1.4 million for Town Center and $2.1 million for Palm Coast Park. As we sell property, 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.

X
- Details
Name: | ale_CommitmentsGuaranteesAndContingenciesAbstract
Namespace Prefix: | ale_
Data Type: | xbrli:stringItemType
Balance Type: | na
Period Type: | duration

X
- Definition The entire disclosure for commitments, contingencies, and guarantees. + References No definition available. + Details
Name: | us-gaap_CommitmentsContingenciesAndGuaranteesTextBlock
Namespace Prefix: | us-gaap_
Data Type: | nonnum:textBlockItemType
Balance Type: | na
Period Type: | duration