EDGAR 10-K Filing

Company CIK: 92521
Filing Year: 2023
Filename: 92521_10-K_2023_0000092521-23-000003.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 SPS, 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 we file 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
SPS’ 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.
SPS 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. SPS 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 SPS. 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 electric generation, transmission and distribution operations involve numerous risks that may result in accidents and other operating risks and costs.
Our electric generation, transmission and distribution activities include inherent hazards and operating risks such as contact, fire and outages. Our natural gas transmission activities include inherent hazards and operating risks, such as leaks, explosions, outages and mechanical problems.
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 SPS’ 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 Department of Transportation’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 electric transmission and distribution operations and natural gas transmission 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 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 SPS 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, SPS 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, SPS cannot fully assure that its controls will be effective against all potential risks. If such programs and procedures are not effective, SPS’ 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. SPS 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 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 or 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 SPS is imposed by its state regulatory commissions. State regulatory commissions indirectly limit the amount of dividends that SPS can pay Xcel Energy Inc., by requiring a minimum equity-to-total capitalization ratio.
See Note 5 to the 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 our 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 or 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.
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., SPP, Midcontinent Independent System Operator, Inc., 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 would trigger settlement accounting and could require SPS 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.
SPS 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, SPS 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. SPS 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 utility business is 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. 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 power generation has increasingly become a public policy advocacy target. These efforts may result in a limitation of natural gas as an energy source for power generation, 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 SPS 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 SPS' electric 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 SPS 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 SPS is subject to the lien of its first mortgage bond indenture.
Station, Location and Unit at Dec. 31, 2022 Fuel Installed MW (a)
Steam:
Cunningham-Hobbs, NM, 2 Units Natural Gas 1957 - 1965 225
Harrington-Amarillo, TX, 3 Units Coal 1976 - 1980 1,018
Jones-Lubbock, TX, 2 Units Natural Gas 1971 - 1974 486
Maddox-Hobbs, NM, 1 Unit Natural Gas 1967 112
Nichols-Amarillo, TX, 3 Units Natural Gas 1960 - 1968 457
Plant X-Earth, TX, 3 Units Natural Gas 1952 - 1964 298
Tolk-Muleshoe, TX, 2 Units Coal 1982 - 1985 1,067
Combustion Turbine:
Cunningham-Hobbs, NM, 2 Units Natural Gas 1997 207
Jones-Lubbock, TX, 2 Units Natural Gas 2011 - 2013 334
Maddox-Hobbs, NM, 1 Unit Natural Gas 1963 - 1976 61
Wind:
Hale-Plainview, TX, 239 Units Wind 2019 477 (b)
Sagamore-Dora, NM, 240 Units Wind 2020 507 (b)
Total 5,249
(a)Summer 2022 net dependable capacity.
(b) Capacity is attainable only when wind conditions are sufficiently available.
Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2022:
Conductor Miles
Transmission
500 KV -
345 KV 11,676
230 KV 9,829
161 KV -
138 KV -
115 KV 14,905
Less than 115 KV 4,469
Total Transmission 40,879
Distribution
Less than 115 KV 23,538
Total 64,417
SPS had 457 electric utility transmission and distribution substations at Dec. 31, 2022.
SPS had 20 miles of natural gas utility transmission mains at Dec. 31, 2022.

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ITEM 3. LEGAL PROCEEDINGS
ITEM 3 - LEGAL PROCEEDINGS
SPS 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 SPS’ financial statements. Legal fees are generally expensed as incurred.
See Note 10 to the 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
SPS is a wholly owned subsidiary of Xcel Energy Inc. and there is no market for its common equity securities.
See Note 5 to the financial statements for further information.
The dividends declared during 2022 and 2021 were as follows:
(Millions of Dollars) 2022 2021
First quarter $ 53 $ 52
Second quarter 58 79
Third quarter 150 123
Fourth quarter 61 60

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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 SPS 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 and the results of operations for the current year as set forth in general instructions 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.
SPS’ 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 SPS’ core earnings and underlying performance.
We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of SPS. 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
SPS’ net income was $349 million for 2022, compared with net income of $318 million for 2021. The increase was largely related to regulatory rate outcomes, strong sales growth and favorable weather, partially offset by higher 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 and coal. 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 $ 2,426 $ 2,465
Electric fuel and purchased power (1,157) (1,432)
Electric margin $ 1,269 $ 1,033
Changes in Electric Margin
(Millions of Dollars) 2022 vs. 2021
Regulatory rate outcomes (Texas and New Mexico) $ 138
Revenue recognition for the Texas rate case surcharge (a)
Sales and demand 48
Estimated impact of weather 24
PTCs flowed back to customers (offset by lower ETR) (30)
Other (net) (29)
Total increase $ 236
(a)Recognition of revenue from the Texas rate case outcome is largely offset by recognition of previously deferred costs, see Public Utility Regulation and Other for additional information.
Non-Fuel Operating Expense and Other Items
O&M Expenses - O&M expenses increased $46 million year-to-date. The increase was primarily due to recognition of previously deferred amounts related to the 2021 Texas rate case; costs for technology and customer programs; inflation and impacts of supply chain constraints; insurance costs; and other.
Depreciation and Amortization - Depreciation and amortization increased $88 million year-to-date. The increase is primarily due to the 2021 Texas Rate Case depreciation deferral, capital investment and the implementation of new depreciation rates in Texas and New Mexico.
Income Taxes - Income tax benefit decreased $6 million for 2022. This was primarily driven by higher pretax earnings partially offset by an increase in wind PTCs due to an increase in the PTC rate. 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 state and local regulatory commissions regulate SPS. SPS is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric distribution companies in New Mexico and Texas.
Rates are designed to recover plant investment, operating costs and an allowed return on investment. SPS requests changes in utility rates through commission filings. Changes in operating costs can affect SPS’ 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 DSM 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 SPS’ results of operations and credit quality.
See Rate Matters within Note 10 to the financial statements for further
information.
Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
Regulatory Body / RTO Additional Information
PUCT Retail electric operations, rates, services, construction of transmission or generation and other aspects of SPS’ electric operations.
The municipalities in which SPS operates in Texas have original jurisdiction over rates in those communities. The municipalities’ rate setting decisions are subject to PUCT review.
Reviews and approves Integrated Resource Plans for meeting future energy needs
NMPRC Retail electric operations, retail rates and services and the construction of transmission or generation.
FERC Wholesale electric operations, accounting practices, wholesale sales for resale, the transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers, and natural gas transactions in interstate commerce.
SPP RTO and SPP Integrated and Wholesale Markets SPS is a transmission owning member of the SPP RTO and operates within the SPP RTO and SPP integrated and wholesale markets. SPS is authorized to make wholesale electric sales at market-based prices.
Recovery Mechanisms
Mechanism Additional Information
Distribution Cost Recovery Factor Recovers distribution costs not included in rates in Texas.
Energy Efficiency Cost Recovery Factor Recovers costs for energy efficiency programs in Texas.
Energy Efficiency Rider Recovers costs for energy efficiency programs in New Mexico.
Fuel and Purchased Power Cost Adjustment Clause Adjusts monthly to recover actual fuel and purchased power costs in New Mexico.
Power Cost Recovery Factor Allows recovery of purchased power costs not included in Texas rates.
Renewable Portfolio Standards Recovers deferred costs for renewable energy programs in New Mexico.
Transmission Cost Recovery Factor Recovers certain transmission infrastructure improvement costs and changes in wholesale transmission charges not included in Texas base rates.
Fixed Fuel and Purchased Recovery Factor Provides for the over- or under-recovery of energy expenses in Texas. Regulations require refunding or surcharging over- or under- recovery amounts, including interest, when they exceed 4% of the utility’s annual fuel and purchased energy costs on a rolling 12-month basis, if this condition is expected to continue.
Wholesale Fuel and Purchased Energy Cost Adjustment SPS recovers fuel and purchased energy costs from its wholesale customers through a monthly wholesale fuel and purchased energy cost adjustment clause accepted by the FERC. Wholesale customers also pay the jurisdictional allocation of production costs.
Electric Vehicle Rider Recovers costs of the Transportation Electrification Plan in New Mexico.
Advanced Metering System Surcharge Recovers costs incurred in deployment of the Advanced Metering System in Texas.
Consulting Fee Rider Recovers consulting fees and carrying charges incurred by SPS on behalf of the PUCT.
Pending and Recently Concluded Regulatory Proceedings
2021 Texas Electric Rate Case - In May 2022, the PUCT approved a settlement between SPS and intervening parties.
In July 2022, SPS filed to surcharge the final under-recovered amount, estimated to be approximately $85 million, substantially offset by the recognition of previously deferred costs.
(Millions of Dollars) Year Ended Dec. 31, 2022
Revenue surcharge accrual $ 85
Depreciation and amortization (43)
O&M expenses (16)
Interest expense (12)
Taxes other than income taxes (10)
Fuel and purchased power (2)
2022 New Mexico Electric Rate Case - In November 2022, SPS filed an electric rate case with NMPRC seeking a revenue increase of $78 million, or 10%. The request is based on a future test year ending June 30, 2024, a ROE of 10.75%, an equity ratio of 54.7% and rate base of $2.4 billion. Additionally, the request reflects further acceleration of the Tolk coal plant depreciation life from 2032 to 2028.
Next steps in the procedural schedule are expected to be as follows:
•Staff and intervenor testimony: March 31, 2023.
•Rebuttal testimony: April 25, 2023.
•Stipulation: May 8, 2023.
•Hearing: June 5, 2023.
•End of rate suspension: Sept. 19, 2023.
2023 Texas Electric Rate Case - On Feb. 8, 2023, SPS filed an electric rate case with the PUCT seeking an increase in base rate revenue of $149 million. The impact to overall customer bills is expected to be approximately 13%. The request is based on a historical test year period ended Sept. 30, 2022, with an Update Period ended Dec. 31, 2022, a ROE of 10.65%, an equity ratio of 54.6% and retail rate base of $3.6 billion. Additionally, the request reflects further acceleration of the Tolk coal plant depreciation life from 2034 to 2028.
SPS is requesting a surcharge from July 13, 2023 through the effective date of new base rates. A PUCT decision is expected in the first quarter of 2024.
Contract Termination - SPS and LP&L are parties to a 25-year, 170 MW partial requirements contract. In May 2021, SPS and LP&L finalized a settlement which would terminate the contract upon LP&L’s move from the SPP to the Electric Reliability Council of Texas (expected in 2023). The settlement agreement requires LP&L to pay SPS $78 million (lump sum or annual installments), to the benefit of SPS’ remaining customers. LP&L would remain obligated to pay for SPP transmission charges associated with LP&L’s load in SPP. The agreement is subject to approval by the PUCT and FERC.
2022 All-Source RFP - In 2022, SPS issued an RFP, which seeks up to 947 MW of new or existing capacity resources to provide replacement capacity for retiring units and meet SPS’ growing capacity needs through 2027. SPS will receive bids in the first quarter of 2023 and file for the approval of successful proposals in the second quarter of 2023.
Purchased Power Arrangements and Transmission Service Providers
SPS expects to use electric generating stations, power purchases, DSM and new generation options to meet its system capacity requirements.
Purchased Power - SPS purchases power from other utilities and IPPs. Long-term purchased power contracts typically require periodic capacity and energy charges. SPS also makes short-term purchases to meet system load and energy requirements to replace owned generation, meet operating reserve obligations or obtain energy at a lower cost.
Purchased Transmission Services - SPS has contractual arrangements with SPP and regional transmission service providers to deliver power and energy to its native load customers.
Natural Gas
SPS does not provide retail natural gas service, but purchases and transports natural gas for its generation facilities and operates limited natural gas pipeline facilities connecting the generation facilities to interstate natural gas pipelines. SPS is subject to the jurisdiction of the FERC with respect to natural gas transactions in interstate commerce and the PHMSA and PUCT for pipeline safety compliance.
Wholesale and Commodity Marketing Operations
SPS conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy related products. SPS uses physical and financial instruments to minimize commodity price and credit risk and to hedge sales and purchases.
Other
Supply Chain
Xcel Energy’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. SPS 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. SPS continues to seek alternative suppliers and prioritize work plans to mitigate impacts of supply constraints.
Inflation Reduction Act
In August 2022, the IRA was signed into law.
Key provisions impacting SPS 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 and clean hydrogen.
•Establishes an ITC for energy storage, microgrids, interconnection facilities, etc.
•Allows companies to monetize or sell credits to unrelated parties.
SPS 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 SPS to monetize tax credits more efficiently with the incremental benefits passed through to customers.
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, SPS incurred net natural gas, fuel and purchased energy costs of approximately $100 million (largely deferred as regulatory assets). SPS currently has regulatory approval for recovery of Winter Storm Uri costs in New Mexico and anticipates a final decision on recovery in Texas in the first quarter of 2023.
Texas Regulatory Overview - In 2021, SPS filed to recover $88 million of Winter Storm Uri costs over 24 months, as part of the Texas fuel surcharge filing, with total under-recovered costs of $121 million. In April 2022, interim rates designed to recover $121 million over 30 months were approved, subject to PUCT approval through the triennial Fuel Reconciliation proceeding.
In July 2022, the intervenors filed recommendations. The Texas Industrial Energy Consumers and PUCT staff recommended disallowances of approximately $10 million (off-system sales margins). The Office of Public Utility Counsel recommended disallowances of approximately $15 million (off-system sales margins and adjustment to energy loss factors). The Alliance of Xcel Municipalities recommended disallowances of approximately $100 million (natural gas storage, contracted capability and off-system sales margins).
In November 2022, the Administrative Law Judges found that costs were prudently incurred and recommended no disallowances. A final PUCT decision is anticipated in the first quarter of 2023.

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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
SPS 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.
SPS 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 SPS expects that the counterparties will perform on the contracts underlying its derivatives, the contracts expose SPS to credit and non-performance risk.
Distress in the financial markets may impact counterparty risk and the fair value of the securities in the pension fund.
Commodity Price Risk - We are exposed to commodity price risk in our electric 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.
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 - SPS conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments, including derivatives. SPS’ risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee.
Interest Rate Risk - SPS is subject to interest rate risk. SPS’ 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 SPS’ variable rate debt would impact pretax interest expense annually by an immaterial amount in 2022 and approximately $2 million in 2021.
The value of pension and postretirement plan assets and benefit costs are impacted by changes in discount rates and expected return on plan assets. SPS’ 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 - SPS is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance on their contractual obligations. SPS 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 $12 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $12 million. At Dec. 31, 2021, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $3 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $3 million.
SPS 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 SPS’ credit risk.
Fair Value Measurements
Derivative contracts, with the exception of those designated as normal purchases and normal sales, are reported at fair value. SPS’ investments held in pension and other postretirement funds are also subject to fair value accounting. See Note 8 and 9 to the 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 12 to the financial statements for further information.
Management Report on Internal Control Over Financial Reporting
The management of SPS is responsible for establishing and maintaining adequate internal control over financial reporting. SPS’ internal control system was designed to provide reasonable assurance to Xcel Energy Inc.’s and SPS’ 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.
SPS management assessed the effectiveness of SPS’ 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, SPS’ 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 Southwestern Public Service Company
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Southwestern Public Service Company (the "Company") as of December 31, 2022 and 2021, the related 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 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 transmission and distribution companies in New Mexico and Texas. The Company is also subject to the jurisdiction of the Federal Energy Regulatory Commission for its wholesale electric operations, 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.
SOUTHWESTERN PUBLIC SERVICE CO.
STATEMENTS OF INCOME
(amounts in millions)
Year Ended Dec. 31
2022 2021 2020
Operating revenues $ 2,426 $ 2,465 $ 1,870
Operating expenses
Electric fuel and purchased power 1,157 1,432 835
Operating and maintenance expenses 317 271 275
Demand side management expenses 23 17 16
Depreciation and amortization 388 300 295
Taxes (other than income taxes) 107 79 90
Total operating expenses 1,992 2,099 1,511
Operating income 434 366 359
Other income (expense), net - 1 (2)
Allowance for funds used during construction - equity 3 4 33
Interest charges and financing costs
Interest charges - includes other financing costs of $4, $4 and $4, respectively
143 114 119
Allowance for funds used during construction - debt (2) (2) (14)
Total interest charges and financing costs 141 112 105
Income before income taxes 296 259 285
Income tax benefit (53) (59) (10)
Net income $ 349 $ 318 $ 295
See Notes to Financial Statements
SOUTHWESTERN PUBLIC SERVICE CO.
STATEMENTS OF CASH FLOWS
(amounts in millions)
Year Ended Dec. 31
2022 2021 2020
Operating activities
Net income $ 349 $ 318 $ 295
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization 391 303 298
Deferred income taxes 17 (47) 22
Allowance for equity funds used during construction (3) (4) (33)
Provision for bad debts 9 6 6
Changes in operating assets and liabilities:
Accounts receivable (67) (29) (14)
Accrued unbilled revenues (16) (10) -
Inventories (19) (21) (35)
Prepayments and other (50) 16 (14)
Accounts payable 22 4 8
Net regulatory assets and liabilities (5) (154) (115)
Other current liabilities 52 (1) 13
Pension and other employee benefit obligations 1 (18) (16)
Other, net (5) (4) (1)
Net cash provided by operating activities 676 359 414
Investing activities
Utility capital/construction expenditures (578) (580) (1,142)
Investments in utility money pool arrangement (176) (83) (4)
Receipts from utility money pool arrangement 176 83 4
Net cash used in investing activities (578) (580) (1,142)
Financing activities
(Repayments of) proceeds from short-term borrowings, net (103) (113) 250
Proceeds from issuance of long-term debt, net 196 247 343
Borrowings under utility money pool arrangement 336 539 561
Repayments under utility money pool arrangement (427) (448) (561)
Capital contributions from parent 220 301 438
Dividends paid to parent (319) (310) (313)
Net cash (used in) provided by financing activities (97) 216 718
Net change in cash and cash equivalents 1 (5) (10)
Cash, cash equivalents and restricted cash at beginning of period 1 6 16
Cash, cash equivalents and restricted cash at end of period $ 2 $ 1 $ 6
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized) $ (137) $ (108) $ (98)
Cash received for income taxes, net 81 21 10
Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions $ 86 $ 37 $ 99
Inventory transfers to property, plant and equipment 10 6 31
Allowance for equity funds used during construction 3 4 33
See Notes to Financial Statements
SOUTHWESTERN PUBLIC SERVICE CO.
BALANCE SHEETS
(amounts in millions, except share and per share data)
Dec. 31
2022 2021
Assets
Current assets
Cash and cash equivalents $ 2 $ 1
Accounts receivable, net 167 115
Accounts receivable from affiliates 15 9
Accrued unbilled revenues 140 125
Inventories 61 51
Regulatory assets 217 193
Derivative instruments 122 30
Prepaid taxes 5 3
Prepayments and other 68 21
Total current assets 797 548
Property, plant and equipment, net 8,129 7,838
Other assets
Regulatory assets 359 380
Derivative instruments 3 6
Operating lease right-of-use assets 434 463
Other 26 27
Total other assets 822 876
Total assets $ 9,748 $ 9,262
Liabilities and Equity
Current liabilities
Short-term debt $ 34 $ 137
Borrowings under utility money pool arrangement - 91
Accounts payable 209 172
Accounts payable to affiliates 23 16
Regulatory liabilities 148 54
Taxes accrued 61 47
Accrued interest 31 30
Dividends payable to parent 61 58
Derivative instruments 4 4
Operating lease liabilities 31 30
Other 58 24
Total current liabilities 660 663
Deferred credits and other liabilities
Deferred income taxes 739 702
Regulatory liabilities 715 709
Asset retirement obligations 147 116
Derivative instruments 2 6
Pension and employee benefit obligations 12 8
Operating lease liabilities 403 434
Other 9 8
Total deferred credits and other liabilities 2,027 1,983
Commitments and contingencies
Capitalization
Long-term debt 3,211 3,013
Common stock - 200 shares authorized of $1.00 par value; 100 shares outstanding at Dec. 31, 2022 and Dec. 31, 2021, respectively
- -
Additional paid in capital 3,311 3,091
Retained earnings 540 513
Accumulated other comprehensive loss (1) (1)
Total common stockholder's equity 3,850 3,603
Total liabilities and equity $ 9,748 $ 9,262
See Notes to Financial Statements
SOUTHWESTERN PUBLIC SERVICE CO.
STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
(amounts in millions, except share data)
Common Stock Issued Accumulated
Other
Comprehensive
Loss Total
Common
Stockholder’s
Equity
Shares Par Value Additional
Paid In
Capital
Retained
Earnings
Balance at Dec. 31, 2019 100 $ - $ 2,351 $ 535 $ (1) $ 2,885
Net income 295 295
Common dividends declared to parent (321) (321)
Contribution of capital by parent 439 439
Balance at Dec. 31, 2020 100 $ - $ 2,790 $ 509 $ (1) $ 3,298
Net income 318 318
Common dividends declared to parent (314) (314)
Contribution of capital by parent 301 301
Balance at Dec. 31, 2021 100 $ - $ 3,091 $ 513 $ (1) $ 3,603
Net income 349 349
Common dividends declared to parent (322) (322)
Contribution of capital by parent 220 220
Balance at Dec. 31, 2022 100 $ - $ 3,311 $ 540 $ (1) $ 3,850
See Notes to Financial Statements
SOUTHWESTERN PUBLIC SERVICE COMPANY
Notes to Financial Statements
1. Summary of Significant Accounting Policies
General - SPS is engaged in the regulated generation, purchase, transmission, distribution and sale of electricity.
SPS’ financial statements are presented in accordance with GAAP. All of SPS’ 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 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.
SPS has evaluated events occurring after Dec. 31, 2022 up to the date of issuance of these financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.
Use of Estimates - SPS 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 - SPS 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, SPS 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 SPS’ results of operations, financial condition and cash flows.
See Note 4 for further information.
Income Taxes - SPS 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 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.
SPS 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. SPS 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 SPS tax elections. For tax credits otherwise eligible to be recognized when earned, SPS 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.
SPS 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 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 statements of income.
Xcel Energy Inc. and its subsidiaries, including SPS 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 balance sheet as a regulatory liability. Depreciation expense, expressed as a percentage of average depreciable property, was 3.4% in 2022, 3.3% in 2021 and 3.1% in 2020.
See Note 3 for further information.
AROs - SPS 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.
Benefit Plans and Other Postretirement Benefits - SPS 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 SPS 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 SPS’ 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. SPS 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.
SPS participates in SPP. SPS 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.
See Note 6 for further information.
Cash and Cash Equivalents - SPS 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. SPS 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 $13 million and $12 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 $ 42 $ 29
Fuel 19 22
Total inventories $ 61 $ 51
Fair Value Measurements - SPS presents cash equivalents, interest rate derivatives and commodity derivatives at estimated fair values in its 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 - SPS 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 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 - SPS 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.
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 SPS’ rate base.
Alternative Revenue - Certain rate rider mechanisms (including 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 equal to the revenue requirement, 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 - SPS has implemented programs in its jurisdictions to assist customers in conserving energy and reducing peak demand on the electric system. These programs include commercial motor, air conditioner and lighting upgrades, as well as residential rebates for participation in air conditioner interruption and home weatherization.
The costs incurred for some DSM programs are deferred as permitted by the applicable regulatory jurisdiction. For those programs, costs are deferred if it is probable future revenue will be provided to permit recovery of the incurred cost. Revenues recognized for incentive programs designed for recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the annual period in which they are earned. SPS recovers approved conservation program costs in base rate revenue or through a rider.
Emissions Allowances - Emissions allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emission allowances and sales of these allowances are included in electric revenues.
RECs - Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. SPS reduces recoverable fuel and purchased power costs for the cost of RECs received.
An inventory accounting model is used to account for RECs, however these assets are classified as regulatory assets if amounts are recoverable in future rates.
Sales of RECs are recorded in electric revenues on a gross basis. Cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.
Segment Information - SPS has only one reportable segment. SPS is a wholly owned subsidiary of Xcel Energy Inc. and operates in the regulated electric utility industry providing wholesale and retail electric service in the states of Texas and New Mexico.
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 SPS’ 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 $ 10,182 $ 9,639
Plant to be retired (a)
266 299
CWIP 167 171
Total property, plant and equipment 10,615 10,109
Less accumulated depreciation (2,486) (2,271)
Property, plant and equipment, net $ 8,129 $ 7,838
(a)Amounts include Tolk and coal generation assets at Harrington pending facility gas conversion and are presented net of accumulated depreciation.
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 rates. SPS 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 $ 2 $ 146 $ 11 $ 135
Net AROs (b)
1, 10 Various - 48 - 40
Excess deferred taxes - TCJA 7 Various 1 48 2 50
Recoverable deferred taxes on AFUDC Plant lives - 40 - 41
Deferred natural gas and electric energy/fuel costs One to three years
136 34 146 4
Losses on reacquired debt Term of related debt 1 19 1 19
Texas revenue surcharges One year
69 - 20 64
Other Various 8 24 13 27
Total regulatory assets $ 217 $ 359 $ 193 $ 380
(a)Prior period amounts have been restated to conform with current year presentation.
(b)Includes amounts recorded for future recovery of AROs.
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 $ - $ 469 $ 15 $ 486
Plant removal costs 1, 10 Various - 198 - 190
Effects of regulation on employee benefit costs Various - 20 - 19
Renewable resources and environmental initiatives Various - 14 - 7
Formula rates One to two years
10 8 6 4
Contract valuation adjustments (c)
1, 8 One to two years
119 1 27 1
Other Various 19 5 6 2
Total regulatory liabilities $ 148 $ 715 $ 54 $ 709
(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.
SPS’ 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 $48 million and $292 million at Dec. 31, 2022 and 2021, respectively, of past expenditures not earning a return. Amounts are predominately related to losses on reacquired debt, rate case expenses, and transmission-related deferrals and amortizations.
5. Borrowings and Other Financing Instruments
Short-Term Borrowings
SPS 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 $ 100 $ 100 $ 100 $ 100
Amount outstanding at period end - - 91 -
Average amount outstanding 7 35 51 43
Maximum amount outstanding 42 100 100 100
Weighted average interest rate, computed on a daily basis 3.17 % 0.44 % 0.05 % 0.54 %
Weighted average interest rate at end of period N/A N/A 0.05 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 $ 500 $ 500 $ 500 $ 500
Amount outstanding at period end 34 34 137 250
Average amount outstanding 20 100 63 44
Maximum amount outstanding 65 324 342 250
Weighted average interest rate, computed on a daily basis 4.08 % 0.79 % 0.21 % 1.11 %
Weighted average interest rate at end of period 4.55 4.55 0.26 0.29
Letters of Credit - SPS may use letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. At both Dec. 31, 2022 and 2021, there were $2 million of letters of credit outstanding under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees.
Credit Facility - In order to use its commercial paper program to fulfill short-term funding needs, SPS must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under this credit facility. The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.
Features of SPS’ 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
46% 47% $50 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 SPS would be in default on its borrowings under the facility if SPS or any of its future significant subsidiaries whose total assets exceed 15% of SPS’ total assets default on indebtedness in an aggregate principal amount exceeding $75 million.
If SPS 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, SPS was in compliance with all financial covenants.
SPS had the following committed credit facility available as of Dec. 31, 2022 (in millions) of dollars:
Credit Facility (a)
Drawn (b)
Available
$ 500 $ 36 $ 464
(a)This credit facility matures in September 2027.
(b)Includes letters of credit and outstanding commercial paper.
All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. SPS had no direct advances on the facility outstanding at Dec. 31, 2022 and 2021.
Long-Term Borrowings and Other Financing Instruments
Generally, the property of SPS 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 SPS as of Dec. 31 (in millions of dollars):
Financing Instrument Interest Rate Maturity Date 2022 2021
First mortgage bonds 3.30 % June 15, 2024 $ 150 $ 150
First mortgage bonds 3.30 June 15, 2024 200 200
Unsecured senior notes 6.00 Oct. 1, 2033 100 100
Unsecured senior notes 6.00 Oct. 1, 2036 250 250
First mortgage bonds 4.50 Aug. 15, 2041 200 200
First mortgage bonds 4.50 Aug. 15, 2041 100 100
First mortgage bonds 4.50 Aug. 15, 2041 100 100
First mortgage bonds 3.40 Aug. 15, 2046 300 300
First mortgage bonds 3.70 Aug. 15, 2047 450 450
First mortgage bonds 4.40 Nov. 15, 2048 300 300
First mortgage bonds
3.75 June 15, 2049 300 300
First mortgage bonds 3.15 May 1, 2050 350 350
First mortgage bonds (a)
3.15 May 1, 2050 250 250
First mortgage bonds (b)
5.15 June 1, 2052 200 -
Unamortized discount (10) (9)
Unamortized debt issuance cost (29) (28)
Total long-term debt $ 3,211 $ 3,013
(a)2020 financing re-opened in 2021.
(b)2022 financing.
Maturities of long-term debt:
(Millions of Dollars)
2023 $ -
2024 350
2025 -
2026 -
2027 -
Deferred Financing Costs - Deferred financing costs of approximately $29 million and $28 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt at Dec. 31, 2022 and 2021, respectively. SPS is amortizing these financing costs over the remaining maturity periods of the related debt.
Capital Stock - SPS has the following preferred stock:
Preferred Stock Authorized (Shares) Par Value of Preferred Stock Preferred Stock Outstanding (Shares) 2022 and 2021
10,000,000 1.00 -
Dividend Restrictions - SPS dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital accounts. Dividends are solely to be paid from retained earnings. SPS is required to be current on particular interest payments before dividends can be paid.
SPS’ 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 (a)
Low High 2022
45.0 % 55.0 % 54.3 %
(a)Excludes short-term debt.
Unrestricted Retained Earnings Total Capitalization Limit on Total Capitalization (a)
$ 540 million $ 7,094 million N/A
(a)SPS may not pay a dividend that would cause it to lose its investment grade bond rating.
6. Revenues
Revenue is classified by the type of goods/services rendered and market/customer type. SPS’ operating revenues consisted of the following:
Year Ended Dec. 31
(Millions of Dollars) 2022 2021 2020
Major revenue types
Revenue from contracts with customers:
Residential $ 445 $ 375 $ 359
C&I 1,102 842 739
Other 51 38 39
Total retail 1,598 1,255 1,137
Wholesale 407 873 345
Transmission 296 287 279
Other 10 6 4
Total revenue from contracts with customers 2,311 2,421 1,765
Alternative revenue and other 115 44 105
Total revenues $ 2,426 $ 2,465 $ 1,870
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 2.3 2.5 2.3
Increases (decreases) in tax from:
Wind PTCs (a)
(35.9) (39.7) (18.3)
Plant regulatory differences (b)
(3.8) (4.8) (6.4)
Amortization of excess nonplant deferred taxes (0.9) (1.1) (0.8)
Other, net (0.6) (0.7) (1.3)
Effective income tax rate (17.9) % (22.8) % (3.5) %
(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 to current year presentation.
Components of income tax expense for years ended Dec. 31:
(Millions of Dollars) 2022 2021 2020
Current federal tax benefit $ (65) $ (11) $ (31)
Current state tax benefit (5) (1) (1)
Deferred federal tax expense (benefit) 3 (57) 13
Deferred state tax expense 13 9 8
Deferred change in unrecognized tax expense 1 1 1
Total income tax benefit $ (53) $ (59) $ (10)
Components of deferred income tax expense as of Dec. 31:
(Millions of Dollars) 2022 2021 2020
Deferred tax expense (benefit) excluding items below $ 37 $ (23) $ 53
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities (20) (24) (31)
Deferred tax expense (benefit) $ 17 $ (47) $ 22
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 $ 1,015 $ 942
Operating lease assets 97 103
Regulatory assets 61 65
Deferred fuel costs 35 34
Pension expense 33 34
Other 1 1
Total deferred tax liabilities $ 1,242 $ 1,179
Deferred tax assets:
Operating lease liabilities $ 97 $ 103
Regulatory liabilities 98 98
Tax credit carryforward 294 187
NOL carryforward 2 76
Other employee benefits 6 7
Other 6 6
Total deferred tax assets 503 477
Net deferred tax liability $ 739 $ 702
(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 $ 8 $ 336
Federal tax credit carryforwards 294 187
State NOL carryforwards 4 111
Federal carryforward periods expire starting 2033 and state carryforward periods expire starting 2034.
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. SPS is not expected to accrue any income tax expense related to this adjustment.
Unrecognized Tax Benefits
Federal Audit - SPS is a member of Xcel Energy affiliated group that files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s consolidated federal 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 - SPS is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2022, SPS’ earliest open tax years that are subject to examination by state taxing authorities under applicable statutes of limitations are as follows:
State Tax Year(s) Expiration
Texas 2016 May 2023
Texas 2017 July 2025
Texas 2018 November 2023
In 2021, Texas began an audit of tax years 2016 - 2019. As of Dec. 31, 2022, no material adjustments have been proposed.
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 $ 5 $ 4
Unrecognized tax benefit - Temporary tax positions 4 4
Total unrecognized tax benefit $ 9 $ 8
Changes in unrecognized tax benefits:
(Millions of Dollars) 2022 2021 2020
Balance at Jan. 1 $ 8 $ 7 $ 5
Additions based on tax positions related to the current year 1 1 1
Additions for tax positions of prior years - - 5
Reductions for tax positions of prior years - - (4)
Balance at Dec. 31 $ 9 $ 8 $ 7
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 $ (8) $ (7)
As the IRS progresses its review of the tax loss carryback claim and as state audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $6 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) receivable for interest related to unrecognized tax benefits at Jan. 1 $ (1) $ (1) $ 1
Interest expense related to unrecognized tax benefits 1 - (2)
(Payable) receivable for interest related to unrecognized tax benefits at Dec. 31 $ - $ (1) $ (1)
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:
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 SPS 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.
Derivative Activities and Fair Value Measurements
SPS enters into derivative instruments, including forward contracts, for trading purposes and to manage risk in connection with changes in interest rates and utility commodity prices.
Interest Rate Derivatives - SPS 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 loss.
As of Dec. 31, 2022, accumulated other comprehensive loss related to interest rate derivatives included immaterial net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings. As of Dec. 31, 2022, SPS had no unsettled interest rate derivatives.
Wholesale and Commodity Trading - SPS conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments, including derivatives. SPS 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 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 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 - SPS enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric utility operations. This could include the purchase or sale of energy or energy-related products and FTRs.
The most significant derivative positions outstanding at December 31, 2022 and 2021 for this purpose relate to FTR instruments administered by SPP. 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 SPS enters into derivative instruments that mitigate commodity price risk on behalf of electric 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.
Gross notional amounts of FTRs:
(Amounts in Millions) (a)
Dec. 31, 2022 Dec. 31, 2021
MWh of electricity 8 8
(a)Not reflective of net positions in the underlying commodities.
Consideration of Credit Risk and Concentrations - SPS 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 balance sheets.
SPS’ 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, two of SPS’ eight most significant counterparties for these activities, comprising $7 million or 23% of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services, or Fitch Ratings.
Five of the eight most significant counterparties, comprising $24 million or 77% of this credit exposure, were not rated by these external ratings agencies, but based on SPS’ internal analysis, had credit quality consistent with investment grade. One of these significant counterparties, comprising an immaterial amount or less than 1% of this credit exposure, had credit quality less than investment grade, based on internal analysis. These eight significant counterparties are municipal or cooperative electric entities, RTOs or other utilities.
Recurring Derivative Fair Value Measurements
Impact of derivative activity:
Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:
(Millions of Dollars) Regulatory (Assets) and Liabilities
Year Ended Dec. 31, 2022
Other derivative instruments
Electric commodity $ (3)
Total $ (3)
Year Ended Dec. 31, 2021
Other derivative instruments
Electric commodity $ 28
Total $ 28
Year Ended Dec. 31, 2020
Other derivative instruments
Electric commodity $ (7)
Total $ (7)
Pre-Tax (Gains) Losses
Reclassified into Income
During the Period from:
(Millions of Dollars) Regulatory
Assets and (Liabilities)
Year Ended Dec. 31, 2022
Other derivative instruments
Electric commodity 2 (a)
Total $ 2
Year Ended Dec. 31, 2021
Other derivative instruments
Electric commodity (20) (a)
Total $ (20)
(a)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.
An immaterial amount of settlements were recorded in 2020. SPS 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:
Electric commodity $ - $ - $ 119 $ 119 $ - $ 119 $ - $ - $ 27 $ 27 $ - $ 27
Total current derivative assets $ - $ - $ 119 $ 119 $ - 119 $ - $ - $ 27 $ 27 $ - 27
PPAs (b)
3 3
Current derivative instruments $ 122 $ 30
Noncurrent derivative assets
PPAs (b)
$ 3 $ 6
Noncurrent derivative instruments $ 3 $ 6
Current derivative liabilities
Other derivative instruments:
PPAs (b)
$ 4 $ 4
Current derivative instruments $ 4 $ 4
Noncurrent derivative liabilities
PPAs (b)
$ 2 $ 6
Noncurrent derivative instruments $ 2 $ 6
(a)SPS nets derivative instruments and related collateral on its balance sheet 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 or rights to reclaim cash collateral. Counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
(b)SPS 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 $ 27 $ 7 $ 12
Purchases (a)
248 10 23
Settlements (a)
(168) (79) (23)
Net transactions recorded during the period:
Net gains (losses) recognized as regulatory assets and liabilities (a)
12 89 (5)
Balance at Dec. 31 $ 119 $ 27 $ 7
(a)Relates primarily to FTR instruments administered by SPP.
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 $ 3,211 $ 2,674 $ 3,013 $ 3,454
Fair value of SPS’ 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 SPS, 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 4.69, 2.35 and 2.37 percent 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 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 $1 million and $2 million was attributable to SPS in 2022 and 2021, respectively. In 2022 and 2021, Xcel Energy recognized net benefit cost for the SERP and nonqualified plans of $17 million and $4 million, respectively, of which immaterial amounts were attributable to SPS.
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 long-term projected return levels by investment experts. Xcel Energy and SPS continually review 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 6.39%.
•Investment returns in 2021 were above the assumed level of 6.39%.
•Investment returns in 2020 were above the assumed level of 6.78%.
•In 2023, SPS’s expected investment-return assumption is 6.96%.
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.
State agencies also have issued guidelines to the funding of postretirement benefit costs. SPS is required to fund postretirement benefit costs for Texas and New Mexico amounts collected in rates. These assets are invested in a manner consistent with the investment strategy for the pension plan.
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, SPS’ 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 $ 21 $ - $ - $ - $ 21 $ 20 $ - $ - $ - $ 20
Commingled funds 144 - - 129 273 202 - - 169 371
Debt securities - 115 - - 115 - 148 1 - 149
Equity securities 7 - - - 7 10 - - - 10
Other - 1 - - 1 - 2 - 5 7
Total $ 172 $ 116 $ - $ 129 $ 417 $ 232 $ 150 $ 1 $ 174 $ 557
(a)See Note 8 for further information on fair value measurement inputs and methods.
For each of the fair value hierarchy levels, SPS’ proportionate allocation of the total 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
Cash equivalents $ 3 $ - $ - $ - $ 3 $ 3 $ - $ - $ - $ 3
Insurance contracts - 4 - - 4 - 5 - - 5
Commingled funds 5 - - 6 11 6 - - 7 13
Debt securities - 18 - - 18 - 22 - - 22
Total $ 8 $ 22 $ - $ 6 $ 36 $ 9 $ 27 $ - $ 7 $ 43
(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 SPS are as follows:
Pension Benefits Postretirement Benefits
(Millions of Dollars) 2022 2021 2022 2021
Change in Benefit Obligation:
Obligation at Jan. 1 $ 545 $ 562 $ 34 $ 38
Service cost 10 11 1 1
Interest cost 16 15 1 1
Actuarial gain (123) (13) (8) (3)
Plan participants’ contributions - - 1 -
Benefit payments (34) (30) (3) (3)
Obligation at Dec. 31 $ 414 $ 545 $ 26 $ 34
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1 $ 557 $ 527 $ 43 $ 44
Actual return on plan assets (106) 46 (5) 1
Employer contributions - 14 - -
Plan participants’ contributions - - 1 1
Benefit payments (34) (30) (3) (3)
Fair value of plan assets at Dec. 31 $ 417 $ 557 $ 36 $ 43
Funded status of plans at Dec. 31 $ 3 $ 12 $ 10 $ 9
Amounts recognized in the Balance Sheet at Dec. 31:
Noncurrent assets 7 12 10 9
Noncurrent liabilities (4) - - -
Net amounts recognized $ 3 $ 12 $ 10 $ 9
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 $386 million and $506 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 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 $ 10 $ 11 $ 10 $ 1 $ 1 $ 1
Interest cost 16 15 18 1 1 1
Expected return on plan assets (31) (30) (29) (2) (2) (2)
Amortization of net loss (gain) 10 14 12 (1) (1) -
Settlement charge (a)
2 - - - - -
Net periodic pension cost 7 10 11 (1) (1) -
Effects of regulation (1) - 2 - - -
Net benefit cost recognized for financial reporting $ 6 $ 10 $ 13 $ (1) $ (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 6.39 6.39 6.78 4.10 4.10 4.50
(a)A settlement charge is required when the amount of all 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, as a result of lump-sum distributions during each plan year, SPS recorded a total pension settlement charge of $2 million. An immaterial amount was recorded in the income statement in 2022. There were no settlement charges recorded to the qualified pension plans in 2021 or 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 (gain) $ 145 $ 143 $ (21) $ (19)
Prior service credit (1) (1) - (1)
Total $ 144 $ 142 $ (21) $ (20)
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 $ 2 $ 11 $ - $ -
Noncurrent regulatory assets 142 131 - -
Current regulatory liabilities - - (1) (1)
Noncurrent regulatory liabilities - - (20) (19)
Total $ 144 $ 142 $ (21) $ (20)
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 none was attributable to SPS.
•$50 million in 2022, of which none was attributable to SPS.
•$131 million in 2021, of which $15 million was attributable to SPS.
•$150 million in 2020, of which $14 million was attributable to SPS.
For future years, Xcel Energy and SPS anticipate contributions will be made as necessary.
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, of which the amounts attributable to SPS were immaterial, were as follows:
•$12 million expected in 2023.
•$13 million during 2022.
•$15 million during 2021.
•$11 million during 2020.
Target asset allocations:
Pension Benefits Postretirement Benefits
2022 2021 2022 2021
Domestic and international equity securities 33 % 33 % 16 % 15 %
Long-duration fixed income 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 - There were no significant plan amendments made in 2022 or 2020 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
SPS’ projected benefit payments:
(Millions of Dollars) Projected
Pension Benefit
Payments Net Projected Postretirement Health Care Benefit Payments (a)
2023 $ 33 $ 2
2024 31 2
2025 32 2
2026 31 2
2027 32 2
2028-2032 157 11
(a)Amount is reported net of expected Medicare Part D subsidies, which are immaterial.
Defined Contribution Plans
Xcel Energy, which includes SPS, maintains 401(k) and other defined contribution plans that cover most employees. The expense to these plans for SPS was approximately $3 million in 2022, 2021 and 2020.
10. Commitments and Contingencies
Legal
SPS 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 SPS’ financial statements. Legal fees are generally expensed as incurred.
Other Litigation - In 2019, SPS and Xcel Energy Services, Inc. were served with a lawsuit related to a traffic accident that resulted in two fatalities in New Mexico. In July 2022, a confidential settlement was reached of approximately $50 million. No impact to earnings occurred, as the amounts were reimbursed by SPS’ insurers. An asset has been recorded to reflect the reimbursement within Prepayments and other current assets.
Rate Matters
SPS 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 financial statements.
SPP OATT Upgrade Costs - Costs of transmission upgrades may be recovered from other SPP customers whose transmission service depends on capacity enabled by the upgrade under the SPP OATT. SPP had not been charging its customers for these upgrades, even though the SPP OATT had allowed SPP to do so since 2008. In 2016, the FERC granted SPP’s request to recover these previously unbilled charges and SPP subsequently billed SPS approximately $13 million.
In July 2018, SPS’ appeal to the D.C. Circuit over the FERC rulings granting SPP the right to recover previously unbilled charges was remanded to the FERC. In February 2019, the FERC reversed its 2016 decision and ordered SPP to refund charges retroactively collected from its transmission customers, including SPS, related to periods before September 2015. In March 2020, SPP and Oklahoma Gas & Electric separately filed petitions for review of the FERC’s orders at the D.C. Circuit. In August 2021, the D.C. Circuit issued a decision denying these appeals and upholding the FERC’s orders. Refunds received by SPS are expected to be given back to SPS customers through future rates.
In October 2017, SPS filed a separate related complaint asserting SPP assessed upgrade charges to SPS in violation of the SPP OATT. In March 2018, the FERC issued an order denying the SPS complaint. SPS filed a request for rehearing in April 2018. The FERC issued a tolling order granting a rehearing for further consideration in May 2018. If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the amount through future SPS customer rates. In October 2020, SPS filed a petition for review of the FERC’s March 2018 order and May 2018 tolling order at the D.C. Circuit. In February 2022, FERC issued an order rejecting SPS’ request for hearing. SPS has appealed that order. That appeal has been combined with SPS’ prior appeal.
Wind Operating Commitments - PUCT and NMPRC orders related to the Hale and Sagamore wind projects included certain operating and savings minimums. In general, annual generation must exceed a net capacity factor of 48%. If annual generation is below the guaranteed level, SPS would be obligated to refund an amount equal to foregone PTCs and fuel savings. Additionally, retail customer savings must exceed project costs included in base rates over the first ten years of operations. SPS would be required to refund excess costs, if any, after ten years of operations. As of Dec. 31, 2022, the full-year net capacity factor exceeded the guaranteed level, resulting in no refund liability for 2022.
Environmental
New and changing federal and state environmental mandates can create financial liabilities for SPS, 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. SPS may sometimes pay all or a portion of the cost to remediate sites where past activities of SPS’ 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 SPS is alleged to have sent wastes to that site.
Historical MGP, Landfill and Disposal Sites
SPS is remediating one former disposal site. SPS 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 - Air
Reasonable Progress Rule and BART- In 2016, the EPA adopted a final rule establishing a federal implementation plan for reasonable further progress under the regional haze program for the state of Texas. The rule imposes SO2 emission limitations which would require the installation of dry scrubbers on Tolk Units 1 and 2; compliance would have been required by February 2021. SPS appealed the EPA’s decision and obtained a stay of the final rule.
In 2017, the EPA adopted a final BART rule for Texas. Under that rule, Harrington Units 1, 2, and 3 and Tolk Units 1 and 2 participate in intrastate SO2 budget and trading program. The rule also implemented participation in a federal ozone season NOx budget and trading program, named the Cross State Air Pollution Rule. The EPA is reconsidering this rule. In October 2020, the TCEQ approved an agreement that SPS will convert the Harrington plant from coal to natural gas by Jan. 1, 2025.
AROs - AROs have been recorded for SPS’ assets, as follows:
(Millions of Dollars) Jan. 1, 2022 Accretion Cash Flow Revisions (a)
Dec. 31, 2022
Electric
Steam and other production $ 54 $ 3 $ 26 $ 83
Wind 52 2 - 54
Distribution 10 - - 10
Total liability $ 116 $ 5 $ 26 $ 147
(a)In 2022, AROs were revised for changes in estimates of cash flows. Revisions in steam and other production AROs primarily related to changes in costs for steam production ponds remediation.
(Millions of Dollars) Jan. 1, 2021 Accretion Dec. 31, 2021 (a)
Electric
Steam and other production $ 52 $ 2 $ 54
Wind 50 2 52
Distribution 10 - 10
Total liability $ 112 $ 4 $ 116
(a)No AROs were revised in 2021.
Indeterminate AROs - Outside of the recorded asbestos AROs, other plants or buildings may contain asbestos due to the age of many of SPS’ 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.
Leases
SPS 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 SPS’ 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 SPS’ 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 4.4%). SPS 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 balance sheet.
Operating lease ROU assets:
(Millions of Dollars) Dec. 31, 2022 Dec. 31, 2021
PPAs $ 500 $ 500
Other 44 45
Gross operating lease ROU assets 544 545
Accumulated amortization (110) (82)
Net operating lease ROU assets $ 434 $ 463
Components of lease expense:
(Millions of Dollars) 2022 2021 2020
Operating leases
PPA capacity payments $ 53 $ 53 $ 48
Other operating leases (a)
4 4 3
Total operating lease expense (b)
$ 57 $ 57 $ 51
(a)Includes short-term lease expense of $1 million for 2022, 2021 and 2020.
(b)PPA capacity payments are included in electric fuel and purchased power on the statements of income. Expense for other operating leases is included in O&M expense.
Commitments under operating leases as of Dec. 31, 2022:
(Millions of Dollars) PPA (a) (b)
Operating
Leases
Other Operating
Leases
Total
Operating
Leases
2023 $ 46 $ 3 $ 49
2024 46 3 49
2025 46 4 50
2026 46 4 50
2027 46 4 50
Thereafter 266 36 302
Total minimum obligation 496 54 550
Interest component of obligation (102) (14) (116)
Present value of minimum obligation 394 40 434
Less current portion (31)
Noncurrent operating and finance lease liabilities $ 403
Weighted-average remaining lease term in years 11
(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 2033.
PPAs and Fuel Contracts
Non-Lease PPAs - SPS 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 2024, contain minimum energy purchase requirements.
Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts, were payments for capacity of $12 million in 2022, 2021 and 2020.
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.
At Dec. 31, 2022, the estimated future payments for capacity that SPS is obligated to purchase pursuant to these executory contracts, subject to availability, were as follows:
(Millions of Dollars) Capacity
2023 $ 13
2024 6
2025 -
2026 -
2027 -
Thereafter -
Total $ 19
Fuel Contracts - SPS has entered into various long-term commitments for the purchase and delivery of a significant portion of its coal and natural gas requirements. These contracts expire between 2023 and 2033. SPS is required to pay additional amounts depending on actual quantities shipped under these agreements.
Estimated minimum purchases under these contracts as of Dec. 31, 2022:
(Millions of Dollars) Coal Natural gas
supply Natural gas
storage and
transportation
2023 $ 201 $ 33 30
2024 133 - 16
2025 18 - 12
2026 19 - 6
2027 19 - 6
Thereafter - - 8
Total $ 390 $ 33 $ 78
VIEs
PPAs - Under certain PPAs, SPS purchases power from IPPs for which SPS is required to reimburse fuel costs, or to participate in tolling arrangements under which SPS procures the natural gas required to produce the energy that it purchases. SPS has determined that certain IPPs are VIEs. SPS 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.
In addition, certain solar PPAs provide an option to purchase emission allowances or sharing provisions related to production credits generated by the solar facility under contract. These specific PPAs create a variable interest in the IPP.
SPS 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. SPS concluded that these entities are not required to be consolidated in its financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance.
SPS had approximately 1,197 MW of capacity under long-term PPAs at both Dec. 31, 2022 and 2021 with entities that have been determined to be VIEs. These agreements have expiration dates through 2041.
Fuel Contracts - SPS purchases all of its coal requirements for its Harrington and Tolk plants from TUCO Inc. under contracts that will expire in December 2024 and December 2027, respectively. TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing, and delivery of coal to meet SPS’ requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters and handlers.
SPS has not provided any significant financial support to TUCO, other than contractual payments for delivered coal. However, the fuel contracts create a variable interest in TUCO due to SPS’ reimbursement of fuel procurement costs.
SPS has determined that TUCO is a VIE, however it has concluded that SPS is not the primary beneficiary because it does not have the power to direct the activities that most significantly impact TUCO’s economic performance.
11. Related Party Transactions
Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy Inc., including SPS. The services are provided and billed to each subsidiary in accordance with service agreements executed by each subsidiary. SPS uses 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.
Significant affiliate transactions among the companies and related parties for the years ended Dec. 31:
(Millions of Dollars) 2022 2021 2020
Operating expenses:
Other operating expenses - paid to Xcel Energy Services Inc. $ 238 $ 209 $ 200
Interest expense 1 - -
Accounts receivable and payable with affiliates at Dec. 31 were:
2022 2021
(Millions of Dollars) Accounts Receivable Accounts Payable Accounts Receivable Accounts Payable
NSP-Minnesota $ 3 $ - $ 2 $ -
PSCo 11 - 7 -
Other subsidiaries of Xcel Energy Inc. 1 23 - 16
$ 15 $ 23 $ 9 $ 16

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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
SPS 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 SPS’ management, including the CEO and CFO, of the effectiveness of its disclosure controls and procedures, the CEO and CFO have concluded that SPS’ disclosure controls and procedures were effective.
Internal Control Over Financial Reporting
No changes in SPS’ internal control over financial reporting occurred during SPS’ most recent fiscal quarter ended Dec. 31, 2022 that materially affected, or are reasonably likely to materially affect, SPS’ internal control over financial reporting. SPS maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting. SPS 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, SPS conducted testing and monitoring of its internal control over financial reporting. Based on the control evaluation, testing and remediation performed, SPS 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 SPS’ 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 SPS’ independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by SPS’ independent registered public accounting firm pursuant to the rules of the SEC that permit SPS 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 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
Statements of Income - For each of the three years ended Dec. 31, 2022, 2021 and 2020.
Statements of Comprehensive Income - For each of the three years ended Dec. 31, 2022, 2021 and 2020.
Statements of Cash Flows - For each of the three years ended Dec. 31, 2022, 2021 and 2020.
Balance Sheets - As of Dec. 31, 2022 and 2021.
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*
Amended and Restated Articles of Incorporation dated Sept. 30, 1997
SPS Form 10-Q for the quarter ended Sept. 30, 2017 3.01
3.02*
By-Laws of SPS as Amended and Restated on Jan. 25, 2019
SPS Form 10-K for the year ended Dec. 31, 2018 3.02
4.01*
Indenture, dated as of Feb. 1, 1999, by and between SPS and The Chase Manhattan Bank, as Trustee
SPS Form 8-K dated Feb. 25, 1999 99.2
4.02*
Third Supplemental Indenture, dated as of Oct. 1, 2003, by and between SPS and JPMorgan, (Chase Bank, as successor to The Chase Manhattan Bank), as Trustee, creating $100 million aggregate principal amount of Series C Notes, 6% due Oct. 1, 2033 and Series D Notes, 6% due Oct. 1, 2033
Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2003 4.04
4.03*
Fourth Supplemental Indenture, dated as of Oct. 1, 2006, by and between SPS and The Bank of New York, (as successor to The Chase Manhattan Bank), as Trustee, creating $250 million aggregate principal amount of Series F Notes, 6% due Oct. 1, 2036
SPS Form 8-K dated Oct. 3, 2006 4.01
4.04*
Indenture, dated as of Aug. 1, 2011, by and between SPS and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee
SPS Form 8-K dated Aug. 10, 2011 4.01
4.05*
Supplemental Indenture No. 1, dated as of Aug. 3, 2011, by and between SPS and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $200 million aggregate principal amount of 4.50% First Mortgage Bonds, Series No. 1 due Aug. 15, 2041
SPS Form 8-K dated Aug. 10, 2011 4.02
4.06*
Supplemental Indenture No. 3, dated as of June 1, 2014, by and between SPS and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $150 million aggregate principal amount of 3.30% First Mortgage Bonds, Series No. 3 due June 15, 2024
SPS Form 8-K dated June 9, 2014 4.02
4.07*
Supplemental Indenture No. 4, dated as of Aug. 1, 2016, by and between SPS and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $300 million aggregate principal amount of 3.40% First Mortgage Bonds, Series No. 4 due Aug. 15, 2046
SPS Form 8-K dated Aug. 12, 2016 4.02
4.08*
Supplemental Indenture No. 5, dated as of Aug. 1, 2017, by and between SPS and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $450 million aggregate principal amount of 3.70% First Mortgage Bonds, Series No. 5 due Aug. 15 2047
SPS Form 8-K dated Aug. 9, 2017 4.02
4.09*
Supplemental Indenture No. 6, dated as of Oct. 1, 2018, by and between SPS and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $300 million aggregate principal amount of 4.40% First Mortgage Bonds, Series No. 6 due Nov. 15, 2048
SPS Form 8-K dated Nov. 5, 2018 4.02
4.10*
Supplemental Indenture No. 7, dated as of June 1, 2019, by and between SPS and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $300 million aggregate principal amount of 3.75% First Mortgage Bonds, Series No. 7 due June 15, 2049
SPS Form 8-K dated June 18, 2019 4.02
4.11*
Supplemental Indenture No. 8, dated as of May 1, 2020, by and between SPS and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association, as Trustee), creating $600 million aggregate principal amount of 3.15% First Mortgage Bonds, Series No. 8 due May 1, 2050
SPS Form 8-K dated May 18, 2020 4.02
4.12*
Supplemental Indenture No. 9, dated as of May 1, 2022, by and between SPS and U.S. Bank Trust Company, National Association, as Trustee, creating $200 million aggregate principal amount of 5.15% First Mortgage Bonds, Series No. 9 due June 1, 2052
SPS Form 8-K dated May 31, 2022
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 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. 2015 Omnibus Incentive Plan Award Agreement for awards since 2020
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2019 10.32
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 Appendix A
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 Sept. 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*
Fourth Amended and Restated Credit Agreement, dated as of Sept. 19, 2022, among SPS, 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 99.04
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
Southwestern Public Service Co. Valuation and Qualifying Accounts Years Ended Dec. 31
Allowance for bad debts
(Millions of Dollars) 2022 2021 2020
Balance at Jan. 1 $ 12 $ 8 $ 5
Additions charged to costs and expenses 9 6 6
Additions charged to other accounts (a)
1 3 2
Deductions from reserves (b)
(9) (5) (5)
Balance at Dec. 31 $ 13 $ 12 $ 8
(a)Recovery of amounts previously written-off.
(b)Deductions related primarily to bad debt write-offs.