Commitments, Guarantees and Contingencies

12 Months Ended

Dec. 31, 2020

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, 2020
Millions	2021	2022	2023	2024	2025	Thereafter
Capital Purchase Obligations	$235.0	—	—	—	—	—
Easements (a)	$5.8	$6.0	$6.1	$6.1	$6.2	$175.9
PPAs (b)	$130.8	$143.7	$143.8	$136.7	$134.6	$1,215.6
Other Purchase Obligations (c)	$40.1	—	—	—	—	—

(a)Easement obligations represent the minimum payments for our land easement agreements at our wind energy facilities.

(b)Does not include the agreement with Manitoba Hydro expiring in 2022, as this contract is for surplus energy only; or the Oliver Wind I, Oliver Wind II or Nobles 2 PPAs, as Minnesota Power only pays for energy as it is delivered. (See Power Purchase Agreements.)

(c)Consists of long-term service agreements for wind energy facilities and minimum purchase commitments under coal and rail contracts.

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, 2020, Square Butte had total debt outstanding of $268.6 million. Annual debt service for Square Butte is expected to be approximately $45.5 million annually through 2023, $30.5 million in 2024 and $26.6 million in 2025, 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.

NOTE 8. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Power Purchase and Sales Agreements (Continued)

Minnesota Power’s cost of power purchased from Square Butte during 2020 was $79.5 million ($82.7 million in 2019; $78.0 million in 2018). 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 $7.1 million in 2020 ($8.3 million in 2019; $9.1 million in 2018). Minnesota Power’s payments to Square Butte are approved as a purchased power expense for ratemaking purposes by both the MPUC and the FERC.

Minnesota Power has also entered into the following long-term PPAs for the purchase of capacity and energy as of December 31, 2020:

Counterparty	Quantity	Product	Commencement	Expiration	Pricing
PPAs
Calpine Corporation	25 MW	Capacity	June 2019	May 2026	Fixed
Manitoba Hydro
PPA 1	(a)	Energy	May 2011	April 2022	Forward Market Prices
PPA 2	250 MW	Capacity / Energy	June 2020	May 2035	(b)
PPA 3	133 MW	Energy	June 2020	June 2040	Forward Market Prices
Nobles 2	250 MW	Capacity / Energy	December 2020	December 2040	Fixed
Oliver Wind I	(c)	Energy	December 2006	December 2040	Fixed
Oliver Wind II	(c)	Energy	December 2007	December 2040	Fixed

(a)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.

(b)The capacity price was 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.

(c)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.

Minnesota Power has also entered into the following long-term PSAs for the sale of capacity and energy as of December 31, 2020:

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

(a)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.

(b)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 2020 (28 percent in 2019 and in 2018). (See Square Butte PPA.)

(c)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. Minnesota Power supplied Silver Bay Power with at least 50 MW of energy and Silver Bay Power had the option to purchase additional energy from Minnesota Power as it transitioned away from self-generation. In the third quarter of 2019, Silver Bay Power ceased self-generation and Minnesota Power began supplying the full energy requirements for Silver Bay Power.

(d)The energy pricing escalates at a fixed rate annually and is 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 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.

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 was required. As a result, Minnesota Power constructed 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. On June 1, 2020, Minnesota Power placed the GNTL into service with project costs of approximately $310 million incurred by Minnesota Power. Total project costs, including those costs contributed by a subsidiary of Manitoba Hydro, totaled approximately $660 million. Also on June 1, 2020, Manitoba Hydro placed the MMTP into service. The 250 MW PPA with Manitoba Hydro commenced when the GNTL was placed into service.

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 thermal 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 NOX technologies. Under currently applicable environmental regulations, these facilities are substantially compliant with emission requirements.

NOTE 8. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

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 NOx and SO2 allowances issued and pending issuance, we currently expect generation levels and emission rates will result in continued compliance with the CSAPR. The ongoing CSAPR “good neighbor” provision and interstate transport litigation is also not currently projected to affect Minnesota Power’s CSAPR compliance. The State of Minnesota has not been identified by the downwind litigant states as a culpable upwind source, and previous EPA air quality modeling has demonstrated that Minnesota is not a significant contributor to downwind air quality attainment challenges. Minnesota Power also does not currently anticipate being affected by the EPA’s recent and expected upcoming rulemakings to address the remand of certain CSAPR aspects. Minnesota Power will continue to monitor ongoing CSAPR litigation and associated rulemakings.

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. Minnesota Power actively monitors NAAQS developments and compliance costs for existing standards or proposed NAAQS revisions are not expected to be material. Minnesota is not among the states expected to be impacted by the EPA’s October 20, 2020 proposed rule to revise the 2016 CSAPR Update for the 2008 ozone NAAQS in response to the D.C. Circuit remand of the CSAPR Update Rule.

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 or other changes in 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.

EPA Regulation of GHG Emissions. In June 2019, the EPA finalized several separate rulemakings regarding regulating carbon emissions from electric utility generating units. These rulemakings included repealing the Clean Power Plan (CPP) and adopting the Affordable Clean Energy Rule under Section 111(d) of the Clean Air Act (CAA) to regulate CO2 emissions at existing coal-fired power plants. The CPP was first announced as a proposed rule under Section 111(d) of the CAA for existing power plants entitled “Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Generating Units”. The Affordable Clean Energy Rule established emissions guidelines for states to use when developing plans to limit CO2 coal-fired power plants. The EPA also published regulations for the state implementation of the Affordable Clean Energy Rule and other Section 111(d) rules. Affected facilities for Minnesota Power included Boswell Units 3 and 4, and Taconite Harbor Units 1 and 2, which are currently economically idled.

On January 19, 2021, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued an opinion vacating the Affordable Clean Energy Rule and remanded the Affordable Clean Energy Rule back to the EPA for further consideration, consistent with the D.C. Circuit’s finding that the EPA erred in interpreting the CAA, pending rehearing or appeal.

NOTE 8. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

Minnesota had already initiated several measures consistent with those called for under the now repealed CPP and vacated Affordable Clean Energy Rule. Minnesota Power continues 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. We are unable to predict the GHG emission compliance costs we might incur as a result of a replacement for the Affordable Clean Energy Rule or other future laws, regulations or administrative policies; however, the costs could be material. Minnesota Power would seek recovery of additional costs through a rate proceeding.

Additionally on January 13, 2021, the EPA issued a rulemaking to apply CO2 emission New Source Performance Standards (NSPS) to new, modified and reconstructed fossil fuel-fired electric generating units under Section 111(b) of the CAA. Minnesota Power is monitoring the NSPS final rule and any further Section 111(b) developments including their potential impact to the Company. The Company’s proposed combined-cycle natural gas-fired generating facility, NTEC, is expected to meet these NSPS requirements.

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 2017, the EPA announced a two-year postponement of the ELG compliance date of November 1, 2018, to November 1, 2020, while the agency reconsidered the bottom ash transport water and FGD wastewater provisions. On April 12, 2019, the U.S. Court of Appeals for the Fifth Circuit vacated and remanded back to the EPA portions of the ELG that allowed for continued discharge of legacy wastewater and leachate. On October 13, 2020, the EPA published a final ELG Rule allowing re-use of bottom ash transport water in FGD scrubber systems with limited discharges related to maintaining system water balance. The rule sets technology standards and numerical pollutant limits for discharges of bottom ash transport water and FGD wastewater. Compliance deadlines depend on subcategory, with compliance generally required as soon as possible, beginning after October 13, 2021, but no later than December 31, 2023, or December 31, 2028 in some specific cases. The rule also establishes new subcategories for retiring high-flow and low-utilization units, and establishes a voluntary incentives program for FGD wastewater.

The ELG'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 if additional water treatment measures are implemented. With Boswell’s planned conversion to dry FGD handling and storage, ongoing FGD water generation will be reduced, and the majority of FGD waters will be legacy waters to be dewatered from existing impoundments. Re-use and onsite consumption for the majority of FGD waters is planned at Boswell.

Under the new ELG rule, most bottom ash transport water discharge to surface waters must cease no later than December 31, 2025, except for small discharges needed to retain water balance. The majority of bottom ash transport water will either need to be re-used in a closed-loop process or routed to a FGD scrubber. At Boswell, the bottom ash handling systems are planned to be converted to a dry process, which will eliminate bottom ash transport water.

The EPA’s additional reconsideration of legacy wastewater discharge requirements have the potential to reduce timelines for dewatering Boswell’s existing bottom ash pond. The timing of a draft rule addressing legacy wastewater and leachate is currently unknown.

NOTE 8. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Environmental Matters (Continued)

At this time, we estimate that the planned dry conversion of bottom ash handling and storage at Boswell in response to the CCR revisions requiring closure of clay-lined impoundments, as well as other water re-use practices, will reduce or eliminate the need for additional significant compliance costs for ELG bottom ash water and FGD requirements. Compliance costs we might incur related to other ELG waste streams (e.g. legacy leachate) or other potential future water discharge regulations cannot be estimated; however, the costs could be material, including costs associated with 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 produces the majority of its coal ash at Boswell, with small amounts of ash generated at Hibbard Renewable Energy Center. Ash storage and disposal methods include storing ash in clay-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. 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 2017, the EPA announced its intention to formally reconsider the CCR rule under Subtitle D of the RCRA. In March 2018, the EPA published the first phase of the proposed rule revisions in the Federal Register. In July 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. In August 2018, a U.S. District Court for the District of Columbia decision vacated specific provisions of the CCR rule. The court decision resulted in a change to the status of three existing clay-lined impoundments at Boswell that must now be considered unlined. The EPA proposed additional rule revisions in August and December 2019 to address outstanding issues from litigation and closure timelines for unlined impoundments, respectively. The first of these rules, CCR Rule Part A, was finalized on September 28, 2020. The Part A Rule revision requires unlined impoundments to cease disposal of waste as soon as technically feasible but no later than April 11, 2021. Minnesota Power intends to seek EPA approval to extend the closure date for the two active Boswell impoundments. Additionally, the EPA released a proposed Part B rulemaking in February 2020 that addressed options for beneficial reuse of CCR materials, alternative liner demonstrations, and other CCR regulatory revisions. Portions of the Part B Rule addressing alternative liner equivalency standards were finalized on November 12, 2020. According to the EPA’s current regulatory agenda, the remainder of the proposed Part B Rule is expected to be finalized in mid-2021. Expected compliance costs at Boswell due to the court decision and subsequent rule revisions are reflected in our estimate of compliance costs for the CCR rule noted previously. 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 January 2021, SWL&P submitted a final remedial actions options report to the WDNR with remedial site design expected to be completed in 2021. As of December 31, 2020, we have recorded a liability of approximately $7 million for remediation costs at this site (approximately $7 million as of December 31, 2019); however, SWL&P continues to work with the WDNR on the extent of contamination which may result in additional remediation costs being identified. SWL&P has also recorded an associated regulatory asset as we expect recovery of these remediation costs to be allowed by the PSCW. Remediation costs are expected to be incurred through 2023.

Commitments Contingencies and Guarantees

NOTE 8. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Other Matters

We have multiple credit facility agreements in place that provide the ability to issue standby letters of credit to satisfy our contractual security requirements across our businesses. As of December 31, 2020, we had $117.2 million of outstanding letters of credit issued, including those issued under our revolving credit facility.

Regulated Operations. As of December 31, 2020, we had $28.8 million outstanding in standby letters of credit at our Regulated Operations which are pledged as security for MISO and state agency agreements as well as energy facilities under development.

ALLETE Clean Energy. ALLETE Clean Energy’s wind energy facilities have PSAs in place for their output and expire in various years between 2022 and 2039. As of December 31, 2020, ALLETE Clean Energy has $74.4 million outstanding in standby letters of credit, the majority of which are pledged as security under these PSAs and PSAs for wind energy facilities under development.

Corporate and Other.

Investment in Nobles 2. Nobles 2 wind energy facility requires standby letters of credit as security for certain contractual obligations. As of December 31, 2020, ALLETE South Wind has $14.0 million outstanding in standby letters of credit, related to our portion of the security requirements relative to our ownership in Nobles 2.

BNI Energy. As of December 31, 2020, BNI Energy had surety bonds outstanding of $67.7 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 $67.3 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, 2020, ALLETE Properties had surety bonds outstanding and letters of credit to governmental entities totaling $2.0 million primarily related to development and maintenance obligations for various projects. The estimated cost of the remaining development work is $1.0 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. The capital improvement revenue bonds are payable over 31 years (by May 1, 2036) and are secured by special assessments on the benefited land. 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, 2020, we owned 48 percent of the assessable land in the Town Center District (53 percent as of December 31, 2019). As of December 31, 2020, ownership levels, our annual assessments related to capital improvement and special assessment bonds for the ALLETE Properties project within the district is approximately $1.8 million. As we sell property at this project, 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.