EDGAR 10-K Filing

Company CIK: 1123852
Filing Year: 2023
Filename: 1123852_10-K_2023_0001123852-23-000004.json

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ITEM 1. BUSINESS
Item 1 - Business

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ITEM 1A. RISK FACTORS
ITEM 1A - RISK FACTORS
Xcel Energy, which includes NSP-Minnesota, is subject to a variety of risks, many of which are beyond our control. Risks that may adversely affect the business, financial condition, results of operations or cash flows are described below. Although the risks are organized by heading, and each risk is described separately, many of the risks are interrelated. These risks should be carefully considered together with the other information set forth in this report and future reports that Xcel Energy files with the SEC. You should not interpret the disclosure of any risk factor to imply that the risk has not already materialized. While we believe we have identified and discussed below the key risk factors affecting our business, there may be additional risks and uncertainties that are not presently known or that are not currently believed to be significant that may adversely affect our business, financial condition, results of operations or cash flows in the future.
Oversight of Risk and Related Processes
NSP-Minnesota’s Board of Directors is responsible for the oversight of material risk and maintaining an effective risk monitoring process. Management and the Board of Directors have responsibility for overseeing the identification and mitigation of key risks.
NSP-Minnesota maintains a robust compliance program and promotes a culture of compliance beginning with the tone at the top. The risk mitigation process includes adherence to our Code of Conduct and compliance policies, operation of formal risk management structures and overall business management. NSP-Minnesota further mitigates inherent risks through formal risk committees and corporate functions such as internal audit, and internal controls over financial reporting and legal.
Management identifies and analyzes risks to determine materiality and other attributes such as timing, probability and controllability. Identification and risk analysis occurs formally through risk assessment conducted by senior management, the financial disclosure process, hazard risk procedures, internal audit and compliance with financial and operational controls. Management also identifies and analyzes risk through the business planning process, development of goals and establishment of key performance indicators, including identification of barriers to implementing our strategy. The business planning process also identifies likelihood and mitigating factors to prevent the assumption of inappropriate risk to meet goals.
Management communicates regularly with the Board of Directors and its sole stockholder regarding risk. Senior management presents and communicates a periodic risk assessment to the Board of Directors, providing information on the risks that management believes are material, including financial impact, timing, likelihood and mitigating factors. The Board of Directors regularly reviews management’s key risk assessments, which includes areas of existing and future macroeconomic, financial, operational, policy, environmental, safety and security risks.
The oversight, management and mitigation of risk is an integral and continuous part of the Board of Directors’ governance of NSP-Minnesota. Processes are in place to confirm appropriate risk oversight, as well as identification and consideration of new risks.
Risks Associated with Our Business
Operational Risks
Our natural gas and electric generation/transmission and distribution operations involve numerous risks that may result in accidents and other operating risks and costs.
Our natural gas transmission and distribution activities include inherent hazards and operating risks, such as leaks, explosions, outages and mechanical problems. Our electric generation, transmission and distribution activities include inherent hazards and operating risks such as contact, fire and outages. These risks could result in loss of life, significant property damage, environmental pollution, impairment of our operations and substantial financial losses to employees, third-party contractors, customers or the public. We maintain insurance against most, but not all, of these risks and losses. The occurrence of these events, if not fully covered by insurance, could have a material effect on our financial condition, results of operations and cash flows as well as potential loss of reputation.
Other uncertainties and risks inherent in operating and maintaining NSP-Minnesota's facilities include, but are not limited to:
•Risks associated with facility start-up operations, such as whether the facility will achieve projected operating performance on schedule and otherwise as planned.
•Failures in the availability, acquisition or transportation of fuel or other supplies.
•Impact of adverse weather conditions and natural disasters, including, tornadoes, icing events, floods and droughts.
•Performance below expected or contracted levels of output or efficiency.
•Availability of replacement equipment.
•Availability of adequate water resources and ability to satisfy water intake and discharge requirements.
•Availability or changes to wind patterns.
•Inability to identify, manage properly or mitigate equipment defects.
•Use of new or unproven technology.
•Risks associated with dependence on a specific type of fuel or fuel source, such as commodity price risk, availability of adequate fuel supply and transportation and lack of available alternative fuel sources.
•Increased competition due to, among other factors, new facilities, excess supply, shifting demand and regulatory changes.
Additionally, compliance with existing and potential new regulations related to the operation and maintenance of our natural gas infrastructure could result in significant costs. The PHMSA is responsible for administering the DOT’s national regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipelines. The PHMSA continues to develop regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance and emergency response of natural gas pipeline infrastructure. We have programs in place to comply with these regulations and systematically monitor and renew infrastructure over time, however, a significant incident or material finding of non-compliance could result in penalties and higher costs of operations.
Our natural gas and electric transmission and distribution operations are dependent upon complex information technology systems and network infrastructure, the failure of which could disrupt our normal business operations, which could have a material adverse effect on our ability to process transactions and provide services.
Our utility operations are subject to long-term planning and project risks.
Most electric utility investments are planned to be used for decades. Transmission and generation investments typically have long lead times and are planned well in advance of in-service dates and typically subject to long-term resource plans. These plans are based on numerous assumptions such as: sales growth, customer usage, commodity prices, economic activity, costs, regulatory mechanisms, customer behavior, available technology and public policy. Our long-term resource plan is dependent on our ability to obtain required approvals, develop necessary technical expertise, allocate and coordinate sufficient resources and adhere to budgets and timelines.
In addition, the long-term nature of both our planning processes and our asset lives are subject to risk. The electric utility sector is undergoing significant change (e.g., increases in energy efficiency, wider adoption of distributed generation and shifts away from fossil fuel generation to renewable generation). Customer adoption of these technologies and increased energy efficiency could result in excess transmission and generation resources, downward pressure on sales growth, and potentially stranded costs if we are not able to fully recover costs and investments.
The magnitude and timing of resource additions and changes in customer demand may not coincide with evolving customer preference for generation resources and end-uses, which introduces further uncertainty into long-term planning. Efforts to electrify the transportation and building sectors to reduce GHG emissions may result in higher electric demand and lower natural gas demand over time. Higher electric demand may require us to adopt new technologies and make significant transmission and distribution investments including advanced grid infrastructure, which increases exposure to overall grid instability and technology obsolescence. Evolving stakeholder preference for lower emissions from generation sources and end-uses, like heating, may impact our resource mix and put pressure on our ability to recover capital investments in natural gas generation and delivery. Multiple states may not agree as to the appropriate resource mix, which may lead to costs to comply with one jurisdiction that are not recoverable across all jurisdictions served by the same assets.
We require inputs such as coal, natural gas, uranium and water to cool our facilities. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate.
Our utility operations are highly dependent on suppliers to deliver components in accordance with short and long-term project schedules.
Our products contain components that are globally sourced from suppliers who, in turn, source components from their suppliers. A shortage of key components in which an alternative supplier is not identified could significantly impact operations and project plans for NSP-Minnesota and our customers. Such impacts could include timing of projects, including potential for project cancellation. Failure to adhere to project budgets and timelines adversely impacts our results of operations, financial condition or cash flows.
We are subject to commodity risks and other risks associated with energy markets and energy production.
A significant increase in fuel costs could cause a decline in customer demand, adverse regulatory outcomes and an increase in bad debt expense which may have a material impact on our results of operations. Despite existing fuel cost recovery mechanisms, higher fuel costs could significantly impact our results of operations if costs are not recovered. Delays in the timing of the collection of fuel cost recoveries could impact our cash flows and liquidity.
A significant disruption in supply could cause us to seek alternative supply services at potentially higher costs. Additionally, supply shortages may not be fully resolved, which negatively impacts our ability to provide services to our customers. Failure to provide service due to disruptions may also result in fines, penalties or cost disallowances through the regulatory process. Also, significantly higher energy or fuel costs relative to sales commitments negatively impacts our cash flows and results of operations.
We also engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. In many markets, emission allowances and/or RECs are also needed to comply with various statutes and commission rulings. As a result, we are subject to market supply and commodity price risk.
Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis. Settlements can vary significantly from estimated fair values recorded and significant changes from the assumptions underlying our fair value estimates could cause earnings variability. The management of risks associated with hedging and trading is based, in part, on programs and procedures which utilize historical prices and trends.
Public perception often does not distinguish between pass through commodity costs and base rates. High commodity prices that are being passed through to customer bills could impact our ability to recover costs for other improvements and operations.
Due to the uncertainty involved in price movements and potential deviation from historical pricing, NSP-Minnesota is unable to fully assure that its risk management programs and procedures would be effective to protect against all significant adverse market deviations. In addition, NSP-Minnesota cannot fully assure that its controls will be effective against all potential risks. If such programs and procedures are not effective, NSP-Minnesota’s results of operations, financial condition or cash flows could be materially impacted.
Failure to attract and retain a qualified workforce could have an adverse effect on operations.
The competition for talent has become increasingly prevalent, and we have experienced increased employee turnover due to the condition of the labor market. In addition, specialized knowledge and skills are required for many of our positions, which may pose additional difficulty for us as we work to recruit, retain and motivate employees in this climate. Failure to hire and adequately train replacement employees, including the transfer of significant knowledge and expertise to new employees or future availability and cost of contract labor may adversely affect the ability to manage and operate our business. Inability to attract and retain these employees adversely impacts our results of operations, financial condition or cash flows.
Our operations use third-party contractors in addition to employees to perform periodic and ongoing work.
We rely on third-party contractors to perform operations, maintenance and construction work. Our contractual arrangements with these contractors typically include performance and safety standards, progress payments, insurance requirements and security for performance. Poor vendor performance or contractor unavailability could impact ongoing operations, restoration operations, regulatory recovery, our reputation and could introduce financial risk or risks of fines.
Our employees, directors, third-party contractors, or suppliers may violate or be perceived to violate our Codes of Conduct, which could have an adverse effect on our reputation.
We are exposed to risk of employee or third-party contractor fraud or misconduct. All employees and members of the Board of Directors are subject to comply with our Code of Conduct and are required to participate in annual training. Additionally, suppliers are subject to comply with our Supplier Code of Conduct. NSP-Minnesota does not tolerate discrimination, violations of our Code of Conduct or other unacceptable behaviors. However, it is not always possible to identify and deter misconduct by employees and other third-parties, which may result in governmental investigations, other actions or lawsuits. If such actions are taken against us we may suffer loss of reputation and such actions could have a material effect on our financial condition, results of operations and cash flows.
We are subject to the risks of nuclear generation.
NSP-Minnesota has two nuclear generation plants, PI and Monticello. Risks of nuclear generation include:
•Hazards associated with the use of radioactive material in energy production, including management, handling, storage and disposal.
•Limitations on insurance available to cover losses that may arise in connection with nuclear operations, as well as obligations to contribute to an insurance pool in the event of damages at a covered U.S. reactor.
•Technological and financial uncertainties related to the costs of decommissioning nuclear plants may cause our funding obligations to change.
The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities, including the ability to impose fines and/or shut down a unit until compliance is achieved. NRC safety requirements could necessitate substantial capital expenditures or an increase in operating expenses. In addition, the INPO reviews our nuclear operations. Compliance with the INPO’s recommendations could result in substantial capital expenditures or a substantial increase in operating expenses.
If a nuclear incident did occur, it could have a material impact on our results of operations, financial condition or cash flows. Furthermore, non-compliance or the occurrence of a serious incident at other nuclear facilities could result in increased industry regulation, which may increase our compliance costs.
We are a wholly owned subsidiary of Xcel Energy Inc. Xcel Energy Inc. can exercise substantial control over our dividend policy and business and operations and may exercise that control in a manner that may be perceived to be adverse to our interests.
All of the members of our Board of Directors, as well as many of our executive officers, are officers of Xcel Energy Inc. Our Board of Directors makes determinations with respect to a number of significant corporate events, including the payment of our dividends.
We have historically paid quarterly dividends to Xcel Energy Inc. If Xcel Energy Inc.’s cash requirements increase, our Board of Directors could decide to increase the dividends we pay to Xcel Energy Inc. to help support Xcel Energy Inc.’s cash needs. This could adversely affect our liquidity. The most restrictive dividend limitation for NSP-Minnesota is imposed by our state regulatory commissions. State regulatory commissions indirectly limit the amount of dividends NSP-Minnesota can pay to Xcel Energy Inc., by requiring a minimum equity-to-total capitalization ratio.
See Note 5 to the consolidated financial statements for further information.
Financial Risks
Our profitability depends on our ability to recover costs and changes in regulation may impair our ability to recover costs from our customers.
We are subject to comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and the rates that we can charge customers.
The profitability of our operations is dependent on our ability to recover the costs of providing energy and utility services and earn a return on capital investment. Our rates are generally regulated and are based on an analysis of our costs incurred in a test year. We are subject to both future and historical test years depending upon the regulatory jurisdiction. Thus, the rates we are allowed to charge may or may not match our costs at any given time. Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital.
There can also be no assurance that our regulatory commissions will judge all our costs to be prudent, which could result in disallowances, or that the regulatory process will always result in rates that will produce full recovery.
Overall, management believes prudently incurred costs are recoverable given the existing regulatory framework. However, there may be changes in the regulatory environment that could impair our ability to recover costs historically collected from customers, or we could exceed caps on capital costs required by commissions and result in less than full recovery.
Changes in the long-term cost-effectiveness or to the operating conditions of our assets may result in early retirements of utility facilities. While regulation typically provides cost recovery relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs.
Higher than expected inflation or tariffs may increase costs of construction and operations. Also, rising fuel costs could increase the risk that we will not be able to fully recover our fuel costs from our customers.
Adverse regulatory rulings (including changes in recovery mechanisms) or the imposition of additional regulations could have an adverse impact on our results of operations and materially affect our ability to meet our financial obligations, including debt payments and the payment of dividends on common stock.
Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.
We cannot be assured that our current credit ratings will remain in effect, or that a rating will not be lowered or withdrawn by a rating agency. Significant events including disallowance of costs, use of historic test years, elimination of riders or interim rates, increasing depreciation lives, lower returns on equity, changes to equity ratios and impacts of tax policy may impact our cash flows and credit metrics, potentially resulting in a change in our credit ratings. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies.
Any credit ratings downgrade could lead to higher borrowing costs or lower proceeds from equity issuances. It could also impact our ability to access capital markets. Also, we may enter into contracts that require posting of collateral or settlement if credit ratings fall below investment grade.
We are subject to capital market and interest rate risks.
Utility operations require significant capital investment. As a result, we frequently need to access capital markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital market disruption and financial market distress could prevent us from issuing commercial paper, issuing new securities or cause us to issue securities with unfavorable terms and conditions, such as higher interest rates or lower proceeds from equity issuances. Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results.
The performance of capital markets impacts the value of assets held in trusts to satisfy future obligations to decommission our nuclear plants and satisfy our defined benefit pension and postretirement benefit plan obligations. These assets are subject to market fluctuations and yield uncertain returns, which may fall below expected returns. A decline in the market value of these assets may increase funding requirements. Additionally, the fair value of the debt securities held in the nuclear decommissioning and/or pension trusts may be impacted by changes in interest rates.
We are subject to credit risks.
Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in our liquidity and an increase in bad debt expense. Credit risk is comprised of numerous factors including the price of products and services provided, the economy and unemployment rates.
Credit risk also includes the risk that counterparties that owe us money or product will become insolvent and may breach their obligations. Should the counterparties fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and incur losses.
We may have direct credit exposure in our short-term wholesale and commodity trading activity to financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties. We may also have some indirect credit exposure due to participation in organized markets, (e.g., MISO, Electric Reliability Council of Texas and California ISO), in which any credit losses are socialized to all market participants.
We have additional indirect credit exposure to financial institutions from letters of credit provided as security by power suppliers under various purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below investment grade, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party could be in default under the contract.
As we are a subsidiary of Xcel Energy Inc., we may be negatively affected by events impacting the credit or liquidity of Xcel Energy Inc. and its affiliates.
If either S&P or Moody’s were to downgrade Xcel Energy Inc.’s debt securities below investment grade, it would increase Xcel Energy Inc.’s cost of capital and restrict its access to the capital markets. This could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.
As of Dec. 31, 2022, Xcel Energy Inc. and its utility subsidiaries had approximately $22.8 billion of long-term debt and $2.0 billion of short-term debt and current maturities. Xcel Energy Inc. provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries for specified agreements or transactions.
Xcel Energy also has other contingent liabilities resulting from various tax disputes and other matters. Xcel Energy Inc.’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. The majority of Xcel Energy Inc.’s guarantees limit its exposure to a maximum amount that is stated in the guarantees.
As of Dec. 31, 2022, Xcel Energy had the following guarantees outstanding:
•$1 million maximum stated amount and immaterial exposure.
•$61 million for performance and payment of surety bonds for the benefit of itself and its subsidiaries, with total exposure that cannot be estimated at this time.
•$98 million for performance and payment of a capital services contract for solar generating equipment, with immaterial exposure.
If Xcel Energy Inc. were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund other contingent liabilities, it could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us, or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.
Increasing costs of our defined benefit retirement plans and employee benefits may adversely affect our results of operations, financial condition or cash flows.
We have defined benefit pension and postretirement plans that cover most of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements of these plans. Estimates and assumptions may change. In addition, the Pension Protection Act sets the minimum funding requirements for defined benefit pension plans. Therefore, our funding requirements and contributions may change in the future. Also, the payout of a significant percentage of pension plan liabilities in a single year due to high numbers of retirements or employees leaving NSP-Minnesota could trigger settlement accounting and could require NSP-Minnesota to recognize incremental pension expense related to unrecognized plan losses in the year liabilities are paid. Changes in industry standards utilized in key assumptions (e.g., mortality tables) could have a significant impact on future obligations and benefit costs.
Increasing costs associated with health care plans may adversely affect our results of operations.
Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our results of operations, financial condition or cash flows. Health care legislation could also significantly impact our benefit programs and costs.
Federal tax law may significantly impact our business.
NSP-Minnesota collects estimated federal, state and local tax payments through their regulated rates. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Tax depreciable lives and the value/availability of various tax credits or the timeliness of their utilization may impact the economics or selection of resources. If tax rates are increased, there could be timing delays before regulated rates provide for recovery of such tax increases in revenues. In addition, certain IRS tax policies such as tax normalization may impact our ability to economically deliver certain types of resources relative to market prices.
Macroeconomic Risks
Economic conditions impact our business.
Our operations are affected by economic conditions, which correlates to customers/sales growth (decline). Economic conditions may be impacted by recessionary factors, rising interest rates and insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay their bills which could lead to additional bad debt expense.
Additionally, NSP-Minnesota faces competitive factors, which could have an adverse impact on our financial condition, results of operations and cash flows. Further, worldwide economic activity impacts the demand for basic commodities necessary for utility infrastructure, which may inhibit our ability to acquire sufficient supplies. We operate in a capital intensive industry and federal trade policy could significantly impact the cost of materials we use. There may be delays before these additional material costs can be recovered in rates.
We face risks related to health epidemics and other outbreaks, which may have a material effect on our financial condition, results of operations and cash flows.
Health epidemics continue to impact countries, communities, supply chains and markets. Uncertainty continues to exist regarding epidemics; the duration and magnitude of business restrictions including shutdowns (domestically and globally); the potential impact on the workforce including shortages of employees and third-party contractors due to quarantine policies, vaccination requirements or government restrictions; impacts on the transportation of goods, and the generalized impact on the economy.
We cannot ultimately predict whether an epidemic will have a material impact on our future liquidity, financial condition or results of operations. Nor can we predict the impact on the health of our employees, our supply chain or our ability to recover higher costs associated with managing an outbreak.
Operations could be impacted by war, terrorism, or other events.
Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any disruption could impact operations or result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition, results of operations or cash flows. The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have incurred increased costs for security and capital expenditures in response to these risks. The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, insurance may have higher deductibles, higher premiums and more restrictive policy terms.
A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business, brand and reputation. Because our facilities are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility.
We also face the risks of possible loss of business due to significant events such as severe storms, temperature extremes, wildfires, widespread pandemic, generator or transmission facility outage, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or a workforce disruption.
In addition, major catastrophic events throughout the world may disrupt our business. While we have business continuity plans in place, our ability to recover may be prolonged due to the type and extent of the event. NSP-Minnesota participates in a global supply chain, which includes materials and components that are globally sourced. A prolonged disruption could result in the delay of equipment and materials that may impact our ability to connect, restore and reliably serve our customers.
A major disruption could result in a significant decrease in revenues, additional costs to repair assets, and an adverse impact on the cost and availability of insurance, which could have a material impact on our results of operations, financial condition or cash flows.
A cyber incident or security breach could have a material effect on our business.
We operate in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including Company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors and other individuals.
Our generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets, as well as information processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cyber security incidents, including those caused by human error.
The utility industry has been the target of several attacks on operational systems and has seen an increased volume and sophistication of cyber security incidents from international activist organizations, other countries and individuals. We expect to continue to experience attempts to compromise our information technology and control systems, network infrastructure and other assets. To date, no cybersecurity incident or attack has had a material impact on our business or results of operations.
Cyber security incidents could harm our businesses by limiting our generating, transmitting and distributing capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which would likely receive state and federal regulatory scrutiny and could expose us to liability.
Our generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cyber security incident on the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third-party service providers’ operations, could also negatively impact our business.
Our supply chain for procurement of digital equipment and services may expose software or hardware to these risks and could result in a breach or significant costs of remediation. We are unable to quantify the potential impact of cyber security threats or subsequent related actions. Cyber security incidents and regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third-party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.
We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cyber security incidents, including asset failure or unauthorized access to assets or information. A failure or breach of our technology systems or those of our third-party service providers could disrupt critical business functions and may negatively impact our business, our brand, and our reputation. The cyber security threat is dynamic and evolves continually, and our efforts to prioritize network protection may not be effective given the constant changes to threat vulnerability.
While the Company maintains insurance relating to cybersecurity events, such insurance is subject to a number of exclusions and may be insufficient to offset any losses, costs or damages experienced. Also, the market for cybersecurity insurance is relatively new and coverage available for cybersecurity events is evolving as the industry matures.
Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.
Our electric and natural gas utility businesses are seasonal and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand depends heavily upon weather patterns. A significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of operations or cash flows.
Public Policy Risks
Increased risks of regulatory penalties could negatively impact our business.
The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. FERC can impose penalties of up to $1.5 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Also, the PHMSA, Occupational Safety and Health Administration and other federal agencies have the authority to assess penalties.
In the event of serious incidents, these agencies may pursue penalties. In addition, certain states have the authority to impose substantial penalties. If a serious reliability, cyber or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows.
The continued use of natural gas for both power generation and gas distribution have increasingly become a public policy advocacy target. These efforts may result in a limitation of natural gas as an energy source for both power generation and heating, which could impact our ability to reliably and affordably serve our customers.
In recent years, there have been various local and state agency proposals within and outside our service territories that would attempt to restrict the use and availability of natural gas. If such policies were to prevail, we may be forced to make new resource investment decisions which could potentially result in stranded costs if we are not able to fully recover costs and investments and impact the overall reliability of our service.
Environmental Policy Risks
We may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.
Legislative and regulatory responses related to climate change may create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. International agreements could additionally lead to future federal or state regulations.
In 2015, the United Nations Framework Convention on Climate Change reached consensus among 190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries, with a goal of holding the increase in global average temperature to below 2º Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5º Celsius.
International commitments and agreements could result in future additional GHG reductions in the United States. In addition, in 2023 the EPA intends to publish draft regulations for GHG emissions from the power sector consistent with the agency’s Clean Air Act authorities.
Many states and localities continue to pursue their own climate policies. The steps NSP-Minnesota has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation and retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies.
We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.
If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial condition or cash flows.
We are subject to environmental laws and regulations, with which compliance could be difficult and costly.
We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. Laws and regulations require us to obtain permits, licenses, and approvals and to comply with a variety of environmental requirements.
Environmental laws and regulations can also require us to restrict or limit the output of facilities or the use of certain fuels, shift generation to lower-emitting facilities, install pollution control equipment, clean up spills and other contamination and correct environmental hazards. Failure to meet requirements of environmental mandates may result in fines or penalties. We may be required to pay all or a portion of the cost to remediate sites where our past activities, or the activities of other parties, caused environmental contamination.
Changes in environmental policies and regulations or regulatory decisions may result in early retirements of our generation facilities. While regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs.
We are subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. It could have a material effect on our results of operations, financial condition or cash flows if our regulators do not allow us to recover the cost of capital investment or O&M costs incurred to comply with the requirements.
In addition, existing environmental laws or regulations may be revised and new laws or regulations may be adopted. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.
We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.
Climate change can create physical and financial risk. Physical risks include changes in weather conditions and extreme weather events.
Our customers’ energy needs vary with weather. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease. Increased energy use due to weather changes may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues.
Climate change may impact the economy, which could impact our sales and revenues. The price of energy has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as regulation of GHG, could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.
We establish strategies and expectations related to climate change and other environmental matters. Our ability to achieve any such strategies or expectations is subject to numerous factors and conditions, many of which are outside of our control. Examples of such factors include, but are not limited to, evolving legal, regulatory, and other standards, processes, and assumptions, the pace of scientific and technological developments, increased costs, the availability of requisite financing, and changes in carbon markets. Failures or delays (whether actual or perceived) in achieving our strategies or expectations related to climate change and other environmental matters could adversely affect our business, operations, and reputation, and increase risk of litigation.
Severe weather impacts our service territories, primarily when thunderstorms, flooding, tornadoes, wildfires and snow or ice storms or extreme temperatures (high heating/cooling days) occur. Extreme weather conditions in general require system backup and can contribute to increased system stress, including service interruptions. Extreme weather conditions creating high energy demand may raise electricity prices, increasing the cost of energy we provide to our customers.
To the extent the frequency of extreme weather events increases, this could increase our cost of providing service and result in more frequent service interruptions. Periods of extreme temperatures could also impact our ability to meet demand.
More frequent and severe drought conditions, extreme swings in amount and timing of precipitation, changes in vegetation, unseasonably warm temperatures, very low humidity, stronger winds and other factors have increased the duration of the wildfire season and the potential impact of an event. Also, the expansion of the wildland urban interface increases the wildfire risk to surrounding communities and NSP-Minnesota’s electric and natural gas infrastructure.
Other potential risks associated with wildfires include the inability to secure sufficient insurance coverage, or increased costs of insurance, regulatory recovery risk, and the potential for a credit downgrade and subsequent additional costs to access capital markets.
While we carry liability insurance, given an extreme event, if NSP-Minnesota was found to be liable for wildfire damages, amounts that potentially exceed our coverage could negatively impact our results of operations, financial condition or cash flows. Drought or water depletion could adversely impact our ability to provide electricity to customers, cause early retirement of power plants and increase the cost for energy. Adverse events may result in increased insurance costs and/or decreased insurance availability We may not recover all costs related to mitigating these physical and financial risks.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B - UNRESOLVED STAFF COMMENTS
None.

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ITEM 2. PROPERTIES
ITEM 2 - PROPERTIES
Virtually all of the utility plant property of NSP-Minnesota is subject to the lien of its first mortgage bond indenture.
Station, Location and Unit at Dec. 31, 2022 Fuel Installed MW (a)
Steam:
A.S. King-Bayport, MN, 1 Unit Coal 1968 511
Sherco-Becker, MN
Unit 1 Coal 1976 680
Unit 2 Coal 1977 682
Unit 3 Coal 1987 517 (b)
Monticello, MN, 1 Unit Nuclear 1971 617
PI-Welch, MN
Unit 1 Nuclear 1973 521
Unit 2 Nuclear 1974 519
Various locations, 4 Units Wood/Refuse Various 36 (c)
Combustion Turbine:
Angus Anson-Sioux Falls, SD, 3 Units Natural Gas 1994 - 2005 327
Black Dog-Burnsville, MN, 3 Units Natural Gas 1987 - 2018 494
Blue Lake-Shakopee, MN, 6 Units Natural Gas 1974 - 2005 447
High Bridge-St. Paul, MN, 3 Units Natural Gas 2008 530
Inver Hills-Inver Grove Heights, MN, 6 Units Natural Gas 1972 252
Riverside-Minneapolis, MN, 3 Units Natural Gas 2009 454
Various locations, 7 Units Natural Gas Various 10
Wind:
Blazing Star 1-Lincoln County, MN, 100 Units Wind 2020 200 (d)
Blazing Star 2-Lincoln County, MN, 100 Units Wind 2021 200 (d)
Border-Rolette County, ND, 75 Units Wind 2015 148 (d)
Community Wind North-Lincoln County, MN, 12 Units Wind 2020 26 (d)
Courtenay Wind-Stutsman County, ND, 100 Units Wind 2016 190 (d)
Crowned Ridge 2-Grant County, SD, 88 Units Wind 2020 192 (d)
Dakota Range, SD, 72 Units Wind 2022 298 (d)
Foxtail-Dickey County, ND, 75 Units Wind 2019 150 (d)
Freeborn-Freeborn County, MN, 100 Units Wind 2021 200 (d)
Grand Meadow-Mower County, MN, 67 Units Wind 2008 99 (d)
Jeffers-Cottonwood County, MN, 20 Units Wind 2020 43 (d)
Lake Benton-Pipestone County, MN, 44 Units Wind 2019 99 (d)
Mower-Mower County, MN, 43 Units Wind 2021 91 (d)
Nobles-Nobles County, MN, 133 Units (e)
Wind 2010 200 (d)
Pleasant Valley-Mower County, MN, 100 Units Wind 2015 196 (d)
Rock Aetna - Murray County, MN, 8 Units Wind 2022 20 (d)
Total 8,949
(a)Summer 2022 net dependable capacity.
(b)Based on NSP-Minnesota’s ownership of 59%.
(c)Refuse-derived fuel is made from municipal solid waste.
(d)Capacity is attainable only when wind conditions are sufficiently available.
(e)Repowered in 2022.
Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2022:
Conductor Miles
Transmission
500 KV 2,915
345 KV 12,183
230 KV 2,300
161 KV 626
115 KV 8,033
Less than 115 KV 6,537
Total Transmission 32,594
Distribution
Less than 115 KV 82,024
Total 114,618
NSP-Minnesota had 352 electric utility transmission and distribution substations at Dec. 31, 2022.
Natural gas utility mains at Dec. 31, 2022:
Miles
Transmission 78
Distribution 10,902

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ITEM 3. LEGAL PROCEEDINGS
ITEM 3 - LEGAL PROCEEDINGS
NSP-Minnesota is involved in various litigation matters in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for losses probable of being incurred and subject to reasonable estimation.
Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to, when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.
For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on NSP-Minnesota’s consolidated financial statements. Legal fees are generally expensed as incurred.
See Note 10 to the consolidated financial statements, Item 1 and Item 7 for further information.

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ITEM 4. MINE SAFETY DISCLOSURE
ITEM 4 - MINE SAFETY DISCLOSURES
None.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
ITEM 5 - MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
NSP-Minnesota is a wholly owned subsidiary of Xcel Energy Inc. and there is no market for its common equity securities.
The dividends declared during 2022 and 2021 were as follows:
(Millions of Dollars) 2022 2021
First quarter $ 167 $ 109
Second quarter 114 107
Third quarter 182 109
Fourth quarter 123 96

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ITEM 6. SELECTED FINANCIAL DATA
ITEM 6 - [RESERVED]

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
ITEM 7 - MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Discussion of financial condition and liquidity for NSP-Minnesota is omitted per conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries. It is replaced with management’s narrative analysis of the results of operations set forth in General Instruction I(2)(a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).
Non-GAAP Financial Measures
The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as ongoing earnings. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that are adjusted from measures calculated and presented in accordance with GAAP.
NSP-Minnesota’s management uses non-GAAP measures for financial planning and analysis, for reporting of results to the Board of Directors, in determining performance-based compensation and communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.
Earnings Adjusted for Certain Items (Ongoing Earnings)
Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items.
We use these non-GAAP financial measures to evaluate and provide details of NSP-Minnesota’s core earnings and underlying performance. We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of NSP-Minnesota. For the years ended Dec. 31, 2022 and 2021, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings.
Results of Operations
2022 Comparison with 2021
NSP-Minnesota’s net income was approximately $675 million for 2022, compared with approximately $606 million for 2021. The increase in earnings is driven primarily by regulatory rate outcomes, partially offset by additional depreciation and O&M expenses.
Electric Margin
Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Expenses incurred for electric fuel and purchased power are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues.
Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and uranium. However, these price fluctuations generally have minimal impact on earnings impact due to fuel recovery mechanisms. In addition, electric customers receive a credit for PTCs generated, which reduce electric revenue and income taxes.
Electric Revenues, Fuel and Purchased Power and Electric Margin
(Millions of Dollars) 2022 2021
Electric revenues $ 5,617 $ 5,094
Electric fuel and purchased power (2,416) (2,042)
Electric margin $ 3,201 $ 3,052
Changes in Electric Margin
(Millions of Dollars) 2022 vs. 2021
Regulatory rate outcome (Minnesota) $ 183
Non-fuel riders 36
Wholesale transmission (net)
PTCs flowed back to customers (offset by lower ETR) (109)
Other (net) 11
Total increase $ 149
Natural Gas Margin
Natural gas margin is presented as natural gas revenues less the cost of natural gas sold and transported. Expenses incurred for the cost of natural gas sold are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues.
Natural gas expense varies with changing sales and the cost of natural gas. However, fluctuations in the cost of natural gas generally have minimal earnings impact due to cost recovery mechanisms.
Natural Gas Revenues, Cost of Natural Gas Sold and Transported and Natural Gas Margin
(Millions of Dollars) 2022 2021
Natural gas revenues $ 1,022 $ 623
Cost of natural gas sold and transported (741) (385)
Natural gas margin $ 281 $ 238
Changes in Natural Gas Margin
(Millions of Dollars) 2022 vs. 2021
Regulatory rate outcomes (Minnesota, North Dakota) $ 27
Estimated impact of weather 12
Conservation revenue (offset in expenses) 9
Infrastructure and integrity riders 7
Winter Storm Uri disallowance (16)
Other (net) 4
Total increase $ 43
Non-Fuel Operating Expenses and Other Items
O&M Expenses - O&M expenses increased $38 million year-to-date. The increase was primarily due to inflation and impacts of supply chain constraints; operational activities (vegetation management, repairs/maintenance and storms); costs for technology and customer programs; insurance-related costs; interchange; and other.
Depreciation and Amortization - Depreciation and amortization expense increased $88 million for 2022. The increase was primarily driven by capital investment, including several wind farms going into service in 2021 and 2022.
Interest Charges - Interest charges increased $20 million year-to-date. The increase was largely due to higher debt levels to fund capital investments and higher interest rates.
Income Taxes - Income tax benefit increased $64 million for 2022. The increase was primarily driven by increased wind PTCs due to several new wind farms going into service and greater production at existing wind farms. Wind PTCs are credited to customers (recorded as a reduction to revenue) and do not have a material impact on net income.
Public Utility Regulation
The FERC and various state and local regulatory commissions regulate NSP-Minnesota. NSP-Minnesota is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota and South Dakota.
Rates are designed to recover plant investment, operating costs and an allowed return on investment. NSP-Minnesota requests changes in utility rates through commission filings. Changes in operating costs can affect NSP-Minnesota’s financial results, depending on the timing of rate cases and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and demand side management efforts, and the cost of capital.
In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings. Decisions by these regulators can significantly impact NSP-Minnesota’s results of operations and credit quality.
See Rate Matters within Note 12 to the consolidated financial statements for further information.
Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
Regulatory Body / RTO Additional Information
MPUC Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations.
Reviews and approves Integrated Resource Plans for meeting future energy needs.
Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota.
Reviews and approves natural gas supply plans.
NDPSC Retail rates, services and other aspects of electric and natural gas operations.
Reviews and approves Integrated Resource Plans for meeting future energy needs.
Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota.
Pipeline safety compliance.
SDPUC Retail rates, services and other aspects of electric operations.
Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota.
Pipeline safety compliance.
FERC Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce.
MISO NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC.
DOT Pipeline safety compliance.
Minnesota Office of Pipeline Safety Pipeline safety compliance.
Recovery Mechanisms
Mechanism Additional Information
CIP Rider (a)
Recovers costs of conservation and DSM programs in Minnesota.
Environmental Improvement Rider Recovers costs of environmental improvement projects in Minnesota.
Renewable Development Fund Allocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.
RES Recovers cost of renewable generation in Minnesota.
Renewable Energy Rider Recovers cost of renewable generation in North Dakota.
Transmission Cost Recovery Recovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization.
Infrastructure Rider Recovers costs for investments in generation in South Dakota.
Fuel Clause Adjustment Recovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).
Purchased Gas Adjustment Provides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.
GUIC Rider Recovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota. The statute authorizing the GUIC Rider is set to expire June 30, 2023.
Sales True-up NSP-Minnesota has historically had a sales true-up mechanism for all electric customer classes which ended in 2021. We are requesting implementation of a new sales true-up mechanism for 2022 - 2024. These mechanisms mitigate the impact of changes to sales levels as compared to a baseline.
(a)Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.
Pending and Recently Concluded Regulatory Proceedings
2022 Minnesota Electric Rate Case - In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. The request is based on a ROE of 10.2%, a 52.5% equity ratio and forward test years.
In December 2021, the MPUC approved interim rates, subject to refund, of $247 million, effective Jan. 1, 2022. In November 2022, NSP-Minnesota revised its rate request to $498 million over three years.
The revised request is detailed as follows:
(Amounts in Millions) 2022 2023 2024 Total
Rate request (annual increase) $ 234 $ 94 $ 170 $ 498
Rate base $ 10,923 $ 11,425 $ 11,902 N/A
In 2022, several parties filed testimony with various recommendations. The DOC provided the following recommendations in surrebuttal testimony.
2022 2023 2024
NSP-Minnesota’s filed base revenue request $ 396 $ 546 $ 677
Recommended adjustments:
Rate base and rate of return (72) (65) (65)
MISO capacity credits (66) (112) (111)
Sales forecast update (51) - -
Monticello and wind farm life extension (21) (54) (51)
PTC forecast (28) (1) (1)
Property tax (14) (23) (34)
Prepaid pension asset and liability (13) (21) (32)
O&M expenses (37) (39) (44)
Sherco 3 and King remaining life - 29 28
Other, net (23) (33) (43)
Total adjustments (325) (319) (353)
Total proposed revenue change $ 71 $ 227 $ 324
Next steps in the procedural schedule are expected to be as follows:
•ALJ Report: March 31, 2023.
•MPUC Order: June 30, 2023.
2022 Minnesota Natural Gas Rate Case - In November 2021, NSP-Minnesota filed a request with the MPUC for a natural gas rate increase of $36 million, or 6.6%. The filing is based on a 2022 forecast test year and includes a requested ROE of 10.5%, an equity ratio of 52.5% and a rate base of $934 million. In December 2021, the MPUC approved an interim rate increase of $25 million, subject to refund, effective Jan. 1, 2022.
In October 2022, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following key terms:
•Base rate revenue increase of $21 million, with a true up to weather normalized actual sales for 2022.
•Revenue decoupling mechanism.
•Symmetrical property tax true-up.
•ROE of 9.57%.
•Equity ratio of 52.5%.
In December 2022, the ALJ recommended MPUC approval of the settlement. A MPUC decision is expected in the first half of 2023.
2021 North Dakota Natural Gas Rate Case - In September 2021, NSP-Minnesota filed a request with the NDPSC for a natural gas rate increase of $7 million, or 10.5%. The filing is based on a ROE of 10.5%, an equity ratio of 52.54%, a 2022 forecast test year and rate base of $124 million. Interim rates of $7 million, subject to refund, were implemented on Nov. 1, 2021.
In May 2022, NSP-Minnesota and NDPSC Staff reached a settlement, which reflects a rate increase of $5 million, based on a 9.8% ROE and 52.54% equity ratio. In October 2022, the NDPSC approved the settlement and final rates were implemented on Nov. 1, 2022.
South Dakota Electric Rate Case - In June 2022, NSP-Minnesota filed a South Dakota electric rate case seeking a revenue increase of approximately $44 million. The filing is based on a 2021 historic test year adjusted for certain known and measurable changes for 2022 and 2023, a ROE of 10.75%, rate base of approximately $947 million and an equity ratio of 53%. Interim rates were implemented on Jan. 1, 2023. Final rates are expected to be approved by the SDPUC in mid-2023.
Wind Repowering - In January 2021, the MPUC approved NSP-Minnesota’s request for the repowering of 651 MW of owned wind projects. Two of the four repowering projects, where construction has not yet begun (in-service dates in 2025), now expect costs in excess of the original approval. While the capital costs have increased, the passage of the IRA and other changes result in a levelized cost of energy that is approximately 30% lower than the original approval.
In October 2022, NSP-Minnesota filed a request with the MPUC seeking approval of the higher capital costs for these repowering projects. In February 2023, the DOC filed comments recommending approval of recovery of the increased costs of these projects through the RES Rider. A final decision is pending.
2022 Upper Midwest RFP - In August 2022, NSP-Minnesota launched a RFP for 900 MW of solar or solar-plus-storage hybrid resources to come online by the end of 2025, including up to 300 MW of capacity to reuse the Sherco Unit 2 interconnection rights when the coal facility retires at the end of 2023.
NSP-Minnesota completed its bid evaluation process in December 2022 and will file for approval of the selected projects in early 2023.
2022 Minnesota Electric Vehicle Proposal - In August 2022, NSP-Minnesota filed a request with the MPUC for approval of approximately $320 million of capital investments (2022 through 2026) to support a public charging network, electric school bus pilot, and other expansions and modifications to its residential and commercial electric vehicle programs.
In October 2022, the MPUC referred the matter to the Office of Administrative Hearings to conduct a contested case on the proposals. In February 2023, other parties to the contested proceeding filed their direct testimony ranging in levels of support / opposition to the proposals. The evidentiary hearing is scheduled in Q2 2023 with a report from the ALJ expected in Q3 2023. A MPUC decision is expected in late 2023.
Nuclear Power Operations
Nuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.
NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.
Low-Level Waste Disposal - Low level waste from Monticello and PI is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site at PI and Monticello which would allow both plants to continue to operate until the end of their current licensed lives if off-site low-level waste disposal facilities become unavailable.
High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management.
This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.
Nuclear Spent Fuel Storage - NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and PI nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until the end of the operating licenses in 2030 for Monticello, 2033 for PI Unit 1, and 2034 for PI Unit 2.
In September 2021, NSP-Minnesota filed an application for a CON for additional spent fuel storage (existing Independent spent fuel storage installation) at the Monticello Nuclear Power Generating Plant to allow continued operation of the Monticello Plant until 2040.
A decision is expected in late 2023. Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations.
In February 2023, NSP-Minnesota also filed an application with the NDPSC for an Advance Determination of Prudence for continued operation of the Monticello Plant until at least 2040. A decision is expected in 2023.
Wholesale and Commodity Marketing Operations
NSP-Minnesota conducts wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy-related products. NSP-Minnesota uses physical and financial instruments to minimize commodity price risk and to hedge sales and purchases.
NSP-Minnesota also engages in trading activity unrelated to these hedging activities. Sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement. NSP-Minnesota does not serve any wholesale requirements customers at cost-based regulated rates.
Other
Supply Chain
NSP-Minnesota’s ability to meet customer energy requirements, respond to storm-related disruptions and execute our capital expenditure program are dependent on maintaining an efficient supply chain. Manufacturing processes have experienced disruptions related to scarcity of certain raw materials and interruptions in production and shipping. These disruptions have been further exacerbated by inflationary pressures, labor shortages and the impact of international conflicts/issues. NSP-Minnesota continues to monitor the situation as it remains fluid and seeks to mitigate the impacts by securing alternative suppliers, modifying design standards, and adjusting the timing of work.
Electric Distribution and Transmission Transformers
The availability of certain transformers is an industry-wide issue that has been significantly impacted and in some cases may result in delays in projects and new customer connections. NSP-Minnesota continues to seek alternative suppliers and prioritize work plans to mitigate impacts of supply constraints.
Solar Resources
In April 2022, the U.S. Department of Commerce initiated an anti-circumvention investigation that would subject CSPV solar panels and cells imported from Malaysia, Vietnam, Thailand, and Cambodia with potential incremental tariffs ranging from 50% to 250%. These countries account for more than 80% of CSPV panel imports.
An interim stay on tariffs has been issued and many significant solar projects have resumed with modified costs and projected in-service dates, including the Sherco Solar facility. Further policy action or other restrictions on solar imports (i.e., as a result of implementation of the Uyghur Forced Labor Protection Act) could impact project timelines and costs.
MISO Capacity Credits
The NSP System offered 1,500 MW of excess capacity into the MISO planning resource auction for June 2022 through May 2023. Due to a projected overall capacity shortfall in the MISO region, the 1,500 MWs offered cleared the auction at maximum pricing, generating revenues of approximately $90 million in 2022, with approximately $60 million expected in 2023. These amounts mitigate customer rate increases or are returned through earnings sharing or other mechanisms.
Inflation Reduction Act
In August 2022, the IRA was signed into law.
Key provisions impacting NSP-Minnesota include:
•Extends current PTC and ITC for renewable technologies (e.g., wind and solar).
•Restores full value of the PTC and ITC for qualifying facilities placed in-service after 2021.
•Creates a PTC for solar, clean hydrogen and nuclear.
•Establishes an ITC for energy storage, microgrids, interconnection facilities, etc.
•Allows companies to monetize or sell credits to unrelated parties.
NSP-Minnesota anticipates the IRA will drive significant customer savings for both new and existing Company owned renewable projects, assuming appropriate regulatory mechanisms and development of a market for the sale of tax credits. The IRA is expected to allow NSP-Minnesota to monetize tax credits more efficiently with the incremental benefits passed through to customers.
The IRA creates a nuclear PTC beginning in 2024 that may also provide additional savings to NSP System customers, depending on locational marginal pricing, as well as constructive U.S. Treasury guidance regarding computation of the credits.
In addition, the IRA created a new corporate AMT. NSP-Minnesota does not anticipate AMT having a material cash impact based on current estimates and our interpretation of AMT application.
Winter Storm Uri
In February 2021, the United States experienced Winter Storm Uri. Extreme cold temperatures impacted certain operational assets as well as the availability of renewable generation. The cold weather also affected the country’s supply and demand for natural gas. These factors contributed to extremely high market prices for natural gas and electricity. As a result of the extremely high market prices, NSP-Minnesota incurred net natural gas, fuel and purchased energy costs of approximately $230 million (largely deferred as regulatory assets).
NSP-Minnesota received approval of recovery in North Dakota from the NDPSC in 2021. Winter Storm Uri had no impact on South Dakota electric costs as NSP-Minnesota was a net seller in the market.
In 2021, NSP-Minnesota filed with the MPUC seeking recovery of $215 million in incremental costs from natural gas customers. In August 2021, the MPUC allowed recovery of $36 million of ordinary costs over 12 months through the PGA and of $179 million of costs deemed to be extraordinary (with no financing charge) starting in September 2021, pending a prudency review. The C&I class ($82 million) will be recovered over 27 months and the residential class ($97 million) will be recovered over a 63-month recovery period.
In May 2022, the ALJs found the Winter Storm Uri fuel costs were prudently incurred and recommended no disallowances. In August 2022, the MPUC approved recovery of Uri storm costs with a $19 million disallowance.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Derivatives, Risk Management and Market Risk
NSP-Minnesota is exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value for a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk.
NSP-Minnesota is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While NSP-Minnesota expects that the counterparties will perform on the contracts underlying its derivatives, the contracts expose NSP-Minnesota to credit and non-performance risk.
Distress in the financial markets may impact counterparty risk and the fair value of the securities in the nuclear decommissioning fund and pension fund.
Commodity Price Risk - We are exposed to commodity price risk in our electric and natural gas operations. Commodity price risk is managed by entering into long and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities.
Commodity price risk is also managed through the use of financial derivative instruments. Our risk management policy allows us to manage commodity price risk within each rate-regulated operation per commission approved hedge plans.
Wholesale and Commodity Trading Risk - NSP-Minnesota conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. NSP-Minnesota’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee.
Fair value of net commodity trading contracts as of Dec. 31, 2022:
Futures/ Forwards Maturity
(Millions of Dollars) Less Than 1 Year
1 to 3 Years 4 to 5 Years Greater Than 5 Years Total
Fair Value
NSP-Minnesota (a)
$ (8) $ (6) $ (7) $ (2) $ (23)
NSP-Minnesota (b)
5 (4) - (3) (2)
$ (3) $ (10) $ (7) $ (5) $ (25)
Options Maturity
(Millions of Dollars) Less Than 1 Year
1 to 3 Years
4 to 5 Years Greater Than 5 Years Total
Fair Value
NSP-Minnesota (b)
$ - $ - $ - $ 15 $ 15
(a)Prices actively quoted or based on actively quoted prices.
(b)Prices based on models and other valuation methods.
Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the years ended Dec. 31:
(Millions of Dollars) 2022 2021
Fair value of commodity trading net contracts outstanding at Jan. 1 $ (18) $ (8)
Contracts realized or settled during the period (7) (58)
Commodity trading contract additions and changes during the period 15 48
Fair value of commodity trading net contracts outstanding at Dec. 31 $ (10) $ (18)
A 10% increase and 10% decrease in forward market prices for NSP-Minnesota’s commodity trading contracts would have likewise increased and decreased pretax income from continuing operations, by approximately $2 million at Dec. 31, 2022 and $3 million at Dec. 31, 2021. Market price movements can exceed 10% under abnormal circumstances.
NSP-Minnesota’s commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations using an industry standard methodology known as VaR. VaR expresses the potential change in fair value of the outstanding contracts and obligations over a particular period of time under normal market conditions.
The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchases and normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:
(Millions of Dollars) Year Ended Dec. 31 Average High Low
2022 $ 2 $ 1 $ 5 $ -
2021 $ 1 $ 2 $ 52 $ 1
A short-term increase in VaR occurred during the week of Feb. 12, 2021 through Feb. 18, 2021. On Feb. 17, 2021, the portfolio VaR reached a high of $52 million. This increase in VaR was driven by the unprecedented market conditions during Winter Storm Uri. Prior to this weather event, VaR was $1 million and returned to $1 million by Feb. 19, 2021.
Nuclear Fuel Supply - NSP-Minnesota has contracted for its 2023 and 2024 enriched nuclear material requirements, which are in various stages of processing in Canada, Europe, and the United States. NSP-Minnesota is scheduled to take delivery of approximately 26% of its average enriched nuclear material requirements from Russia through 2030. We are closely monitoring the evolving situation in Ukraine and its global impacts. NSP-Minnesota is in the process of entering into new contracts to reduce the risk of supply interruptions of nuclear material from Russia. NSP-Minnesota will take additional further action to reduce this risk as necessary.
Interest Rate Risk - NSP-Minnesota is subject to interest rate risk. NSP-Minnesota’s risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives.
A 100-basis-point change in the benchmark rate on NSP-Minnesota’s variable rate debt would impact pretax interest expense annually by approximately $2 million and an immaterial amount in 2022 and 2021, respectively.
NSP-Minnesota maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate and equity price risk. The fund is invested in a diversified portfolio of cash equivalents, debt securities, equity securities and other investments. These investments may be used only for the purpose of decommissioning NSP-Minnesota’s nuclear generating plants.
Fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on earnings due to the application of regulatory accounting. Realized and unrealized gains on the decommissioning fund investments are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs.
The value of pension and postretirement plan assets and benefit costs are impacted by changes in discount rates and expected return on plan assets. NSP-Minnesota’s ongoing pension and postretirement investment strategy is based on plan-specific investment recommendations that seek to optimize potential investment risk and minimize interest rate risk associated with changes in the obligations as a plan’s funded status increases over time. The impacts of fluctuations in interest rates on pension and postretirement costs are mitigated by pension cost calculation methodologies and regulatory mechanisms that minimize the earnings impacts of such changes.
Credit Risk - NSP-Minnesota is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance on their contractual obligations. NSP-Minnesota maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.
At Dec. 31, 2022, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $30 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $29 million. At Dec. 31, 2021, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $28 million, while a decrease in prices of 10% would have resulted in an decrease in credit exposure of $18 million.
NSP-Minnesota conducts credit reviews for all wholesale, trading and non-trading commodity counterparties and employs credit risk controls, such as letters of credit, parental guarantees, master netting agreements and termination provisions. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase NSP-Minnesota’s credit risk.
Fair Value Measurements
Derivative contracts, with the exception of those designated as normal purchases and normal sales, are reported at fair value. NSP-Minnesota’s investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value accounting. See Notes 8 and 9 to the consolidated financial statements for further information.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See Item 15 - 1 for an index of financial statements included herein.
See Note 14 to the consolidated financial statements for further information.
Management Report on Internal Control Over Financial Reporting
The management of NSP-Minnesota is responsible for establishing and maintaining adequate internal control over financial reporting. NSP-Minnesota’s internal control system was designed to provide reasonable assurance to Xcel Energy Inc.’s and NSP-Minnesota’s management and board of directors regarding the preparation and fair presentation of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
NSP-Minnesota management assessed the effectiveness of NSP-Minnesota’s internal control over financial reporting as of Dec. 31, 2022. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework (2013). Based on our assessment, we believe that, as of Dec. 31, 2022, NSP-Minnesota’s internal control over financial reporting is effective at the reasonable assurance level based on those criteria.
/s/ ROBERT C. FRENZEL /s/ BRIAN J. VAN ABEL
Robert C. Frenzel Brian J. Van Abel
Chairman, Chief Executive Officer and Director Executive Vice President, Chief Financial Officer and Director
Feb. 23, 2023 Feb. 23, 2023
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholder and the Board of Directors of Northern States Power Company, a Minnesota corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Northern States Power Company, a Minnesota corporation and subsidiaries (the "Company") as of December 31, 2022 and 2021, the related consolidated statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2022, and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Assets and Liabilities - Impact of Rate Regulation on the Financial Statements - Refer to Notes 4 and 10 to the consolidated financial statements.
Critical Audit Matter Description
The Company is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric distribution companies in Minnesota, North Dakota and South Dakota, and natural gas distribution companies in Minnesota and North Dakota. The Company is also subject to the jurisdiction of the Federal Energy Regulatory Commission for its wholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with North American Electric Reliability Corporation standards, asset transactions and mergers and natural gas transactions in interstate commerce, (collectively with state utility regulatory agencies, the “Commissions”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation affects multiple financial statement line items and disclosures, including property, plant and equipment, regulatory assets and liabilities, operating revenues and expenses, and income taxes.
The Company is subject to regulatory rate setting processes. Rates are determined and approved in regulatory proceedings based on an analysis of the Company’s costs to provide utility service and a return on, and recovery of, the Company’s investment in assets required to deliver services to customers. Accounting for the Company’s regulated operations provides that rate-regulated entities report assets and liabilities consistent with the recovery of those incurred costs in rates, if it is probable that such rates will be charged and collected. The Commissions’ regulation of rates is premised on the full recovery of incurred costs and a reasonable rate of return on invested capital. Decisions by the Commissions in the future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. In the rate setting process, the Company’s rates result in the recording of regulatory assets and liabilities based on the probability of future cash flows. Regulatory assets generally represent incurred or accrued costs that have been deferred because future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant, and 3) a refund due to customers. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the recognition of regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the Commissions for the Company, regulatory statutes, interpretations, procedural schedules and memorandums, filings made by intervenors, experts’ testimony and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We also evaluated regulatory filings for any evidence that intervenors are challenging full recovery of the cost of any capital projects. If the full recovery of project costs is being challenged by intervenors, we evaluated management’s assessment of the probability of a disallowance. We evaluated the external information and compared to the Company’s recorded regulatory assets and liabilities for completeness.
•We obtained management’s analysis and correspondence from counsel, as appropriate, regarding regulatory assets or liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 23, 2023
We have served as the Company’s auditor since 2002.
NSP-MINNESOTA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(amounts in millions)
Year Ended Dec. 31
2022 2021 2020
Operating revenues
Electric, non-affiliates $ 5,103 $ 4,593 $ 4,131
Electric, affiliates 514 501 440
Natural gas 1,022 623 493
Other 45 39 37
Total operating revenues 6,684 5,756 5,101
Operating expenses
Electric fuel and purchased power 2,416 2,042 1,626
Cost of natural gas sold and transported 741 385 263
Cost of sales - other 26 23 22
Operating and maintenance expenses 1,228 1,190 1,191
Conservation program expenses 163 144 119
Depreciation and amortization 1,014 926 825
Taxes (other than income taxes) 276 264 259
Total operating expenses 5,864 4,974 4,305
Operating income 820 782 796
Other (expense) income, net (7) 4 2
Allowance for funds used during construction - equity 29 30 25
Interest charges and financing costs
Interest charges - includes other financing costs of $8, $8 and $8, respectively
291 271 249
Allowance for funds used during construction - debt (12) (13) (11)
Total interest charges and financing costs 279 258 238
Income before income taxes 563 558 585
Income tax benefit (112) (48) (6)
Net income $ 675 $ 606 $ 591
See Notes to Consolidated Financial Statements
NSP-MINNESOTA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(amounts in millions)
Year Ended Dec. 31
2022 2021 2020
Net income $ 675 $ 606 $ 591
Other comprehensive income
Pension and retiree medical benefits:
Net pension and retiree medical gain arising during the period, net of tax of $- 1 - -
Derivative instruments:
Reclassification of losses to net income, net of tax of $-
1 2 1
Total other comprehensive income 2 2 1
Total comprehensive income $ 677 $ 608 $ 592
See Notes to Consolidated Financial Statements
NSP-MINNESOTA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(amounts in millions)
Year Ended Dec. 31
2022 2021 2020
Operating activities
Net income $ 675 $ 606 $ 591
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization 1,021 932 831
Nuclear fuel amortization 118 114 123
Deferred income taxes (214) (36) (67)
Allowance for equity funds used during construction (29) (30) (25)
Provision for bad debts 21 24 24
Changes in operating assets and liabilities:
Accounts receivable (102) (89) (55)
Accrued unbilled revenues (53) (71) 1
Inventories (85) (22) (14)
Other current assets (4) 3 (9)
Accounts payable 46 69 (1)
Net regulatory assets and liabilities 443 (282) (87)
Other current liabilities 39 (5) (58)
Pension and other employee benefit obligations (11) (41) (54)
Other, net 6 (50) (8)
Net cash provided by operating activities 1,871 1,122 1,192
Investing activities
Capital/construction expenditures (1,901) (1,866) (1,901)
Purchase of investment securities (1,332) (757) (1,398)
Proceeds from the sale of investment securities 1,297 743 1,378
Investments in utility money pool arrangement (1,522) (821) (718)
Repayments from utility money pool arrangement 1,613 730 718
Other, net 6 1 1
Net cash used in investing activities (1,839) (1,970) (1,920)
Financing activities
Proceeds from (repayments of) short-term borrowings, net 207 (179) 149
Borrowings under utility money pool arrangement 6 434 136
Repayments under utility money pool arrangement (6) (434) (136)
Proceeds from issuance of long-term debt 489 836 677
Repayment of long-term debt (300) - (300)
Capital contributions from parent 124 649 527
Dividends paid to parent (560) (431) (408)
Other, net - - 3
Net cash (used in) provided by financing activities (40) 875 648
Net change in cash, cash equivalents and restricted cash (8) 27 (80)
Cash, cash equivalents and restricted cash at beginning of period 73 46 126
Cash, cash equivalents and restricted cash at end of period $ 65 $ 73 $ 46
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized) $ (268) $ (245) $ (230)
Cash (paid) received for income taxes, net (100) 11 (53)
Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions $ 208 $ 242 $ 74
Inventory transfers to property, plant and equipment 10 8 24
Operating lease right-of-use assets 1 4 2
Allowance for equity funds used during construction 29 30 25
See Notes to Consolidated Financial Statements
NSP-MINNESOTA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(amounts in millions, except share and per share data)
Dec. 31
2022 2021
Assets
Current assets
Cash and cash equivalents $ 65 $ 73
Accounts receivable, net 534 429
Accounts receivable from affiliates 45 29
Investments in money pool arrangements - 91
Accrued unbilled revenues 372 319
Inventories 384 309
Regulatory assets 384 527
Derivative instruments 89 53
Prepayments and other 62 46
Total current assets 1,935 1,876
Property, plant and equipment, net 17,478 16,430
Other assets
Nuclear decommissioning fund and other investments 2,930 3,308
Regulatory assets 894 718
Derivative instruments 68 33
Operating lease right-of-use assets 324 408
Other 29 36
Total other assets 4,245 4,503
Total assets $ 23,658 $ 22,809
Liabilities and Equity
Current liabilities
Current portion of long-term debt $ 400 $ 300
Short-term debt 207 -
Accounts payable 619 522
Accounts payable to affiliates 89 63
Regulatory liabilities 191 117
Taxes accrued 272 260
Accrued interest 79 78
Dividends payable to parent 122 96
Derivative instruments 42 35
Operating lease liabilities 98 90
Other 227 166
Total current liabilities 2,346 1,727
Deferred credits and other liabilities
Deferred income taxes 1,666 1,949
Deferred investment tax credits 15 17
Regulatory liabilities 1,983 1,927
Asset retirement obligations 2,727 2,585
Derivative instruments 102 71
Pension and employee benefit obligations 155 112
Operating lease liabilities 256 353
Other 30 48
Total deferred credits and other liabilities 6,934 7,062
Commitments and contingencies
Capitalization
Long-term debt 6,542 6,447
Common stock - 5,000,000 shares authorized of $0.01 par value; 1,000,000 shares
outstanding at Dec. 31, 2022 and Dec. 31, 2021, respectively
- -
Additional paid in capital 5,374 5,202
Retained earnings 2,480 2,391
Accumulated other comprehensive loss (18) (20)
Total common stockholder's equity 7,836 7,573
Total liabilities and equity $ 23,658 $ 22,809
See Notes to Consolidated Financial Statements
NSP-MINNESOTA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
(amounts in millions, except share data)
Common Stock Accumulated Other
Comprehensive
Income (Loss) Total Common
Stockholder’s
Equity
Shares Par
Value
Additional
Paid In
Capital
Retained
Earnings
Balance at Dec. 31, 2019 1,000,000 $ - $ 4,068 $ 2,036 $ (23) $ 6,081
Net income 591 591
Other comprehensive income 1 1
Dividends declared to parent (420) (420)
Contribution of capital by parent 517 517
Adoption of ASC Topic 326 (1) (1)
Balance at Dec. 31, 2020 1,000,000 $ - $ 4,585 $ 2,206 $ (22) $ 6,769
Net income 606 606
Other comprehensive income 2 2
Dividends declared to parent (421) (421)
Contribution of capital by parent 617 617
Balance at Dec. 31, 2021 1,000,000 $ - $ 5,202 $ 2,391 $ (20) $ 7,573
Net income 675 675
Other comprehensive income 2 2
Dividends declared to parent (586) (586)
Contribution of capital by parent 172 172
Balance at Dec. 31, 2022 1,000,000 $ - $ 5,374 $ 2,480 $ (18) $ 7,836
See Notes to Consolidated Financial Statements
NORTHERN STATES POWER COMPANY - MINNESOTA
Notes to Consolidated Financial Statements
1. Summary of Significant Accounting Policies
General - NSP-Minnesota is engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and the regulated purchase, transportation, distribution and sale of natural gas.
NSP-Minnesota’s consolidated financial statements include its wholly-owned subsidiaries. In the consolidation process, all intercompany transactions and balances are eliminated. NSP-Minnesota has investments in certain plants and transmission facilities jointly owned with nonaffiliated utilities.
NSP-Minnesota’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets and NSP-Minnesota’s proportionate share of operating costs associated with these facilities is included in its consolidated statements of income.
NSP-Minnesota’s consolidated financial statements are presented in accordance with GAAP. All of NSP-Minnesota’s underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions. Certain amounts in the consolidated financial statements or notes have been reclassified for comparative purposes; however, such reclassifications did not affect net income, total assets, liabilities, equity or cash flows.
NSP-Minnesota has evaluated events occurring after Dec. 31, 2022 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.
Use of Estimates - NSP-Minnesota uses estimates based on the best information available in recording transactions and balances resulting from business operations.
Estimates are used for items such as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. Recorded estimates are revised when better information becomes available or actual amounts can be determined. Revisions can affect operating results.
Regulatory Accounting - NSP-Minnesota accounts for income and expense items in accordance with accounting guidance for regulated operations. Under this guidance:
•Certain costs, which would otherwise be charged to expense or other comprehensive income, are deferred as regulatory assets based on the expected ability to recover the costs in future rates.
•Certain credits, which would otherwise be reflected as income or other comprehensive income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred.
Estimates and assumptions for recovery of deferred costs and refund of deferred credits are based on specific ratemaking decisions, precedent or other information available. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process.
If changes in the regulatory environment occur, NSP-Minnesota may no longer be eligible to apply this accounting treatment and may be required to eliminate regulatory assets and liabilities. Such changes could have a material effect on NSP-Minnesota’s results of operations, financial condition and cash flows.
See Note 4 for further information.
Income Taxes - NSP-Minnesota accounts for income taxes using the asset and liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the consolidated financial statements. Income taxes are deferred for all temporary differences between pretax financial and taxable income and between the book and tax bases of assets and liabilities.
NSP-Minnesota uses rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the period that includes the enactment date.
The effects of tax rate changes that are attributable to the utility subsidiaries are generally subject to a normalization method of accounting. Therefore, the revaluation of most of the utility subsidiaries’ net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability, refundable to utility customers over the remaining life of the related assets. NSP-Minnesota anticipates that a tax rate increase would predominantly result in the establishment of a regulatory asset, subject to an evaluation of whether future recovery is expected.
Reversal of certain temporary differences are accounted for as current income tax expense due to the effects of past regulatory practices when deferred taxes were not required to be recorded due to the use of flow through accounting for ratemaking purposes.
Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize over the book depreciable lives of the related property. The requirement to defer and amortize these credits specifically applies to certain federal ITCs, as determined by tax regulations and NSP-Minnesota tax elections. For tax credits otherwise eligible to be recognized when earned, NSP-Minnesota considers the impact of rate regulation to determine if these credits and related adjustments should be deferred as regulatory assets or liabilities.
Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. Utility rate regulation has resulted in the recognition of regulatory assets and liabilities related to income taxes.
NSP-Minnesota measures and discloses uncertain tax positions that it has taken or expects to take in its income tax returns. A tax position is recognized in the consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position. Recognition of changes in uncertain tax positions are reflected as a component of income tax expense.
Interest and penalties related to income taxes are reported within other (expense) income or interest charges in the consolidated statements of income.
Xcel Energy Inc. and its subsidiaries, including NSP-Minnesota file consolidated federal income tax returns as well as consolidated or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to its subsidiaries based on separate company computations. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with consolidated state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries.
See Note 7 for further information.
Property, Plant and Equipment and Depreciation in Regulated Operations - Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred.
Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made.
For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary.
Depreciation expense is recorded using the straight-line method over the plant’s commission approved useful life. Actuarial life studies are performed and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Plant removal costs are typically recognized at the amounts recovered in rates as authorized by the applicable regulator. Accumulated removal costs are reflected in the consolidated balance sheet as a regulatory liability. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 4.0% for 2022, 3.7% for 2021 and 3.7% for 2020.
See Note 3 for further information.
AROs - NSP-Minnesota records AROs as a liability for the fair value of an ARO to be recognized in the period incurred (if it can be reasonably estimated), with the offsetting/associated costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion and the capitalized costs are typically depreciated over the useful life of the long-lived asset. Changes resulting from revisions to timing or amounts of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO.
See Note 10 for further information.
Nuclear Decommissioning - Nuclear decommissioning studies that estimate NSP-Minnesota’s costs of decommissioning its nuclear power plants are normally performed at least every 3 years and submitted to the state commissions for approval. Due to other regulatory activity, the next decommissioning study has been deferred one year until 2024.
NSP-Minnesota recovers regulator-approved decommissioning costs of its nuclear power plants over each facility’s expected service life, typically based on the triennial decommissioning studies. The studies consider estimated future costs of decommissioning and the market value of investments in trust funds and recommend annual funding amounts. Amounts collected in rates are deposited in the trust funds. For financial reporting purposes, NSP-Minnesota accounts for nuclear decommissioning as an ARO.
Restricted funds for the payment of future decommissioning expenditures for NSP-Minnesota’s nuclear facilities are included in nuclear decommissioning fund and other assets on the consolidated balance sheets.
See Notes 8 and 10 for further information.
Benefit Plans and Other Postretirement Benefits - NSP-Minnesota maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans requires management to make various assumptions and estimates.
Certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are deferred as regulatory assets and liabilities, rather than recorded as other comprehensive income, based on regulatory recovery mechanisms.
See Note 9 for further information.
Environmental Costs - Environmental costs are recorded when it is probable NSP-Minnesota is liable for remediation costs and the amount can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. For certain environmental costs related to facilities currently in use, such as for emission-control equipment, the cost is capitalized and depreciated over the life of the plant.
Estimated remediation costs are regularly adjusted as estimates are revised and remediation is performed. If other participating potentially responsible parties exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for NSP-Minnesota’s expected share of the cost.
Future costs of restoring sites are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.
See Note 10 for further information.
Revenue from Contracts with Customers - Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. NSP-Minnesota recognizes revenue that corresponds to the price of the energy delivered to the customer. The measurement of energy sales to customers is generally based on the reading of their meters, which occurs systematically throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recognized.
A separate financing component of collections from customers is not recognized as contract terms are short-term in nature. Revenues are net of any excise or sales taxes or fees.
NSP-Minnesota recognizes physical sales to customers (native load and wholesale) on a gross basis in electric revenues and cost of sales. Revenues and charges for short-term physical wholesale sales of excess energy transacted through RTOs are also recorded on a gross basis. Other revenues and charges settled/facilitated through an RTO are recorded on a net basis in cost of sales.
NSP-Minnesota has various rate-adjustment mechanisms that provide for the recovery of natural gas, electric fuel and purchased energy costs. Cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred.
When applicable, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets.
See Note 6 for further information.
Cash and Cash Equivalents - NSP-Minnesota considers investments in instruments with a remaining maturity of 3 months or less at the time of purchase to be cash equivalents.
Accounts Receivable and Allowance for Bad Debts - Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. NSP-Minnesota establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers.
As of Dec. 31, 2022 and 2021, the allowance for bad debts was $46 million and $45 million, respectively.
Inventory - Inventory is recorded at the lower of average cost or net realizable value and consisted of the following:
(Millions of Dollars) Dec. 31, 2022 Dec. 31, 2021
Inventories
Materials and supplies $ 200 $ 181
Fuel 103 81
Natural gas 81 47
Total inventories $ 384 $ 309
Fair Value Measurements - NSP-Minnesota presents cash equivalents, interest rate derivatives, commodity derivatives and nuclear decommissioning fund assets at estimated fair values in its consolidated financial statements.
For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used to estimate fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price, quoted prices for similar contracts or internally prepared valuation models may be used to determine fair value.
For the pension and postretirement plan assets and nuclear decommissioning fund, published trading data and pricing models, generally using the most observable inputs available, are utilized to determine fair value for each security.
See Notes 8 and 9 for further information.
Derivative Instruments - NSP-Minnesota uses derivative instruments in connection with its commodity trading activities, and to manage risk associated with changes in interest rates, and utility commodity prices, including forward contracts, futures, swaps and options. Any derivative instruments not qualifying for the normal purchases and normal sales exception are recorded on the consolidated balance sheets at fair value as derivative instruments. Classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship.
Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.
Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues.
Normal Purchases and Normal Sales - NSP-Minnesota enters into contracts for purchases and sales of commodities for use in its operations. At inception, contracts are evaluated to determine whether they contain a derivative, and if so, whether they may be exempted from derivative accounting if designated as normal purchases or normal sales.
See Note 8 for further information.
Commodity Trading Operations - All applicable gains and losses related to commodity trading activities are shown on a net basis in electric operating revenues in the consolidated statements of income.
Commodity trading activities are not associated with energy produced from NSP-Minnesota’s generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms.
See Note 8 for further information.
Other Utility Items
AFUDC - AFUDC represents the cost of capital used to finance utility construction activity and is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in NSP-Minnesota’s rate base.
Alternative Revenue - Certain rate rider mechanisms (including decoupling/sales true up and CIP/DSM programs) qualify as alternative revenue programs. These mechanisms arise from instances in which the regulator authorizes a future surcharge in response to past activities or completed events. When certain criteria are met, including expected collection within 24 months, revenue is recognized, which may include incentives and return on rate base items.
Billing amounts are revised periodically for differences between total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers.
See Note 6 for further information.
Conservation Programs - Costs incurred for CIP programs are deferred if it is probable future revenue will recover the incurred cost. Revenues recognized for incentive programs for the recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the year they are earned. Regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers.
Emissions Allowances - Emissions allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emissions allowances and any sales of these allowances are included in electric revenues.
Nuclear Refueling Outage Costs - NSP-Minnesota uses a deferral and amortization method for nuclear refueling costs. This method amortizes costs over the period between refueling outages consistent with rate recovery.
RECs - Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. An inventory accounting model is used to account for RECs.
Sales of RECs are recorded in electric revenues on a gross basis. The cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.
Cost of RECs that are utilized to support commodity trading activities are recorded in a similar manner as the associated commodities and are on a net basis in electric operating revenues in the consolidated statements of income.
2. Accounting Pronouncements
As of Dec. 31, 2022, there was no material impact from the recent adoption of new accounting pronouncements, nor expected material impact from recently issued accounting pronouncements yet to be adopted, on NSP-Minnesota’s consolidated financial statements.
3. Property, Plant and Equipment
Major classes of property, plant and equipment
(Millions of Dollars) Dec. 31, 2022 Dec. 31, 2021
Property, plant and equipment, net
Electric plant $ 20,114 $ 19,154
Natural gas plant 2,100 1,864
Common and other property 1,156 1,007
Plant to be retired (a)
646 719
CWIP 907 984
Total property, plant and equipment 24,923 23,728
Less accumulated depreciation (7,734) (7,606)
Nuclear fuel 3,183 3,081
Less accumulated amortization (2,894) (2,773)
Property, plant and equipment, net $ 17,478 $ 16,430
(a)Amounts include regulator-approved retirements of Sherco Units 1, 2 and 3 and A.S. King and are presented net of accumulated depreciation.
Joint Ownership of Generation and Transmission Facilities
Jointly owned assets as of Dec. 31, 2022:
(Millions of Dollars, Except Percent Owned) Plant in Service Accumulated Depreciation Percent Owned
Electric generation:
Sherco Unit 3 $ 623 $ 468 59 %
Sherco common facilities 180 115 80
Sherco substation 5 4 59
Electric transmission:
Grand Meadow 11 3 50
Huntley Wilmarth 49 1 50
CapX2020 818 124 51
Total (a)
$ 1,686 $ 715
(a)Projects additionally include $4 million in CWIP.
NSP-Minnesota’s share of operating expenses and construction expenditures is included in the applicable utility accounts. Respective owners are responsible for providing their own financing.
4. Regulatory Assets and Liabilities
Regulatory assets and liabilities are created for amounts that regulators may allow to be collected or may require to be paid back to customers in future electric and natural gas rates. NSP-Minnesota would be required to recognize the write-off of regulatory assets and liabilities in net income or other comprehensive income if changes in the utility industry no longer allow for the application of regulatory accounting guidance under GAAP.
Components of regulatory assets:
(Millions of Dollars) See Note(s) Remaining Amortization Period Dec. 31, 2022 Dec. 31, 2021 (a)
Regulatory Assets Current Noncurrent Current Noncurrent
Pension and retiree medical obligations 9 Various $ 12 $ 347 $ 24 $ 301
Recoverable deferred taxes on AFUDC Plant lives - 112 - 114
Excess deferred taxes - TCJA
7 Various 10 103 10 113
Deferred natural gas and electric energy/fuel costs One to five years
110 65 138 190
Net AROs (b)
1, 10 Various - 62 - (316)
Benson biomass PPA termination and asset purchase Six years
10 45 10 55
PI extended power uprate 12 years
4 42 4 46
Contract valuation adjustments (c)
1, 8 Term of related contract 16 28 18 34
Purchased power contracts costs Term of related contract 7 19 6 27
Conservation programs (d)
1 One to two years
6 19 7 22
Nuclear refueling outage costs 1 One to two years
30 12 37 16
Losses on reacquired debt Term of related debt 1 10 1 11
Sales true-up and revenue decoupling One year
53 - 33 56
Laurentian biomass PPA termination Less than one year
18 - 18 18
Renewable resources and environmental initiatives One year
50 - 170 3
Gas pipeline inspection and remediation costs One year
42 - 33 -
Other Various 15 30 18 28
Total regulatory assets $ 384 $ 894 $ 527 $ 718
(a)Prior period amounts have been restated to conform with current year presentation.
(b)Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.
(c)Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.
(d)Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.
Components of regulatory liabilities:
(Millions of Dollars) See Note(s) Remaining Amortization Period Dec. 31, 2022 Dec. 31, 2021 (a)
Regulatory Liabilities Current Noncurrent Current Noncurrent
Deferred income tax adjustments and TCJA refunds (b)
7 Various $ 6 $ 1,200 $ 9 $ 1,256
Plant removal costs 1, 10 Various - 693 - 613
Revenue decoupling Two years - 22 - -
Renewable resources and environmental initiatives Various 6 19 1 10
ITC deferrals 1 Various - 17 - 7
Formula rates One to two years
6 9 4 7
Contract valuation adjustments (c)
1, 8 Less than one year
56 - 29 -
Conservation programs Less than one year
42 - - -
DOE Settlement
N/A - - 14 -
Deferred natural gas and electric energy/fuel costs Less than one year
26 - 14 -
Other Various 49 23 46 34
Total regulatory liabilities (d)
$ 191 $ 1,983 $ 117 $ 1,927
(a)Prior period amounts have been restated to conform with current year presentation.
(b)Includes the revaluation of recoverable/regulated plant accumulated deferred income taxes and revaluation impact of non-plant accumulated deferred income taxes due to the TCJA.
(c)Includes the fair value of FTR instruments utilized/intended to offset the impacts of transmission system congestion.
(d)Revenue subject to refund of $67 million and $15 million for 2022 and 2021, respectively, is included in other current liabilities.
NSP-Minnesota’s regulatory assets not earning a return include the unfunded portion of pension and retiree medical obligations and net AROs (i.e. deferrals for which cash has not been disbursed). In addition, regulatory assets included $369 million and $691 million, respectively, of past expenditures not earning a return. Amounts are predominately related to purchased natural gas and electric energy costs (including certain costs related to Winter Storm Uri), sales true-up and revenue decoupling, various renewable resources/environmental initiatives and certain prepaid pension amounts.
5. Borrowings and Other Financing Instruments
Short-Term Borrowings
NSP-Minnesota meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility and the money pool.
Money Pool - Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc.
Money pool borrowings:
(Millions of Dollars, Except Interest Rates) Three Months Ended Dec. 31, 2022 Year Ended Dec. 31
2022 2021 2020
Borrowing limit $ 250 $ 250 $ 250 $ 250
Amount outstanding at period end - - - -
Average amount outstanding - - 6 3
Maximum amount outstanding 4 4 236 116
Weighted average interest rate, computed on a daily basis 3.87 % 3.87 % 0.07 % 1.53 %
Weighted average interest rate at period end N/A N/A N/A N/A
Commercial Paper - Commercial paper outstanding:
(Millions of Dollars, Except Interest Rates) Three Months Ended Dec. 31, 2022 Year Ended Dec. 31
2022 2021 2020
Borrowing limit $ 700 $ 700 $ 500 $ 500
Amount outstanding at period end 207 207 - 179
Average amount outstanding 81 21 26 10
Maximum amount outstanding 290 290 317 179
Weighted average interest rate, computed on a daily basis 4.32 % 4.14 % 0.18 % 1.25 %
Weighted average interest rate at end of period 4.64 4.64 N/A 0.18
Letters of Credit - NSP-Minnesota uses letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2022 and 2021, there were $15 million and $9 million of letters of credit outstanding under the credit facility, respectively. The contract amounts of these letters of credit approximate their fair value and are subject to fees.
Credit Facility - In order to use commercial paper programs to fulfill short-term funding needs, NSP-Minnesota must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper exceeding available capacity under these credit facilities.
The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.
Features of NSP-Minnesota’s credit facility:
Debt-to-Total Capitalization Ratio (a)
Amount Facility May Be Increased (millions of dollars) Additional Periods for Which a One-Year Extension May Be Requested (b)
2022 2021
48 % 47 % $ 150 2
(a) The credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%.
(b) All extension requests are subject to majority bank group approval.
The credit facility has a cross-default provision that NSP-Minnesota would be in default on its borrowings under the facility if it or any of its subsidiaries whose total assets exceed 15% of NSP-Minnesota’s consolidated total assets, default on indebtedness in an aggregate principal amount exceeding $75 million.
If NSP-Minnesota does not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2022, NSP-Minnesota was in compliance with all financial covenants on its debt agreements.
NSP-Minnesota had the following committed credit facility available as of Dec. 31, 2022 (in millions of dollars):
Credit Facility (a)
Drawn (b)
Available
$ 700 $ 222 $ 478
(a)This credit facility matures in September 2027.
(b)Includes outstanding commercial paper and letters of credit.
All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. NSP-Minnesota had no direct advances on the facility outstanding at Dec. 31, 2022 and 2021.
Bilateral Credit Agreement - In April 2022, NSP-Minnesota’s uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit.
As of Dec. 31, 2022, NSP-Minnesota had $54 million outstanding letters of credit under the $75 million Bilateral Credit Agreement.
Long-Term Borrowings and Other Financing Instruments
Generally, the property of NSP-Minnesota is subject to the lien of its first mortgage indenture for the benefit of bondholders. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses for refinanced debt are deferred and amortized over the life of the new issuance.
Long term debt obligations for NSP-Minnesota as of Dec. 31 (in millions of dollars):
Financing Instrument Interest Rate Maturity Date 2022 2021
First mortgage bonds 2.15 % Aug. 15, 2022 $ - $ 300
First mortgage bonds 2.60 May 15, 2023 400 400
First mortgage bonds 7.125 July 1, 2025 250 250
First mortgage bonds 6.50 March 1, 2028 150 150
First mortgage bonds (a)
2.25 April 1, 2031 425 425
First mortgage bonds 5.25 July 15, 2035 250 250
First mortgage bonds 6.25 June 1, 2036 400 400
First mortgage bonds 6.20 July 1, 2037 350 350
First mortgage bonds 5.35 Nov. 1, 2039 300 300
First mortgage bonds 4.85 Aug. 15, 2040 250 250
First mortgage bonds 3.40 Aug. 15, 2042 500 500
First mortgage bonds 4.125 May 15, 2044 300 300
First mortgage bonds 4.00 Aug. 15, 2045 300 300
First mortgage bonds 3.60 May 15, 2046 350 350
First mortgage bonds 3.60 Sept. 15, 2047 600 600
First mortgage bonds 2.90 March 1, 2050 600 600
First mortgage bonds 2.60 June 1, 2051 700 700
First mortgage bonds (a)
3.20 April 1, 2052 425 425
First mortgage bonds (b)
4.50 June 1,2052 500 -
Other long-term debt 3 3
Unamortized discount (45) (44)
Unamortized debt issuance cost (66) (62)
Current maturities (400) (300)
Total long-term debt $ 6,542 $ 6,447
(a)2021 financing.
(b)2022 financing.
Maturities of long-term debt are as follows:
(Millions of Dollars)
2023 $ 400
2024 -
2025 250
2026 -
2027 -
Deferred Financing Costs - Deferred financing costs of approximately $66 million and $62 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt at Dec. 31, 2022 and 2021, respectively.
Dividend Restrictions - NSP-Minnesota’s dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital accounts. Dividend payments are solely to be paid from retained earnings.
NSP-Minnesota’s state regulatory commissions additionally impose dividend limitations, which are more restrictive than those imposed by the FERC.
Requirements and actuals as of Dec. 31, 2022:
Equity to Total Capitalization Ratio
Required Range Equity to Total Capitalization Ratio Actual
Low High 2022
47.2 % 57.6 % 52.3 %
Unrestricted Retained Earnings Total Capitalization Limit on Total Capitalization
$ 1,446 million $ 14,984 million $ 16,140 million
6. Revenues
Revenue is classified by the type of goods/services rendered and market/customer type. NSP-Minnesota’s operating revenues consisted of the following:
Year Ended Dec. 31, 2022
(Millions of Dollars) Electric Natural Gas All Other Total
Major revenue types
Revenue from contracts with customers:
Residential $ 1,463 $ 510 $ 38 $ 2,011
C&I 2,376 433 - 2,809
Other 38 - 7 45
Total retail 3,877 943 45 4,865
Wholesale 668 - - 668
Transmission 287 - - 287
Interchange 514 - - 514
Other 15 19 - 34
Total revenue from contracts with customers 5,361 962 45 6,368
Alternative revenue and other 256 60 - 316
Total revenues $ 5,617 $ 1,022 $ 45 $ 6,684
Year Ended Dec. 31, 2021
(Millions of Dollars) Electric Natural Gas All Other Total
Major revenue types
Revenue from contracts with customers:
Residential $ 1,374 $ 315 $ 33 $ 1,722
C&I 2,107 246 - 2,353
Other 33 - 6 39
Total retail 3,514 561 39 4,114
Wholesale 442 - - 442
Transmission 242 - - 242
Interchange 501 - - 501
Other 7 14 - 21
Total revenue from contracts with customers 4,706 575 39 5,320
Alternative revenue and other 388 48 - 436
Total revenues $ 5,094 $ 623 $ 39 $ 5,756
Year Ended Dec. 31, 2020
(Millions of Dollars) Electric Natural Gas All Other Total
Major revenue types
Revenue from contracts with customers:
Residential $ 1,375 $ 261 $ 31 $ 1,667
C&I 1,935 189 - 2,124
Other 33 - 6 39
Total retail 3,343 450 37 3,830
Wholesale 202 - - 202
Transmission 238 - - 238
Interchange 440 - - 440
Other 15 7 - 22
Total revenue from contracts with customers 4,238 457 37 4,732
Alternative revenue and other 333 36 - 369
Total revenues $ 4,571 $ 493 $ 37 $ 5,101
7. Income Taxes
Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense.
Effective income tax rate for years ended Dec. 31:
2022 2021 (c)
2020 (c)
Federal statutory rate 21.0 % 21.0 % 21.0 %
State income tax on pretax income, net of federal tax effect 7.0 7.0 7.0
Increases (decreases) in tax from:
Wind PTCs (a)
(39.6) (27.8) (19.3)
Plant regulatory differences (b)
(6.7) (8.1) (7.2)
Other tax credits, net NOL & tax credit allowances (1.3) (1.4) (1.2)
NOL Carryback - - (2.1)
Other, net (0.3) 0.7 0.8
Effective income tax rate (19.9) % (8.6) % (1.0) %
(a)Wind PTCs are credited to customers (reduction to revenue) and do not materially impact net income.
(b)Regulatory differences for income tax primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit of excess deferred taxes are offset by corresponding revenue reductions.
(c)Prior period amounts have been restated to conform with current year presentation.
Components of income tax expense for years ended Dec. 31:
(Millions of Dollars) 2022 2021 2020
Current federal tax expense (benefit) $ 70 $ (10) $ 41
Current state tax expense (benefit) 26 (1) 12
Current change in unrecognized tax expense 8 1 9
Deferred federal tax benefit (237) (87) (102)
Deferred state tax expense 23 49 38
Deferred change in unrecognized tax expense (benefit) - 2 (3)
Deferred ITCs (2) (2) (1)
Total income tax benefit $ (112) $ (48) $ (6)
Components of deferred income tax expense as of Dec. 31:
(Millions of Dollars) 2022 2021 2020
Deferred tax (benefit) expense excluding items below $ (283) $ 109 61
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities 70 (145) (127)
Tax expense allocated to other comprehensive income, and other (1) - (1)
Deferred tax benefit $ (214) $ (36) $ (67)
Components of the net deferred tax liability as of Dec. 31:
(Millions of Dollars) 2022 2021 (a)
Deferred tax liabilities:
Differences between book and tax bases of property $ 2,708 $ 2,679
Regulatory assets 189 214
Operating lease assets 98 123
Deferred fuel costs 49 92
Pension expense 68 73
Other 10 13
Total deferred tax liabilities $ 3,122 $ 3,194
Deferred tax assets:
Tax credit carryforward $ 977 $ 782
Regulatory Liabilities 325 279
Operating lease liabilities 98 123
NOL and tax credit valuation allowances (58) (64)
Other employee benefits 27 32
NOL carryforward 15 43
Deferred ITCs 5 5
Rate refund 28 11
Other 39 34
Total deferred tax assets $ 1,456 $ 1,245
Net deferred tax liability $ 1,666 $ 1,949
(a)Prior periods have been reclassified to conform to current year presentation.
Other Income Tax Matters - NOL amounts represent the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows:
(Millions of Dollars) 2022 2021
Federal NOL carryforward $ 2 $ 77
Federal tax credit carryforwards 909 704
State NOL carryforwards 184 344
Valuation allowances for state NOL carryforwards (1) (1)
State tax credit carryforwards, net of federal detriment (a)
68 78
Valuation allowances for state credit carryforwards, net of federal benefit (b)
(58) (64)
(a)State tax credit carryforwards are net of federal detriment of $18 million and $21 million as of Dec. 31, 2022 and 2021, respectively.
(b)Valuation allowances for state tax credit carryforwards were net of federal benefit of $15 million and $17 million as of Dec. 31, 2022 and 2021, respectively.
Federal carryforward periods expire starting 2032 and state carryforward periods expire starting 2022.
Federal Tax Loss Carryback Claims - In 2020, Xcel Energy identified certain expenses related to tax years 2009 - 2011 that qualify for an extended carryback claim. As a result, a tax benefit of approximately $13 million was recognized in 2020.
Unrecognized Tax Benefits
Federal Audit - NSP-Minnesota is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. Statute of limitations applicable to Xcel Energy’s consolidated federal income tax returns expire as follows:
Tax Year(s) Expiration
2014 - 2016 March 2024
2019 October 2023
Additionally, the statute of limitations related to the federal tax credit carryforwards will remain open until those credits are utilized in subsequent returns. Further, the statute of limitations related to the additional federal tax loss carryback claim filed in 2020 has been extended. Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is unknown.
State Audits - NSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2022, NSP-Minnesota’s earliest open tax years subject to examination by state taxing authorities under applicable statutes of limitations are as follows:
State Tax Year(s) Expiration
Minnesota 2014-2016 September 2024
Minnesota 2018 June 2023
In 2020, Minnesota began an audit of tax years 2015-2018. In 2022, the state of Minnesota issued its audit report without any material adjustments.
Unrecognized Tax Benefits - Unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which deductibility is highly certain, but for which there is uncertainty about the timing. A change in the timing of deductibility would not affect the ETR but would accelerate the payment to the taxing authority.
Unrecognized tax benefits - permanent vs temporary:
(Millions of Dollars) Dec. 31, 2022 Dec. 31, 2021
Unrecognized tax benefit - Permanent tax positions $ 31 $ 23
Unrecognized tax benefit - Temporary tax positions 3 3
Total unrecognized tax benefit $ 34 $ 26
Changes in unrecognized tax benefits:
(Millions of Dollars) 2022 2021 2020
Balance at Jan. 1 $ 26 $ 24 $ 20
Additions based on tax positions related to the current year 2 2 2
Reductions based on tax positions related to the current year - - -
Additions for tax positions of prior years 6 - 16
Reductions for tax positions of prior years - - (14)
Balance at Dec. 31 $ 34 $ 26 $ 24
Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards:
(Millions of Dollars) Dec. 31, 2022 Dec. 31, 2021
NOL and tax credit carryforwards $ (13) $ (13)
As the IRS progresses its review of the tax loss carryback claims and as state audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $22 million in the next 12 months.
Payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards.
Interest payable related to unrecognized tax benefits:
(Millions of Dollars) 2022 2021 2020
Payable for interest related to unrecognized tax benefits at Jan. 1 $ (2) $ (2) $ (2)
Interest expense related to unrecognized tax benefits (1) - -
Payable for interest related to unrecognized tax benefits at Dec. 31 $ (3) $ (2) $ (2)
No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2022, 2021 or 2020.
8. Fair Value of Financial Assets and Liabilities
Fair Value Measurements
Accounting guidance for fair value measurements and disclosures provides a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value.
•Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are actively traded instruments with observable actual trading prices.
•Level 2 - Pricing inputs are other than actual trading prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs.
•Level 3 - Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 include those valued with models requiring significant judgment or estimation.
Specific valuation methods include:
Investments in equity securities and other funds - Equity securities are valued using quoted prices in active markets. The fair values for commingled funds are measured using NAVs. The investments in commingled funds may be redeemed for NAV with proper notice. Private equity commingled funds require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate commingled funds may be redeemed with proper notice, however, withdrawals may be delayed or discounted as a result of fund illiquidity.
Investments in debt securities - Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities.
Interest rate derivatives - Fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.
Commodity derivatives - Methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When contracts relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges, the significance of the use of less observable inputs on a valuation is evaluated and may result in Level 3 classification.
Electric commodity derivatives held by NSP-Minnesota include transmission congestion instruments, generally referred to as FTRs. FTRs purchased from an RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path.
The values of these instruments are derived from, and designed to offset, the costs of transmission congestion. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of these instruments. FTRs are recognized at fair value and adjusted each period prior to settlement. Given the limited observability of certain variables underlying the reported auction values of FTRs, these fair value measurements have been assigned a Level 3 classification.
Net congestion costs, including the impact of FTR settlements are shared through fuel and purchased energy cost recovery mechanisms. As such, the fair value of the unsettled instruments (i.e., derivative asset or liability) is offset/deferred as a regulatory asset or liability.
Non-Derivative Fair Value Measurements
Nuclear Decommissioning Fund
The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning these facilities. The fund contains cash equivalents, debt securities, equity securities and other investments. NSP-Minnesota uses the MPUC approved asset allocation for the investment targets by asset class for the qualified trust.
NSP-Minnesota recognizes the costs of funding the decommissioning over the lives of the nuclear plants, assuming rate recovery of all costs. Realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund are deferred as a component of the regulatory asset.
Unrealized gains for the nuclear decommissioning fund were $1 billion and $1.3 billion as of Dec. 31, 2022 and 2021, respectively, and unrealized losses were $90 million and $7 million as of Dec. 31, 2022 and 2021, respectively.
Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund:
Dec. 31, 2022
Fair Value
(Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total
Nuclear decommissioning fund (a)
Cash equivalents $ 29 $ 29 $ - $ - $ - $ 29
Commingled funds 803 - - - 1,178 1,178
Debt securities 738 - 669 6 - 675
Equity securities 406 999 1 - - 1,000
Total $ 1,976 $ 1,028 $ 670 $ 6 $ 1,178 $ 2,882
(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $48 million of rabbi trust assets and other miscellaneous investments.
Dec. 31, 2021
Fair Value
(Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total
Nuclear decommissioning fund (a)
Cash equivalents $ 64 $ 64 $ - $ - $ - $ 64
Commingled funds 856 - - - 1,294 1,294
Debt securities 631 - 666 9 - 675
Equity securities 411 1,222 1 - - 1,223
Total $ 1,962 $ 1,286 $ 667 $ 9 $ 1,294 $ 3,256
(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $52 million of rabbi trust assets and other miscellaneous investments.
For the years ended Dec. 31, 2022 and 2021, there were immaterial Level 3 nuclear decommissioning fund investments or transfer of amounts between levels.
Contractual maturity dates of debt securities in the nuclear decommissioning fund as of Dec. 31, 2022:
Final Contractual Maturity
(Millions of Dollars) Due in 1 Year or Less Due in 1 to 5 Years Due in 5 to 10 Years Due after 10 Years Total
Debt securities $ 6 $ 204 $ 250 $ 216 $ 676
Rabbi Trusts
NSP-Minnesota has established a rabbi trust to provide partial funding for future distributions of its deferred compensation plan. The fair value of assets held in the rabbi trusts were $12 million and $13 million at Dec. 31, 2022 and 2021, respectively, comprised of cash equivalents and mutual funds (level 1 valuation methods). Amounts are reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.
Derivative Activities and Fair Value Measurements
NSP-Minnesota enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates and utility commodity prices.
Interest Rate Derivatives - NSP-Minnesota enters into contracts that effectively fix the interest rate on a specified principal amount of a hypothetical future debt issuance. These financial swaps net settle based on changes in a specified benchmark interest rate, acting as a hedge of changes in market interest rates that will impact specified anticipated debt issuances. These derivative instruments are designated as cash flow hedges for accounting purposes, with changes in fair value prior to occurrence of the hedged transactions recorded as other comprehensive income.
As of Dec. 31, 2022, accumulated other comprehensive loss related to interest rate derivatives included $1 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings. As of Dec. 31, 2022, NSP-Minnesota had no unsettled interest rate derivatives.
For the financial impact of qualifying interest rate cash flow hedges on NSP-Minnesota’s accumulated other comprehensive loss included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income, see Note 11.
Wholesale and Commodity Trading - NSP-Minnesota conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. NSP-Minnesota is allowed to conduct these activities within guidelines and limitations as approved by its risk management committee, comprised of management personnel not directly involved in the activities governed by this policy.
Derivative instruments entered into for trading purposes are presented in the consolidated statements of income as electric revenues, net of any sharing with customers. These activities are not intended to mitigate commodity price risk associated with regulated electric and natural gas operations. Sharing of these margins is determined through state regulatory proceedings as well as the operation of the FERC-approved joint operating agreement.
Commodity Derivatives - NSP-Minnesota enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale and FTRs.
The most significant derivative positions outstanding at December 31, 2022 and 2021 for this purpose relate to FTR instruments administered by MISO. These instruments are intended to offset the impacts of transmission system congestion. Higher congestion costs in recent years have led to an increase in the fair value of FTRs. Settlements of FTRs are shared with electric customers through fuel and purchased energy cost-recovery mechanisms.
When NSP-Minnesota enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, the instruments are not typically designated as qualifying hedging transactions. The classification of unrealized losses or gains on these instruments as a regulatory asset or liability, if applicable, is based on approved regulatory recovery mechanisms. As of Dec. 31, 2022, NSP-Minnesota had no commodity contracts designated as cash flow hedges.
Gross notional amounts of commodity forwards, options and FTRs:
(Amounts in Millions) (a)(b)
Dec. 31, 2022 Dec. 31, 2021
MWh of electricity 44 57
MMBtu of natural gas 88 85
(a)Not reflective of net positions in the underlying commodities.
(b)Notional amounts for options included on a gross basis, but are weighted for the probability of exercise.
Consideration of Credit Risk and Concentrations - NSP-Minnesota continuously monitors the creditworthiness of counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented on the consolidated balance sheets. NSP-Minnesota’s most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities.
As of Dec. 31, 2022, six of NSP-Minnesota’s ten most significant counterparties for these activities, comprising $38 million or 34% of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services or Fitch Ratings.
Three of the ten most significant counterparties, comprising $28 million or 25% of this credit exposure, were not rated by these external ratings agencies, but based on NSP-Minnesota’s internal analysis, had credit quality consistent with investment grade. One of these significant counterparties, comprising $47 million or 41% of this credit exposure, had credit quality less than investment grade, based on internal analysis. Four of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities.
Credit Related Contingent Features - Contract provisions for derivative instruments that the utility subsidiaries enter, including those accounted for as normal purchase and normal sale contracts and therefore not reflected on the consolidated balance sheets, may require the posting of collateral or settlement of the contracts for various reasons, including if the applicable utility subsidiary’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies. As of Dec. 31, 2022 and 2021, there were $4 million and $3 million, respectively, of derivative liabilities with such underlying contract provisions, respectively.
Certain contracts also contain cross default provisions that may require the posting of collateral or settlement of the contracts if there was a failure under other financing arrangements related to payment terms or other covenants.
As of Dec. 31, 2022 and 2021, there were approximately $76 million and $48 million of derivative liabilities with such underlying contract provisions, respectively.
Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that a given utility subsidiary’s ability to fulfill its contractual obligations is reasonably expected to be impaired. Xcel Energy had no collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 2022 and 2021.
Recurring Derivative Fair Value Measurements
Impact of derivative activity:
Pre-Tax Fair Value
Gains (Losses) Recognized
During the Period in:
(Millions of Dollars) Accumulated Other Comprehensive Loss Regulatory (Assets) and Liabilities
Year Ended Dec. 31, 2022
Other derivative instruments
Electric commodity $ - $ (7)
Natural gas commodity - -
Total $ - $ (7)
Year Ended Dec. 31, 2021
Other derivative instruments
Electric commodity $ - $ 3
Natural gas commodity - (3)
Total $ - $ -
Year Ended Dec. 31, 2020
Other derivative instruments
Electric commodity $ - $ 2
Natural gas commodity - (2)
Total $ - $ -
Pre-Tax (Gains) Losses Reclassified into Income During the Period from: Pre-Tax Gains (Losses) Recognized During the Period in Income
(Millions of Dollars) Accumulated Other Comprehensive Loss Regulatory
Assets and (Liabilities)
Year Ended Dec. 31, 2022
Derivatives designated as cash flow hedges
Interest rate $ 1 (a)
$ - $ -
Total $ 1 $ - $ -
Other derivative instruments
Commodity trading $ - $ - $ 17 (b)
Electric commodity - 1 (c)
-
Natural gas commodity - 2 (d)
(8) (d)(e)
Total $ - $ 3 $ 9
Year Ended Dec. 31, 2021
Derivatives designated as cash flow hedges
Interest rate $ 2 (a)
$ - $ -
Total $ 2 $ - $ -
Other derivative instruments
Commodity trading $ - $ - $ 51 (b)
Electric commodity - (3) (c)
-
Natural gas commodity - 1 (d)
(6) (d)(e)
Total $ - $ (2) $ 45
Year Ended Dec. 31, 2020
Derivatives designated as cash flow hedges
Interest rate $ 1 (a)
$ - $ -
Total $ 1 $ - $ -
Other derivative instruments
Commodity trading $ - $ - $ (5) (b)
Electric commodity $ - $ (3) (c)
$ -
Natural gas commodity - 2 (d)
(4) (d)(e)
Total $ - $ (1) $ (9)
(a)Recorded to interest charges.
(b)Recorded to electric revenues. Presented amounts do not reflect non-derivative transactions or margin sharing with customers.
(c)Recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms and reclassified out of income as regulatory assets or liabilities, as appropriate. FTR settlements are shared with customers and do not have a material impact on net income. Presented amounts reflect changes in fair value between auction and settlement dates, but exclude the original auction fair value.
(d)Recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate.
(e)Relates primarily to option premium amortization.
NSP-Minnesota had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2022, 2021 and 2020.
Derivative assets and liabilities measured at fair value on a recurring basis were as follows:
Dec. 31, 2022 Dec. 31, 2021
Fair Value Fair Value Total Netting (a)
Total Fair Value Fair Value Total Netting (a)
Total
(Millions of Dollars) Level 1 Level 2 Level 3 Level 1 Level 2 Level 3
Current derivative assets
Other derivative instruments:
Commodity trading $ 15 $ 38 $ 33 $ 86 $ (58) $ 28 $ 9 $ 40 $ 22 $ 71 $ (53) $ 18
Electric commodity - - 58 58 (2) 56 - - 30 30 (1) 29
Natural gas commodity - 5 - 5 - 5 - 6 - 6 - 6
Total current derivative assets $ 15 $ 43 $ 91 $ 149 $ (60) $ 89 $ 9 $ 46 $ 52 $ 107 $ (54) $ 53
Noncurrent derivative assets
Other derivative instruments:
Commodity trading $ 21 $ 40 $ 66 $ 127 $ (59) $ 68 $ 6 $ 34 $ 35 $ 75 $ (42) $ 33
Total noncurrent derivative assets $ 21 $ 40 $ 66 $ 127 $ (59) $ 68 $ 6 $ 34 $ 35 $ 75 $ (42) $ 33
Dec. 31, 2022 Dec. 31, 2021
Fair Value Fair Value Total Netting (a)
Total Fair Value Fair Value Total Netting (a)
Total
(Millions of Dollars) Level 1 Level 2 Level 3 Level 1 Level 2 Level 3
Current derivative liabilities
Other derivative instruments:
Commodity trading $ 23 $ 60 $ 6 $ 89 $ (63) $ 26 $ 13 $ 58 $ 4 $ 75 $ (58) $ 17
Electric commodity - - 2 2 (2) - - - 1 1 (1) -
Natural gas commodity - 2 - 2 - 2 - 4 - 4 - 4
Total current derivative liabilities $ 23 $ 62 $ 8 $ 93 $ (65) 28 $ 13 $ 62 $ 5 $ 80 $ (59) 21
PPAs (b)
14 14
Current derivative instruments $ 42 $ 35
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading $ 37 $ 55 $ 42 $ 134 $ (60) $ 74 $ 15 $ 48 $ 26 $ 89 $ (53) $ 36
Total noncurrent derivative liabilities $ 37 $ 55 $ 42 $ 134 $ (60) 74 $ 15 $ 48 $ 26 $ 89 $ (53) 36
PPAs (b)
28 35
Noncurrent derivative instruments $ 102 $ 71
(a)NSP-Minnesota nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement. At Dec. 31, 2022 and 2021, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2022 and 2021, derivative assets and liabilities include rights to reclaim cash collateral of $6 million and $16 million, respectively. Counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
(b)NSP-Minnesota currently applies the normal purchase exception to qualifying PPAs. Balance relates to specific contracts that were previously recognized at fair value prior to applying the normal purchase exception, and are being amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
Changes in Level 3 commodity derivatives:
Year Ended Dec. 31
(Millions of Dollars) 2022 2021 2020
Balance at Jan. 1 $ 56 $ (11) $ 5
Purchases (a)
157 54 28
Settlements (a)
(195) (82) (49)
Net transactions recorded during the period:
Gains (losses) recognized in earnings (b)
91 72 (8)
Net gains (losses) recognized as regulatory assets and liabilities (a)
(2) 23 13
Balance at Dec. 31 $ 107 $ 56 $ (11)
(a)Relates primarily to FTR instruments administered by MISO.
(b)Relates to commodity trading and is subject to substantial offsetting losses and gains on derivative instruments categorized as levels 1 and 2 in the income statement. See above tables for the income statement impact of derivative activity, including commodity trading gains and losses.
Fair Value of Long-Term Debt
As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value:
2022 2021
(Millions of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value
Long-term debt, including current portion $ 6,942 $ 5,995 $ 6,747 $ 7,761
Fair value of NSP-Minnesota’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. Fair value estimates are based on information available to management as of Dec. 31, 2022 and 2021, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.
9. Benefit Plans and Other Postretirement Benefits
Pension and Postretirement Health Care Benefits
Xcel Energy, which includes NSP-Minnesota, has several noncontributory, qualified, defined benefit pension plans that cover almost all employees. All newly hired or rehired employees participate under the Cash Balance formula, which is based on pay credits using a percentage of annual eligible pay and annual interest credits. The average annual interest crediting rates for these plans was 4.86, 1.96 and 1.78% in 2022, 2021, and 2020, respectively. Some employees may participate under legacy formulas such as the traditional final average pay or pension equity. Xcel Energy’s and NSP-Minnesota’s policy is to fully fund into an external trust the actuarially determined pension costs subject to the limitations of applicable employee benefit and tax laws.
In addition to the qualified pension plans, Xcel Energy maintains a SERP and a nonqualified pension plan. The SERP is maintained for certain executives who participated in the plan in 2008, when the SERP was closed to new participants. The nonqualified pension plan provides benefits for compensation that is in excess of the limits applicable to the qualified pension plans, with distributions funded by Xcel Energy’s consolidated operating cash flows. Obligations of the SERP and nonqualified plan as of Dec. 31, 2022 and 2021 were $11 million and $43 million, respectively, of which $2 million and $3 million was attributable to NSP-Minnesota in 2022 and 2021, respectively. Xcel Energy recognized net benefit cost for the SERP and nonqualified plans of $17 million in 2022 and $4 million in 2021, respectively, of which immaterial amounts were attributable to NSPM.
Investment-return assumption considers the expected long-term performance for each of the asset classes in its pension and postretirement health care portfolio. Xcel Energy considers the historical returns achieved by its asset portfolios over long time periods, as well as the long-term projected return levels from investment experts. Xcel Energy and NSP-Minnesota continually review their pension assumptions.
Pension cost determination assumes a forecasted mix of investment types over the long-term.
•Investment returns in 2022 were below the assumed level of 6.60%.
•Investment returns in 2021 were above the assumed level of 6.60%.
•Investment returns in 2020 were above the assumed level of 7.10%.
•In 2023, NSP-Minnesota’s expected investment-return assumption is 7.25%.
Pension plan and postretirement benefit assets are invested in a portfolio according to Xcel Energy’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the asset allocation given the long-term risk, return, correlation and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by the assets in any year.
Xcel Energy’s ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations consider many factors and generally result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios.
Plan Assets
For each of the fair value hierarchy levels, NSP-Minnesota’s pension plan assets measured at fair value:
Dec. 31, 2022 (a)
Dec. 31, 2021 (a)
(Millions of Dollars) Level 1 Level 2 Level 3 Measured at NAV Total Level 1 Level 2 Level 3 Measured at NAV Total
Cash equivalents $ 26 $ - $ - $ - $ 26 $ 31 $ - $ - $ - $ 31
Commingled funds 201 - - 201 402 304 - - 274 578
Debt securities - 129 1 - 130 - 219 1 - 220
Equity securities 11 - - - 11 16 - - - 16
Other - 1 - - 1 - 1 - 7 8
Total $ 238 $ 130 $ 1 $ 201 $ 570 $ 351 $ 220 $ 1 $ 281 $ 853
(a)See Note 8 for further information regarding fair value measurement inputs and methods.
For each of the fair value hierarchy levels, NSP-Minnesota’s postretirement benefit plan assets that were measured at fair value:
Dec. 31, 2022 (a)
Dec. 31, 2021 (a)
(Millions of Dollars) Level 1 Level 2 Level 3 Measured at NAV Total Level 1 Level 2 Level 3 Measured at NAV Total
Insurance contracts - 1 - - 1 - - - - -
Commingled funds $ 1 $ - $ - $ 1 $ 2 $ - $ - $ - $ 1 $ 1
Debt securities - 2 - - 2 - 2 - - 2
Total $ 1 $ 3 $ - $ 1 $ 5 $ - $ 2 $ - $ 1 $ 3
(a)See Note 8 for further information on fair value measurement inputs and methods.
No assets were transferred in or out of Level 3 for 2022 or 2021.
Funded Status - Benefit obligations for both pension and postretirement plans decreased from Dec. 31, 2021 to Dec. 31, 2022, due primarily to benefit payments and increases in discount rates used in actuarial valuations. Comparisons of the actuarially computed benefit obligation, changes in plan assets and funded status of the pension and postretirement health care plans for NSP-Minnesota are as follows:
Pension Benefits Postretirement Benefits
(Millions of Dollars) 2022 2021 2022 2021
Change in Benefit Obligation:
Obligation at Jan. 1 $ 877 $ 989 $ 64 $ 73
Service cost 27 30 - -
Interest cost 25 25 2 2
Plan amendments 1 1 - -
Actuarial gain (139) (28) (13) (5)
Benefit payments (134) (140) (5) (6)
Obligation at Dec. 31 $ 657 $ 877 $ 48 $ 64
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1 $ 853 $ 897 $ 3 $ 2
Actual return on plan assets (154) 62 - -
Employer contributions 5 34 7 7
Benefit payments (134) (140) (5) (6)
Fair value of plan assets at Dec. 31 $ 570 $ 853 $ 5 $ 3
Funded status of plans at Dec. 31 $ (87) $ (24) $ (43) $ (61)
Amounts recognized in the Consolidated Balance Sheet at Dec. 31:
Current liabilities $ - $ - $ (1) $ (3)
Noncurrent liabilities (87) (24) (42) (58)
Net amounts recognized $ (87) $ (24) $ (43) $ (61)
Pension Benefits Postretirement Benefits
Significant Assumptions Used to Measure Benefit Obligations: 2022 2021 2022 2021
Discount rate for year-end valuation 5.80 % 3.08 % 5.80 % 3.09 %
Expected average long-term increase in compensation level 4.25 3.75 N/A N/A
Mortality table PRI-2012 PRI-2012 PRI-2012 PRI-2012
Health care costs trend rate - initial: Pre-65 N/A N/A 6.50 % 5.30 %
Health care costs trend rate - initial: Post-65 N/A N/A 5.50 % 4.90 %
Ultimate trend assumption - initial: Pre-65 N/A N/A 4.50 % 4.50 %
Ultimate trend assumption - initial: Post-65 N/A N/A 4.50 % 4.50 %
Years until ultimate trend is reached N/A N/A 7 4
Accumulated benefit obligation for the pension plan was $600 million and $811 million as of Dec. 31, 2022 and 2021, respectively.
Net Periodic Benefit Cost (Credit) - Net periodic benefit cost (credit), other than the service cost component, is included in other income (expense) in the consolidated statements of income.
Components of net periodic benefit cost (credit) and amounts recognized in other comprehensive income and regulatory assets and liabilities:
Pension Benefits Postretirement Benefits
(Millions of Dollars) 2022 2021 2020 2022 2021 2020
Service cost $ 27 $ 30 $ 27 $ - $ - $ -
Interest cost 25 25 31 2 2 2
Expected return on plan assets (48) (52) (55) - - -
Amortization of prior service cost - - - (3) (3) (3)
Amortization of net loss 24 34 33 1 2 1
Settlement charge (a)
38 35 - - - -
Net periodic pension cost 66 72 36 - 1 -
Effects of regulation (32) (44) (4) - - -
Net benefit cost recognized for financial reporting $ 34 $ 28 $ 32 $ - $ 1 $ -
Significant Assumptions Used to Measure Costs:
Discount rate 3.08 % 2.71 % 3.49 % 3.09 % 2.65 % 3.47 %
Expected average long-term increase in compensation level 3.75 3.75 3.75 - - -
Expected average long-term rate of return on assets 6.60 6.60 7.10 4.10 4.10 4.50
(a)A settlement charge is required when the amount of lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2022 and 2021, as a result of lump-sum distributions during each plan year, NSP-Minnesota recorded a total pension settlement charge of $38 million and $35 million, respectively, which was not recognized in earnings due to the effects of regulation. There were no settlement charges recorded for the qualified pension plans in 2020.
Pension Benefits Postretirement Benefits
(Millions of Dollars) 2022 2021 2022 2021
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss $ 309 $ 307 $ 16 $ 31
Prior service credit - - (1) (4)
Total $ 309 $ 307 $ 15 $ 27
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets $ 12 $ 25 $ - $ -
Noncurrent regulatory assets 297 282 14 25
Deferred income taxes - - - 1
Net-of-tax accumulated other comprehensive income - - 1 1
Total $ 309 $ 307 $ 15 $ 27
Measurement date Dec 31, 2022 Dec 31, 2021 Dec 31, 2022 Dec 31, 2021
Cash Flows - Funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the requirements of income tax and other pension-related regulations. Required contributions were made in 2020 - 2023 to meet minimum funding requirements.
Total voluntary and required pension funding contributions across all four of Xcel Energy’s pension plans were as follows:
•$50 million in January 2023, of which $23 million is attributable to NSP-Minnesota.
•$50 million in 2022, of which $5 million was attributable to NSP-Minnesota.
•$131 million in 2021, of which $34 million was attributable to NSP-Minnesota.
•$150 million in 2020, of which $44 million was attributable to NSP-Minnesota.
The postretirement health care plans have no funding requirements other than fulfilling benefit payment obligations when claims are presented and approved. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities. Xcel Energy’s voluntary postretirement funding contributions were as follows:
•$12 million expected in 2023, of which $6 million is attributable to NSP-Minnesota.
•$13 million during 2022, of which $7 million, was attributable to NSP-Minnesota.
•$15 million during 2021, of which $8 million was attributable to NSP-Minnesota.
•$11 million during 2020, of which $6 million was attributable to NSP-Minnesota.
Targeted asset allocations:
Pension Benefits Postretirement Benefits
2022 2021 2022 2021
Domestic and international equity securities 33 % 33 % 16 % 15 %
Long-duration fixed income and interest rate swap securities 38 37 - -
Short-to-intermediate fixed income securities 9 11 71 71
Alternative investments 18 17 12 8
Cash 2 2 1 6
Total 100 % 100 % 100 % 100 %
The asset allocations above reflect target allocations approved in the calendar year to take effect in the subsequent year
Plan Amendments - In 2022 and 2020, there were no significant plan amendments made which affected the postretirement benefit obligation.
In 2021, Xcel Energy amended the Xcel Energy Pension Plan and Xcel Energy Inc. Nonbargaining Pension Plan (South) to reduce supplemental benefits for non-bargaining participants as well as to allow the transfer of a portion of non-qualified pension obligations into the qualified plans.
Projected Benefit Payments
NSP-Minnesota’s projected benefit payments:
(Millions of Dollars) Projected
Pension Benefit
Payments Gross Projected
Postretirement
Health Care
Benefit Payments (a)
2023 $ 84 $ 6
2024 64 5
2025 64 5
2026 61 5
2027 59 4
2028-2032 279 17
(a)Amount is reported net of expected Medicare Part D subsidies, which are immaterial.
Defined Contribution Plans
Xcel Energy, which includes NSP-Minnesota, maintains 401(k) and other defined contribution plans that cover most employees. The expense to these plans for NSP-Minnesota was approximately $13 million in 2022 and $12 million in 2021 and 2020.
Multiemployer Plans
NSP-Minnesota contributes to several union multiemployer pension and other postretirement benefit plans, none of which are individually significant. These plans provide pension and postretirement health care benefits to certain union employees who may perform services for multiple employers and do not participate in the NSP-Minnesota sponsored pension and postretirement health care plans. Contributing to these types of plans creates risk that differs from providing benefits under NSP-Minnesota sponsored plans, in that if another participating employer ceases to contribute to a multiemployer plan, additional unfunded obligations may need to be funded over time by remaining participating employers.
10. Commitments and Contingencies
Legal
NSP-Minnesota is involved in various litigation matters in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for losses probable of being incurred and subject to reasonable estimation.
Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories.
In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on NSP-Minnesota’s consolidated financial statements. Legal fees are generally expensed as incurred.
Rate Matters and Other
NSP-Minnesota is involved in various regulatory proceedings arising in the ordinary course of business. Until resolution, typically in the form of a rate order, uncertainties may exist regarding the ultimate rate treatment for certain activities and transactions. Amounts have been recognized for probable and reasonably estimable losses that may result. Unless otherwise disclosed, any reasonably possible range of loss in excess of any recognized amount is not expected to have a material effect on the consolidated financial statements.
Sherco - In 2018, NSP-Minnesota and Southern Minnesota Municipal Power Agency (Co-owner of Sherco Unit 3) reached a settlement with GE related to a 2011 incident, which damaged the turbine at Sherco Unit 3 and resulted in an extended outage for repair. NSP-Minnesota notified the MPUC of its proposal to refund settlement proceeds to customers through the fuel clause adjustment.
In March 2019, the MPUC approved NSP-Minnesota’s settlement refund proposal. Additionally, the MPUC decided to withhold any decision as to NSP-Minnesota’s prudence in connection with the incident at Sherco Unit 3 until after conclusion of an appeal pending between GE and NSP-Minnesota’s insurers.
In February 2020, the Minnesota Court of Appeals affirmed the district court’s judgment in favor of GE. In March 2020, NSP-Minnesota’s insurers filed a petition seeking additional review by the Minnesota Supreme Court. In April 2020, the Minnesota Supreme Court denied the insurers’ petition for further review, ending the litigation.
In January 2021, the Minnesota Office of the Attorney General and DOC recommended that NSP-Minnesota refund approximately $17 million of replacement power costs previously recovered through the fuel clause adjustment. NSP-Minnesota subsequently filed its response, asserting that it acted prudently in connection with the Sherco Unit 3 outage, the MPUC has previously disallowed $22 million of related costs and no additional refund or disallowance is appropriate.
A final decision by the MPUC is expected in mid-2024. A loss related to this matter is deemed remote.
MISO ROE Complaints - In November 2013 and February 2015, customer groups filed two ROE complaints against MISO TOs, which includes NSP-Minnesota and NSP-Wisconsin. The first complaint requested a reduction in base ROE transmission formula rates from 12.38% to 9.15% for the time period of Nov. 12, 2013 to Feb. 11, 2015, and removal of ROE adders (including those for RTO membership). The second complaint requested, for a subsequent time period, a base ROE reduction from 12.38% to 8.67%.
The FERC subsequently issued various related orders (including Opinion Nos. 569, 569A and 569B) related to ROE methodology/calculations and timing. NSP-Minnesota has processed refunds to customers for applicable complaint periods based on the ROE in the most recent applicable opinions.
The MISO TOs and various other parties have filed petitions for review of the FERC’s most recent applicable opinions at the D.C. Circuit. In August 2022, the D.C. Circuit ruled that FERC had not adequately supported its conclusions, vacated FERC’s related orders and remanded the issue back to FERC for further proceedings, which remain pending. Additional exposure, if any related to this matter is expected to be immaterial.
Environmental
New and changing federal and state environmental mandates can create financial liabilities for NSP-Minnesota, which are normally recovered through the regulated rate process.
Site Remediation
Various federal and state environmental laws impose liability where hazardous substances or other regulated materials have been released to the environment. NSP-Minnesota may sometimes pay all or a portion of the cost to remediate sites where past activities of NSP-Minnesota’s predecessors or other parties have caused environmental contamination.
Environmental contingencies could arise from various situations, including sites of former MGPs; and third-party sites, such as landfills, for which NSP-Minnesota is alleged to have sent wastes to that site.
Historical MGP, Landfill and Disposal Sites
NSP-Minnesota is investigating, remediating or performing post-closure actions at five MGP, landfill or other disposal sites across its service territories.
NSP-Minnesota has recognized its best estimate of costs/liabilities from final resolution of these issues, however, the outcome and timing are unknown. In addition, there may be insurance recovery and/or recovery from other potentially responsible parties, offsetting a portion of costs incurred.
Environmental Requirements - Water and Waste
Coal Ash Regulation - NSP-Minnesota’s operations are subject to federal and state regulations that impose requirements for handling, storage, treatment and disposal of solid waste. Under the CCR Rule, utilities are required to complete groundwater sampling around their CCR landfills and surface impoundments. Currently, NSP-Minnesota has three regulated ash units in operation.
NSP-Minnesota is conducting groundwater sampling and monitoring and implementing assessment of corrective measures at certain CCR landfills and surface impoundments. No results above the groundwater protection standards in the rule were identified.
Federal Clean Water Act Section 316(b) - The Federal Clean Water Act requires the EPA to regulate cooling water intake structures to assure they reflect the best technology available for minimizing impingement and entrainment of aquatic species. NSP-Minnesota estimates capital expenditures of approximately $40 million may be required for NSP-Minnesota to comply with the requirements pending approval of mitigation plans from the Minnesota Pollution Control Agency. NSP-Minnesota anticipates these costs will be recoverable through regulatory mechanisms.
AROs - AROs have been recorded for NSP-Minnesota’s assets. For nuclear assets, the ARO is associated with the decommissioning of NSP-Minnesota nuclear generating plants.
Aggregate fair value of NSP-Minnesota’s legally restricted assets for funding future nuclear decommissioning was $2.9 billion and $3.3 billion at Dec. 31, 2022 and 2021, respectively.
NSP-Minnesota’s AROs were as follows:
(Millions
of Dollars) Jan. 1, 2022 Amounts
Incurred
(a)
Accretion Cash Flow Revisions (b)
Dec. 31, 2022
Electric
Nuclear $ 2,056 $ - $ 104 $ - $ 2,160
Wind 384 25 15 (8) 416
Steam and other production 73 - 2 - 75
Distribution 16 - - - 16
Natural gas
Transmission and distribution 55 - 2 2 59
Common
Miscellaneous 1 - - - 1
Total liability $ 2,585 $ 25 $ 123 $ (6) $ 2,727
(a)Amounts incurred relate to the wind farms placed in service in 2022 (Dakota Range and Rock Aetna).
(b)In 2022, AROs were revised for changes in timing and estimates of cash flows. Changes in electric wind AROs were related to the repowering and extended retirement date of Nobles. Changes in gas transmission and distribution AROs were primarily related to changes in labor rates coupled with increased gas line mileage and number of services.
(Millions
of Dollars) Jan. 1, 2021 Amounts
Incurred
(a)
Accretion Cash Flow Revisions
(b)
Dec. 31, 2021
Electric
Nuclear $ 1,957 $ - $ 99 $ - $ 2,056
Wind 270 101 13 - 384
Steam and other production 67 6 2 (2) 73
Distribution 16 - - - 16
Miscellaneous - - - - -
Natural gas
Transmission and distribution 39 - 2 14 55
Common
Miscellaneous 1 - - - 1
Total liability $ 2,350 $ 107 $ 116 $ 12 $ 2,585
(a)Amounts incurred relate to the wind farms placed in service in 2021 (Blazing Star 2, Mower and Freeborn) and removal of a utility scale battery asset.
(b)In 2021, AROs were revised for changes in timing and estimates of cash flows. Changes in gas transmission and distribution AROs were primarily related to changes in labor rates coupled with increased gas line mileage and number of services.
Indeterminate AROs - Outside of the recorded asbestos AROs, other plants or buildings may contain asbestos due to the age of many of NSP-Minnesota’s facilities, but no confirmation or measurement of the cost of removal could be determined as of Dec. 31, 2022. Therefore, an ARO has not been recorded for these facilities.
Nuclear Related
Nuclear Insurance - NSP-Minnesota’s public liability for claims from any nuclear incident is limited to $13.7 billion under the Price-Anderson amendment to the Atomic Energy Act. NSP-Minnesota has $450 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $13.2 billion of exposure is funded by the Secondary Financial Protection Program available from assessments by the federal government.
NSP-Minnesota is subject to assessments of up to $138 million per reactor-incident for each of its three reactors, for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $20 million per reactor-incident during any one year. Maximum assessments are subject to inflation adjustments.
NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from NEIL and EMANI. The coverage limits are $2.8 billion for each of NSP-Minnesota’s two nuclear plant sites. NEIL also provides business interruption insurance coverage up to $350 million, including the cost of replacement power during prolonged accidental outages of nuclear generating units. Premiums are expensed over the policy term.
All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NEIL and EMANI to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage. NSP-Minnesota could be subject to annual maximum assessments of $12 million for business interruption insurance and $32 million for property damage insurance if losses exceed accumulated reserve funds.
Nuclear Fuel Disposal - NSP-Minnesota is responsible for temporarily storing spent nuclear fuel from its nuclear plants. The DOE is responsible for permanently storing spent fuel from U.S. nuclear plants, but no such facility is yet available.
NSP-Minnesota owns temporary on-site storage facilities for spent fuel at its Monticello and PI nuclear plants, which consist of storage pools and dry cask facilities. The Monticello dry-cask storage facility currently stores all 30 of the authorized canisters. The PI dry-cask storage facility currently stores 50 of the 64 authorized casks. Monticello’s future spent fuel will continue to be placed in its spent fuel pool. The decommissioning plan addresses the disposition of spent fuel at the end of the licensed life. A CON for additional storage at the Monticello site has been filed with the MPUC, to support possible life extension to 2040. NSP-Minnesota expects a decision by year-end 2023.
Regulatory Plant Decommissioning Recovery - Decommissioning activities for NSP-Minnesota’s nuclear facilities are planned to begin at the end of each unit’s authorized retirement dates, which can be different than the currently approved NRC operating licenses. These decommissioning activities are planned to be completed at both facilities by 2101.
NSP-Minnesota’s current operating licenses allow continued use of its Monticello nuclear plant until 2030 and its PI nuclear plant until 2033 for Unit 1 and 2034 for Unit 2. The MPUC reaffirmed a 60-year DECON scenario, where Monticello continues operations under a 10-year license extension (approved in April 2022). NRC approval of the extension is pending.
Future decommissioning costs of nuclear facilities are estimated through triennial periodic studies that assess the costs and timing of planned nuclear decommissioning activities for each unit. The 2020 nuclear decommissioning filing was approved by the MPUC and became effective in 2022.
Obligations for decommissioning are expected to be funded 100% by the external decommissioning trust fund. NSP-Minnesota had $2.9 billion and $3.3 billion of assets held in external decommissioning trusts at Dec. 31, 2022, and 2021, respectively.
See Note 10 to the consolidated financial statements for additional discussion.
Leases
NSP-Minnesota evaluates contracts that may contain leases, including PPAs and arrangements for the use of office space and other facilities, vehicles and equipment. A contract contains a lease if it conveys the exclusive right to control the use of a specific asset. A contract determined to contain a lease is evaluated further to determine if the arrangement is a finance lease.
ROU assets represent NSP-Minnesota's rights to use leased assets. The present value of future operating lease payments is recognized in current and noncurrent operating lease liabilities. These amounts, adjusted for any prepayments or incentives, are recognized as operating lease ROU assets.
Most of NSP-Minnesota’s leases do not contain a readily determinable discount rate. Therefore, the present value of future lease payments is generally calculated using the estimated incremental borrowing rate (weighted average of 3.8%).
NSP-Minnesota has elected to utilize the practical expedient under which non-lease components, such as asset maintenance costs included in payments, are not deducted from minimum lease payments for the purposes of lease accounting and disclosure.
Leases with an initial term of 12 months or less are classified as short-term leases and are not recognized on the consolidated balance sheet.
Operating lease ROU assets:
(Millions of Dollars) Dec. 31, 2022 Dec. 31, 2021
PPAs $ 556 $ 556
Other 78 74
Gross operating lease ROU assets 634 630
Accumulated amortization (310) (222)
Net operating lease ROU assets $ 324 $ 408
Components of lease expense:
(Millions of Dollars) 2022 2021 2020
Operating leases
PPA capacity payments $ 98 $ 96 $ 89
Other operating leases (a)
9 8 8
Total operating lease expense (b)
$ 107 $ 104 $ 97
(a)Includes short-term lease expense of $3 million, $2 million and $2 million for 2022, 2021 and 2020, respectively.
(b)PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income. Expense for other operating leases is included in O&M expense and electric fuel and purchased power.
Commitments under operating leases as of Dec. 31, 2022:
(Millions of Dollars) PPA (a) (b)
Operating
Leases
Other Operating
Leases
Total
Operating
Leases
2023 $ 98 $ 12 $ 110
2024 100 7 107
2025 79 8 87
2026 40 7 47
2027 - 7 7
Thereafter - 24 24
Total minimum obligation 317 65 382
Interest component of obligation (19) (9) (28)
Present value of minimum obligation $ 298 $ 56 354
Less current portion (98)
Noncurrent operating lease liabilities $ 256
Weighted-average remaining lease term in years 7.6
(a)Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs.
(b)PPA operating leases contractually expire at various dates through 2026.
PPAs and Fuel Contracts
Non-Lease PPAs - NSP-Minnesota has entered into PPAs with other utilities and energy suppliers for purchased power to meet system load and energy requirements, operating reserve obligations and as part of wholesale and commodity trading activities. In general, these agreements provide for energy payments, based on actual energy delivered and capacity payments. Certain PPAs, accounted for as executory contracts with various expiration dates through 2033, contain minimum energy purchase commitments. Total energy payments on those contracts were $182 million, $149 million and $112 million in 2022, 2021 and 2020, respectively.
Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $60 million, $55 million and $52 million in 2022, 2021 and 2020, respectively.
Capacity and energy payments are contingent on the IPPs meeting contract obligations, including plant availability requirements. Certain contractual payments are adjusted based on market indices. The effects of price adjustments on financial results are mitigated through purchased energy cost recovery mechanisms.
At Dec. 31, 2022, the estimated future payments for capacity and energy that NSP-Minnesota is obligated to purchase pursuant to these executory contracts, subject to availability, were as follows:
(Millions of Dollars) Capacity Energy (a)
2023 $ 61 $ 50
2024 63 45
2025 26 51
2026 9 48
2027 7 55
Thereafter 3 28
Total (b)
$ 169 $ 277
(a)Excludes contingent energy payments for renewable energy PPAs.
(b)Includes amounts allocated to NSP-Wisconsin through intercompany charges.
Fuel Contracts - NSP-Minnesota has entered into various long-term commitments for the purchase and delivery of a significant portion of its coal, nuclear fuel and natural gas requirements. These contracts expire in various years between 2023 and 2037. NSP-Minnesota is required to pay additional amounts depending on actual quantities shipped under these agreements.
Estimated minimum purchases for these contracts as of Dec. 31, 2022:
(Millions of Dollars) Coal Nuclear fuel Natural gas
supply Natural gas
storage and
transportation
2023 $ 227 $ 144 $ 130 $ 158
2024 110 112 1 148
2025 17 158 1 138
2026 1 37 - 143
2027 1 155 - 98
Thereafter - 194 - 116
Total (a)
$ 356 $ 800 $ 132 $ 801
(a)Includes amounts allocated to NSP-Wisconsin through intercompany charges.
VIEs
Under certain PPAs, NSP-Minnesota purchases power from IPPs for which NSP-Minnesota is required to reimburse fuel costs, or to participate in tolling arrangements under which NSP-Minnesota procures the natural gas required to produce the energy that it purchases. NSP-Minnesota has determined that certain IPPs are VIEs. NSP-Minnesota is not subject to risk of loss from the operations of these entities, and no significant financial support is required other than contractual payments for energy and capacity. NSP-Minnesota evaluated each of these VIEs for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices, and financing activities.
NSP-Minnesota concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. NSP-Minnesota had approximately 1,322 MW and 1,347 MW of capacity under long-term PPAs at Dec. 31, 2022 and 2021, respectively, with entities that have been determined to be VIEs. These agreements have expiration dates through 2039.
11. Other Comprehensive Income
Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31:
(Millions of Dollars) Gains and Losses on Interest Rate Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total
Accumulated other comprehensive loss at Jan. 1 $ (17) $ (3) $ (20)
Other comprehensive loss before reclassifications, net of taxes of $- $ - $ 1 $ 1
Losses reclassified from net accumulated other comprehensive loss:
Amortization of interest rate hedges
1 (a)
- 1
Net current period other comprehensive income 1 1 2
Accumulated other comprehensive loss at Dec. 31 $ (16) $ (2) $ (18)
(Millions of Dollars) Gains and Losses on Interest Rate Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total
Accumulated other comprehensive loss at Jan. 1 $ (19) $ (3) $ (22)
Losses reclassified from net accumulated other comprehensive loss:
Amortization of interest rate hedges
2 (a)
- 2
Net current period other comprehensive income 2 - 2
Accumulated other comprehensive loss at Dec. 31 $ (17) $ (3) $ (20)
(a)Included in interest charges.
12. Segment Information
NSP-Minnesota evaluates performance based on profit or loss generated from the product or service provided. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment.
NSP-Minnesota has the following reportable segments:
•Regulated Electric - The regulated electric utility segment generates, transmits and distributes electricity in Minnesota, North Dakota and South Dakota. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. The regulated electric utility segment also includes wholesale commodity and trading operations.
•Regulated Natural Gas - The regulated natural gas utility segment transports, stores and distributes natural gas primarily in portions of Minnesota and North Dakota.
NSP-Minnesota also presents All Other, which includes operating segments with revenues below the necessary quantitative thresholds. Those operating segments primarily include steam revenue, appliance repair services, non-utility real estate activities and revenues associated with processing solid waste into refuse-derived fuel.
Asset and capital expenditure information is not provided for NSP-Minnesota’s reportable segments. As an integrated electric and natural gas utility, NSP-Minnesota operates significant assets that are not dedicated to a specific business segment. Reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations, which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.
Certain costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators across each segment. In addition, a general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.
NSP-Minnesota’s segment information:
(Millions of Dollars) 2022 2021 2020
Regulated Electric
Operating revenues - external (a)
$ 5,617 $ 5,094 $ 4,571
Intersegment revenue 1 1 1
Total revenues $ 5,618 $ 5,095 $ 4,572
Depreciation and amortization 953 869 773
Interest charges and financing costs 257 240 221
Income tax (benefit) expense (127) (53) (14)
Net income 626 566 553
Regulated Natural Gas
Operating revenues - external (b)
$ 1,022 $ 623 $ 493
Intersegment revenue 2 1 -
Total revenues $ 1,024 $ 624 $ 493
Depreciation and amortization 60 56 51
Interest charges and financing costs 22 18 17
Income tax expense 14 6 7
Net income 45 29 30
All Other
Total revenues $ 45 $ 39 $ 37
Depreciation and amortization 1 1 1
Income tax (benefit) expense 1 (1) 1
Net income 4 11 8
Consolidated Total
Total revenues (a)(b)
$ 6,687 $ 5,758 $ 5,102
Reconciling eliminations (3) (2) (1)
Total operating revenues $ 6,684 $ 5,756 $ 5,101
Depreciation and amortization 1,014 926 825
Interest charges and financing costs 279 258 238
Income tax (benefit) expense (112) (48) (6)
Net income 675 606 591
(a)Operating revenues include $514 million, $501 million and $440 million of affiliate electric revenue for the years ended Dec. 31, 2022, 2021 and 2020, respectively. See Note 13 for further information.
(b)Operating revenues include $0 million, $1 million and $1 million of affiliate gas revenue for the years ended Dec. 31, 2022, 2021 and 2020, respectively. See Note 13 for further information.
13. Related Party Transactions
Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy Inc., including NSP-Minnesota. The services are provided and billed to each subsidiary in accordance with service agreements executed by each subsidiary. NSP-Minnesota uses the services provided by Xcel Energy Services Inc. whenever possible. Costs are charged directly to the subsidiary and are allocated if they cannot be directly assigned.
Xcel Energy, Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS have established a utility money pool arrangement.
See Note 5 for further information.
The electric production and transmission costs of the entire NSP System are shared by NSP-Minnesota and NSP-Wisconsin. The Interchange Agreement provides for the sharing of all costs of generation and transmission facilities of the system, including capital costs.
Significant affiliate transactions among the companies and related parties including billings under the Interchange Agreement for the years ended Dec. 31:
(Millions of Dollars) 2022 2021 2020
Operating revenues:
Electric $ 514 $ 501 $ 440
Gas - 1 1
Operating expenses:
Purchased power 70 67 59
Transmission expense 132 121 109
Other operating expenses - paid to Xcel Energy Services Inc. 673 615 584
Interest income 1 - -
Interest expense 1 - -
Accounts receivable and payable with affiliates at Dec. 31:
2022 2021
(Millions of Dollars) Accounts Receivable Accounts Payable Accounts Receivable Accounts Payable
NSP-Wisconsin $ 4 $ - $ 13 $ -
PSCo - 2 16 -
SPS - 3 - 2
Other subsidiaries of Xcel Energy Inc. 41 84 - 61
$ 45 $ 89 $ 29 $ 63

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.

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ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A - CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
NSP-Minnesota maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms.
In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the CEO and CFO, allowing timely decisions regarding required disclosure. As of Dec. 31, 2022, based on an evaluation carried out under the supervision and with the participation of NSP-Minnesota’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and procedures, the CEO and CFO have concluded that NSP-Minnesota’s disclosure controls and procedures were effective.
Internal Control Over Financial Reporting
No changes in NSP-Minnesota’s internal control over financial reporting occurred during the most recent fiscal quarter ended Dec. 31, 2022 that materially affected, or are reasonably likely to materially affect, NSP-Minnesota’s internal control over financial reporting. NSP-Minnesota maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting. NSP-Minnesota has evaluated and documented its controls in process activities, general computer activities, and on an entity-wide level.
During the year and in preparation for issuing its report for the year ended Dec. 31, 2022 on internal controls under section 404 of the Sarbanes-Oxley Act of 2002, NSP-Minnesota conducted testing and monitoring of its internal control over financial reporting. Based on the control evaluation, testing and remediation performed, NSP-Minnesota did not identify any material control weaknesses, as defined under the standards and rules issued by the Public Company Accounting Oversight Board, as approved by the SEC and as indicated in NSP-Minnesota’s Management Report on Internal Controls over Financial Reporting, which is contained in Item 8 herein.
This annual report does not include an attestation report of NSP-Minnesota’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by NSP-Minnesota’s independent registered public accounting firm pursuant to the rules of the SEC that permit NSP-Minnesota to provide only management’s report in this annual report.

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ITEM 9B. OTHER INFORMATION
ITEM 9B - OTHER INFORMATION
None.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 10 - DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

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ITEM 11. EXECUTIVE COMPENSATION
ITEM 11 - EXECUTIVE COMPENSATION

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
ITEM 12 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information required under this Item is contained in Xcel Energy Inc.’s definitive Proxy Statement for its 2023 Annual Meeting of Shareholders, which is incorporated by reference.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 14 - PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information required under this Item (aggregate fees billed to us by our principal accountant, Deloitte & Touche LLP (PCAOB ID No. 34)) is contained in Xcel Energy Inc.’s Proxy Statement for its 2023 Annual Meeting of Shareholders, which is incorporated by reference.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15 - EXHIBIT AND FINANCIAL STATEMENT SCHEDULES
1 Consolidated Financial Statements:
Management Report on Internal Controls Over Financial Reporting - For the year ended Dec. 31, 2022.
Report of Independent Registered Public Accounting Firm - Financial Statements
Consolidated Statements of Income - For each of the three years ended Dec. 31, 2022, 2021 and 2020.
Consolidated Statements of Comprehensive Income - For each of the three years ended Dec. 31, 2022, 2021 and 2020.
Consolidated Statements of Cash Flows - For each of the three years ended Dec. 31, 2022, 2021 and 2020.
Consolidated Balance Sheets - As of Dec. 31, 2022 and 2021.
Consolidated Statements of Common Stockholder’s Equity - For each of the three years ended Dec. 31, 2022, 2021 and 2020.
2 Schedule II - Valuation and Qualifying Accounts and Reserves for each of the years ended Dec. 31, 2022, 2021 and 2020.
3 Exhibits
*
Indicates incorporation by reference
+
Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors
Exhibit Number Description Report or Registration Statement Exhibit Reference
3.01*
Articles of Incorporation and Amendments of Northern Power Corp. (renamed Northern States Power Co. (a Minnesota corporation) on Aug. 21, 2000)
NSP-Minnesota Form 10-12G dated Oct. 5, 2000 3.01
3.02*
By-Laws of NSP-Minnesota as Amended and Restated on Jan. 25, 2019
NSP-Minnesota Form 10-K for the year ended Dec. 31, 2018 3.02
4.01*
Supplemental and Restated Trust Indenture, dated May 1, 1988, from NSP-Minnesota to Harris Trust and Savings Bank, as Trustee, providing for the issuance of First Mortgage Bonds, Supplemental Indentures between NSP-Minnesota and said Trustee
Xcel Energy Inc. Form S-3 dated April 18, 2018 4(b)(3)
4.02*
Supplemental Trust Indenture, dated as of June 1, 1995, from NSP-Minnesota to Harris Trust and Savings Bank, as Trustee, creating $250 million aggregate principal amount of 7.125% First Mortgage Bonds, Series due July 1, 2025
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2017 4.11
4.03*
Supplemental Trust Indenture, dated as of March 1, 1998, from NSP-Minnesota to Harris Trust and Savings Bank, as Trustee, creating $150 million aggregate principal amount of 6.5% First Mortgage Bonds, Series due March 1, 2028
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2017 4.12
4.04*
Supplemental Trust Indenture, dated as of Aug. 1, 2000 (Assignment and Assumption of Trust Indenture)
NSP-Minnesota Form 10-12G dated Oct. 5, 2000 4.51
4.05*
Indenture, dated as of July 1, 1999, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, NA (as successor to Norwest Bank Minnesota, NA), as Trustee, providing for the issuance of Sr. Debt Securities
Xcel Energy Inc. Form S-3 dated April 18, 2018 4(b)(7)
4.06*
Supplemental Indenture No. 2, dated Aug. 18, 2000, supplemental to the Indenture, dated as of July 1, 1999, among Xcel Energy Inc., NSP-Minnesota and The Bank of New York Mellon Trust Company, NA (as successor to Wells Fargo Bank Minnesota, NA), as Trustee
NSP-Minnesota Form 10-12G dated Oct. 5, 2000 4.63
4.07*
Supplemental Trust Indenture, dated as of July 1, 2005, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, NA (as successor to BNY Midwest Trust Company), as Trustee, creating $250 million aggregate principal amount of 5.25% First Mortgage Bonds, Series due July 15, 2035
NSP-Minnesota Form 8-K dated July 14, 2005 4.01
4.08*
Supplemental Trust Indenture, dated as of May 1, 2006, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, NA (as successor to BNY Midwest Trust Company), as Trustee, creating $400 million aggregate principal amount of 6.25% First Mortgage Bonds, Series due June 1, 2036
NSP-Minnesota Form 8-K dated May 18, 2006 4.01
4.09*
Supplemental Trust Indenture, dated as of June 1, 2007, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, NA (as successor to BNY Midwest Trust Company), as Trustee, creating $350 million aggregate principal amount of 6.20% First Mortgage Bonds, Series due July 1, 2037
NSP-Minnesota Form 8-K dated June 19, 2007 4.01
4.10*
Supplemental Trust Indenture, dated as of Nov. 1, 2009, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company., NA, as Trustee, creating $300 million aggregate principal amount of 5.35% First Mortgage Bonds, Series due Nov. 1, 2039
NSP-Minnesota Form 8-K dated Nov. 16, 2009 4.01
4.11*
Supplemental Trust Indenture, dated as of Aug. 1, 2010, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, NA, as Trustee, creating $250 million aggregate principal amount of 4.85% First Mortgage Bonds, Series due Aug. 15, 2040
NSP-Minnesota Form 8-K dated Aug. 4, 2010 4.01
4.12*
Supplemental Trust Indenture, dated as of Aug. 1, 2012, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, NA, as Trustee, creating $500 million aggregate principal amount of 3.40% First Mortgage Bonds, Series due Aug. 15, 2042
NSP-Minnesota Form 8-K dated Aug. 13, 2012 4.01
4.13*
Supplemental Trust Indenture, dated as of May 1, 2013, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating $400 million aggregate principal amount of 2.60% First Mortgage Bonds, Series due May 15, 2023
NSP-Minnesota Form 8-K dated May 20, 2013 4.01
4.14*
Supplemental Trust Indenture, dated as of May 1, 2014, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating $300 million aggregate principal amount of 4.125% First Mortgage Bonds, Series due May 15, 2044
NSP-Minnesota Form 8-K dated May 13, 2014 4.01
4.15*
Supplemental Trust Indenture, dated as of Aug. 1, 2015, by and between NSP-Minnesota and The Bank of New York Mellon Company, N.A., as Trustee, creating $300 million aggregate principal amount of 4.00% First Mortgage Bonds, Series due Aug. 15, 2045
NSP-Minnesota Form 8-K dated Aug. 11, 2015 4.01
4.16*
Supplemental Trust Indenture, dated as of May 1, 2016, by and between NSP-Minnesota and The Bank of NY Mellon Trust Company, N.A., as Trustee, creating $350 million aggregate principal amount of 3.60% First Mortgage Bonds, Series due May 15, 2046
NSP-Minnesota Form 8-K dated May 31, 2016 4.01
4.17*
Supplemental Trust Indenture, dated as of Sept. 1, 2017, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating $600 million aggregate principal amount of 3.60% First Mortgage Bonds, Series due Sept. 15, 2047
NSP-Minnesota Form 8-K dated Sept. 13, 2017 4.01
4.18*
Supplemental Trust Indenture, dated as of Sept. 1, 2019, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating $600 million aggregate principal amount of 2.90% First Mortgage Bonds, Series due March 1, 2050
NSP-Minnesota Form 8-K dated Sept. 10, 2019 4.01
4.19*
Supplemental Indenture, dated as of June 8, 2020, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating $700 million aggregate principal amount of 2.60% First Mortgage Bonds, Series due June 1, 2051
NSP-Minnesota 8-K dated June 15, 2020 4.01
4.20*
Supplemental Indenture, dated as of March 1, 2021, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating $425 million principal amount of 2.25% First Mortgage Bonds, Series due April 1, 2031 and $425 million principal amount of 3.20% First Mortgage Bonds, Series due April 1, 2052
NSP-Minnesota 8-K dated March 30, 2021
4.01
4.21*
Supplemental Indenture, dated as of May 1, 2022, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating $500 million aggregate principal amount of 4.50% First Mortgage Bonds, Series due June 1, 2052
NSP-Minnesota 8-K dated May 9, 2022 4.01
10.01*+
Xcel Energy Inc. Nonqualified Pension Plan (2009 Restatement)
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 10.02
10.02*+
Xcel Energy Senior Executive Severance and Change-in-Control Policy (2009 Amendment and Restatement)
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 10.05
10.03*+
Second Amendment to Exhibit 10.02 dated Oct. 26, 2011
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011 10.18
10.04*+
Fifth Amendment to Exhibit 10.02 dated May 3, 2016
Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2016 10.01
10.05*+
Seventh Amendment to Exhibit 10.02 dated May 7, 2018
Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2018 10.01
10.06*+
Eighth Amendment to Exhibit 10.02 dated March 31, 2020
Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2020 10.02
10.07*+
Ninth Amendment to Exhibit 10.02 dated May 22, 2020
Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2020 10.01
10.08*+
Xcel Energy Inc. Supplemental Executive Retirement Plan as amended and restated Jan. 1, 2009
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 10.17
10.09*+
Xcel Energy Inc. Executive Annual Incentive Plan (as amended and restated effective Feb. 17, 2010)
Xcel Energy Inc. Definitive Proxy Statement dated April 6, 2010 Appendix A
10.10*+
First Amendment to Exhibit 10.09 dated Feb. 20, 2013
Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2013 10.01
10.11*+
Xcel Energy Inc. Executive Annual Incentive Award Plan Form of Restricted Stock Agreement
Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2009 10.08
10.12*+
Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement)
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 10.07
10.13*+
First Amendment to Exhibit 10.12 effective Nov. 29, 2011
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011 10.17
10.14*+
Second Amendment to Exhibit 10.12 dated May 21, 2013
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2013 10.22
10.15*+
Third Amendment to Exhibit 10.12 dated Sept. 30, 2016
Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2016 10.01
10.16*+
Fourth Amendment to Exhibit 10.12 dated Oct. 23, 2017
Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2017 10.1
10.17*+
Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018 10.34
10.18*+
Form of Terms and Conditions under the Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan for Awards of Restricted Stock Units and/or Performance Share Units
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018 10.35
10.19*+
Form of Award Agreement for Restricted Stock Units and/or Performance Share Units under the Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan for awards since 2020
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2019 10.33
10.20*+
Stock Equivalent Plan for Non-Employee Directors of Xcel Energy Inc. as amended and restated effective Feb. 23, 2011
Xcel Energy Inc. Definitive Proxy Statement dated April 5, 2011 Schedule 14A
10.21*+
Stock Equivalent Program for Non-Employee Directors of Xcel Energy Inc. under the Xcel Energy Inc. 2015 Omnibus Incentive Plan
Xcel Energy Inc. Form 8-K dated May 26, 2015 10.02
10.22*+
Summary of Non-Employee Director Compensation, effective as of Oct. 1, 2021
Xcel Energy Inc. Form 10-Q for the quarter ended September 30, 2021
10.01
10.23*+
Stock Program for Non-Employee Directors of Xcel Energy Inc. as Amended and Restated on Dec. 12, 2017 under the 2015 Omnibus Incentive Plan
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018 10.36
10.24*+
Form of Services Agreement between Xcel Energy Services Inc. and utility companies
Xcel Energy Inc. Form U5B dated Nov. 16, 2000 H-1
10.25*
Restated Interchange Agreement dated Jan. 16, 2001 between NSP-Wisconsin and NSP-Minnesota
NSP-Wisconsin Form S-4 dated Jan. 21, 2004 10.01
10.26*
Fourth Amended and Restated Credit Agreement, dated as of September 19, 2022, among NSP-Minnesota, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank PLC, as Syndication Agents, and Citibank, N.A., MUFG Bank, Ltd., and Wells Fargo Bank, National Association, as Documentation Agents
Xcel Energy Inc. Form 8-K dated Sept. 19, 2022 99.02
23.01
Consent of Independent Registered Public Accounting Firm.
31.01
Principal Executive Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02
Principal Financial Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01
Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH Inline XBRL Schema
101.CAL Inline XBRL Calculation
101.DEF Inline XBRL Definition
101.LAB Inline XBRL Label
101.PRE Inline XBRL Presentation
104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
SCHEDULE II
NSP-Minnesota and Subsidiaries Valuation and Qualifying Accounts Years Ended Dec. 31
Allowance for bad debts
(Millions of Dollars) 2022 2021 2020
Balance at Jan. 1 $ 45 $ 33 $ 23
Additions charged to costs and expenses 21 24 24
Additions charged to other accounts (a)
6 5 5
Deductions from reserves (b)
(26) (17) (19)
Balance at Dec. 31 $ 46 $ 45 $ 33
(a)Recovery of amounts previously written-off.
(b)Deductions related primarily to bad debt write-offs.