UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
| ☒ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
For the fiscal year ended December 31, 2022 or
| ☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
For the transition period from _____ to _____
001-3034 | ||
| (Commission File Number) | ||
| Xcel Energy Inc. | ||||||||
| (Exact name of registrant as specified in its charter) | ||||||||
Minnesota | 41-0448030 | |||||||||||||
| (State or Other Jurisdiction of Incorporation or Organization) | (IRS Employer Identification No.) | |||||||||||||
414 Nicollet Mall | Minneapolis | Minnesota | 55401 | |||||||||||
| (Address of Principal Executive Offices) | (Zip Code) | |||||||||||||
612 | 330-5500 | ||||
| (Registrant’s Telephone Number, Including Area Code) | |||||
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading Symbol(s) | Name of each exchange on which registered | ||||||||||||
| Common Stock, $2.50 par value per share | XEL | Nasdaq Stock Market LLC | ||||||||||||
Securities registered pursuant to section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ☒ Yes ☐ No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ☐ Yes ☒ No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation
S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☒ Yes ☐ No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. ☒ Large accelerated filer ☐ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). ☐ Yes ☒ No
As of June 30, 2022, the aggregate market value of the voting common stock held by non-affiliates of the Registrant was $38,692,119,433.
As of Feb. 16, 2023, there were 549,847,034 shares of common stock outstanding, $2.50 par value.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive Proxy Statement for its 2023 Annual Meeting of Shareholders are incorporated by reference into Part III of this Form 10-K.
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TABLE OF CONTENTS
| PART I | ||||||||
| Item 1 — | ||||||||
| Item 1A — | ||||||||
| Item 1B — | ||||||||
| Item 2 — | ||||||||
| Item 3 — | ||||||||
| Item 4 — | ||||||||
| PART II | ||||||||
| Item 5 — | ||||||||
| Item 6 — | ||||||||
| Item 7 — | ||||||||
| Item 7A — | ||||||||
| Item 8 — | ||||||||
| Item 9 — | ||||||||
| Item 9A — | ||||||||
| Item 9B — | ||||||||
| Item 9C — | ||||||||
| PART III | ||||||||
| Item 10 — | ||||||||
| Item 11 — | ||||||||
| Item 12 — | ||||||||
| Item 13 — | ||||||||
| Item 14 — | ||||||||
| PART IV | ||||||||
| Item 15 — | ||||||||
| Item 16 — | ||||||||
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PART I
ITEM 1 — BUSINESS | ||
Definitions of Abbreviations
| Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former) | |||||
| Capital Services | Capital Services, LLC | ||||
| Eloigne | Eloigne Company | ||||
| e prime | e prime inc. | ||||
| NSP-Minnesota | Northern States Power Company, a Minnesota corporation | ||||
| NSP System | The electric production and transmission system of NSP-Minnesota and NSP-Wisconsin operated on an integrated basis and managed by NSP-Minnesota | ||||
| NSP-Wisconsin | Northern States Power Company, a Wisconsin corporation | ||||
| Operating companies | NSP-Minnesota, NSP-Wisconsin, PSCo and SPS | ||||
| PSCo | Public Service Company of Colorado | ||||
| SPS | Southwestern Public Service Co. | ||||
| Utility subsidiaries | NSP-Minnesota, NSP-Wisconsin, PSCo and SPS | ||||
| WGI | WestGas InterState, Inc. | ||||
| WYCO | WYCO Development, LLC | ||||
| Xcel Energy | Xcel Energy Inc. and its subsidiaries | ||||
| Other | |||||
| AFUDC | Allowance for funds used during construction | ||||
| AMT | Alternative minimum tax | ||||
| ALJ | Administrative Law Judge | ||||
| ARO | Asset retirement obligation | ||||
| ASC | Financial Accounting Standards Board Accounting Standards Codification | ||||
| ATM | At-the-market | ||||
| BART | Best available retrofit technology | ||||
| C&I | Commercial and Industrial | ||||
| CapX2020 | Alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest involved in a joint transmission line planning and construction effort | ||||
| CCR | Coal combustion residuals | ||||
| CCR Rule | Final rule (40 CFR 257.50 - 257.107) published by the EPA regulating the management, storage and disposal of CCRs as a nonhazardous waste | ||||
| CDD | Cooling degree-days | ||||
| CEO | Chief executive officer | ||||
| CFO | Chief financial officer | ||||
| CIG | Colorado Interstate Gas Company, LLC | ||||
| CON | Certificate of Need | ||||
| CSPV | Crystalline Silicon Photovoltaic | ||||
| CWIP | Construction work in progress | ||||
| D.C. Circuit | United States Court of Appeals for the District of Columbia Circuit | ||||
| DECON | Decommissioning method where radioactive contamination is removed and safely disposed of at a requisite facility or decontaminated to a permitted level | ||||
| DRIP | Dividend Reinvestment Program | ||||
| EEI | Edison Electric Institute | ||||
| EIP | Energy Impact Partners | ||||
| EMANI | European Mutual Association for Nuclear Insurance | ||||
| EPS | Earnings per share | ||||
| ETR | Effective tax rate | ||||
| FTR | Financial transmission right | ||||
| GAAP | Generally accepted accounting principles | ||||
| GE | General Electric | ||||
| GHG | Greenhouse gas | ||||
| HDD | Heating degree-days | ||||
| INPO | Institute of Nuclear Power Operations | ||||
| IPP | Independent power producing entity | ||||
| IRA | Inflation Reduction Act | ||||
| ISO | Independent System Operator | ||||
| ITC | Investment Tax Credit | ||||
| LP&L | Lubbock Power & Light | ||||
| MEC | Mankato Energy Center | ||||
| MGP | Manufactured gas plant | ||||
| MISO | Midcontinent Independent System Operator, Inc. | ||||
| Native load | Demand of retail and wholesale customers that a utility has an obligation to serve under statute or contract | ||||
| NAV | Net asset value | ||||
| NEIL | Nuclear Electric Insurance Ltd. | ||||
| NOL | Net operating loss | ||||
| NOPR | Notice of proposed rulemaking | ||||
| NOx | Nitrogen Oxides | ||||
| O&M | Operating and maintenance | ||||
| OATT | Open Access Transmission Tariff | ||||
| PFAS | Per- and PolyFluoroAlkyl Substances | ||||
| PI | Prairie Island nuclear generating plant | ||||
| Post-65 | Post-Medicare | ||||
| PPA | Purchased power agreement | ||||
| Pre-65 | Pre-Medicare | ||||
| PTC | Production tax credit | ||||
| REC | Renewable energy credit | ||||
| RFP | Request for proposal | ||||
| ROE | Return on equity | ||||
| ROU | Right-of-use | ||||
| RTO | Regional Transmission Organization | ||||
| S&P | Standard & Poor’s Global Ratings | ||||
| SERP | Supplemental executive retirement plan | ||||
SO2 | Sulfur dioxide | ||||
| SPP | Southwest Power Pool, Inc. | ||||
| TCA | Transmission cost adjustment | ||||
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| TCJA | 2017 federal tax reform enacted as Public Law No: 115-97, commonly referred to as the Tax Cuts and Jobs Act | ||||
| THI | Temperature-humidity index | ||||
| TO | Transmission owner | ||||
| TSR | Total shareholder return | ||||
| VaR | Value at Risk | ||||
| VIE | Variable interest entity | ||||
| WACC | Weighted Average Cost of Capital | ||||
| Measurements | |||||
| Bcf | Billion cubic feet | ||||
| KV | Kilovolts | ||||
| KWh | Kilowatt hours | ||||
| MMBtu | Million British thermal units | ||||
| MW | Megawatts | ||||
| MWh | Megawatt hours | ||||
Where to Find More Information | ||
Xcel Energy’s website address is www.xcelenergy.com. Xcel Energy makes available through its website, free of charge, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after the reports are electronically filed with or furnished to the SEC.
The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically at http://www.sec.gov. The information on Xcel Energy’s website is not a part of, or incorporated by reference in, this annual report on Form 10-K. Xcel Energy intends to make future announcements regarding Company developments and financial performance through its website, www.xcelenergy.com, as well as through press releases, filings with the SEC, conference calls and webcasts.
Forward-Looking Statements | ||
Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including those relating to 2023 EPS guidance, long-term EPS and dividend growth rate objectives, future sales, future expenses, future tax rates, future operating performance, estimated base capital expenditures and financing plans, projected capital additions and forecasted annual revenue requirements with respect to rider filings, expected rate increases to customers, expectations and intentions regarding regulatory proceedings, and expected impact on our results of operations, financial condition and cash flows of resettlement calculations and credit losses relating to certain energy transactions, as well as assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2022 (including risk factors listed from time to time by Xcel Energy Inc. in reports filed with the SEC, including “Risk Factors” in Item 1A of this Annual Report on Form 10-K), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: operational safety, including our nuclear generation facilities and other utility operations; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices and fuel costs; qualified employee work force and third-party contractor factors; violations of our Codes of Conduct; our ability to recover costs and our subsidiaries’ ability to recover costs from customers; changes in regulation; reductions in our credit ratings and the cost of maintaining certain contractual relationships; general economic conditions, including recessionary conditions, inflation rates, monetary fluctuations, supply chain constraints and their impact on capital expenditures and/or the ability of Xcel Energy Inc. and its subsidiaries to obtain financing on favorable terms; availability or cost of capital; our customers’ and counterparties’ ability to pay their debts to us; assumptions and costs relating to funding our employee benefit plans and health care benefits; our subsidiaries’ ability to make dividend payments; tax laws; uncertainty regarding epidemics, the duration and magnitude of business restrictions including shutdowns (domestically and globally), the potential impact on the workforce, including shortages of employees or 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; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; seasonal weather patterns; changes in environmental laws and regulations; climate change and other weather events; natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; costs of potential regulatory penalties; regulatory changes and/or limitations related to the use of natural gas as an energy source; challenging labor market conditions and our ability to attract and retain a qualified workforce; and our ability to execute on our strategies or achieve expectations related to environmental, social and governance matters including as a result of 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.
Overview | ||
Xcel Energy (the “Company”) is a major U.S. regulated electric and natural gas delivery company headquartered in Minneapolis, Minnesota (incorporated in Minnesota in 1909). The Company serves customers in eight states, including portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin. Xcel Energy provides a comprehensive portfolio of energy-related products and services to approximately 3.8 million electric customers and 2.1 million natural gas customers through four utility subsidiaries (i.e., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS). Along with the utility subsidiaries, the transmission-only subsidiaries, WYCO (a joint venture formed with CIG to develop and lease natural gas pipelines, storage and compression facilities) and WGI (an interstate natural gas pipeline company) comprise the regulated utility operations. The Company’s nonregulated subsidiaries include Eloigne, Capital Services, Venture Holdings and Nicollet Project Holdings.
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| Subsidiary / Affiliate | Function | |||||||
| NSP-Minnesota | Electric & Gas | |||||||
| NSP-Wisconsin | Electric & Gas | |||||||
| PSCo | Electric & Gas | |||||||
| SPS | Electric | |||||||
| WGI | Interstate gas pipeline | |||||||
| WYCO | Gas storage and transportation | |||||||
| Other Subsidiaries | See Note 1 to the consolidated financial statements for further information | |||||||
| Utility Subsidiary Overview | ||||||||
| Electric customers | 3.8 million | |||||||
| Natural gas customers | 2.1 million | |||||||
| Total assets | $61.1 billion | |||||||
| Electric generating capacity | 20,897 MW | |||||||
| Natural gas storage capacity | 53.5 Bcf | |||||||
| Electric transmission lines (conductor miles) | 110,000 miles | |||||||
| Electric distribution lines (conductor miles) | 213,000 miles | |||||||
| Natural gas transmission lines | 2,200 miles | |||||||
| Natural gas distribution lines | 37,000 miles | |||||||
| Service Territory | |||||||||||
Strategy | ||
Xcel Energy’s vision is to be the preferred and trusted provider of the energy our customers need. We will deliver on this vision while offering a competitive total return to shareholders. Our mission is to provide our customers with safe, clean, reliable energy services they want and value at a competitive price.
We execute on our vision and mission through three strategic priorities.
| LEAD THE CLEAN ENERGY TRANSITION | ENHANCE THE CUSTOMER EXPERIENCE | KEEP BILLS LOW | ||||||
Our employees are guided by our four corporate values: Connected, Committed, Safe, and Trustworthy.
Our values, culture and Code of Conduct serve as the foundation upon which Xcel Energy’s Board of Directors, employees, contractors and suppliers approach their work in delivering on our three strategic priorities.
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Our sustainability and Environmental, Social and Governance commitments are summarized as follows:
(1)Spans natural gas supply, delivery and customer use.
(2)Includes the Xcel Energy fleet; zero-carbon fuel is electricity or other clean energy.
Deliver a Competitive Total Return to Investors
Successful strategy execution, along with our disciplined approach to growth, operations and management of environmental, social and governance issues, positions us to continue delivering a competitive TSR.
We have consistently achieved our financial objectives, meeting or exceeding our initial earnings guidance range for 18 consecutive years and delivering dividend growth for 19 consecutive years.
Over the past five years, GAAP earnings per share have grown by 7.1% annually and our annual dividend growth was 6.3%. Xcel Energy works to maintain senior secured debt credit ratings in the A range and senior unsecured debt credit ratings in the BBB+ to A range. Current ratings are consistent with this goal.
LEAD THE CLEAN ENERGY TRANSITION
For nearly two decades, Xcel Energy has proactively managed the risk of climate change and worked to meet increasing demand for cleaner energy.
Carbon-free Electricity by 2050
In 2018, Xcel Energy became the first U.S. utility to establish a carbon-free vision, targeting 100% carbon-free electricity by 2050 with an interim goal to reduce carbon emissions 80% by 2030 (from 2005 levels), including owned and purchased power. A lead author for the climate change scientific analysis issued by the Intergovernmental Panel on Climate Change confirmed that our vision aligns with science-based scenarios likely to limit global warming to 1.5 degrees Celsius from pre-industrial levels.
Goal includes owned and purchased power.
The pace of achieving a carbon-free vision is governed by reliability and customer affordability. Our approved resource plans outline a clear, transparent path for reducing carbon emissions 80% using current technologies, while maintaining customer bill increases at or below the rate of inflation. Moving from 80% carbon reduction to 100% carbon-free electricity will require new dispatchable technologies that are economically viable, as well as supportive public policy.
See Item 1A for risks and uncertainties related to strategic and sustainability goals and objectives.
Through 2022, we reduced carbon emissions from generation serving customers by an estimated 53% (from 2005 levels) and remain on track to achieve 80% carbon reduction by 2030.
Xcel Energy will be coal-free by year-end 2030, pending the approval of the proposed acceleration of the Tolk coal plant retirement to 2028. As we transition to clean energy, service reliability is a priority. Xcel Energy was ranked in the top quartile for customer reliability as determined in the 2022 Institute of Electrical and Electronics Engineers Annual Benchmarking Study.
Xcel Energy’s wind capacity is now over 11,000 MW, including nearly 4,500 MW of owned wind. Our fleet continues to demonstrate high wind availability with 2022 performance at approximately 97%, while saving customers over $3 billion in fuel related costs and PTCs since 2017.In 2022, Minnesota and Colorado commissions approved resource plans that will add nearly 10,000 MW of utility-scale renewable energy to our systems.
Beyond carbon emissions, we have significantly reduced other emissions and environmental impacts. Notable environmental improvements include:
*Reductions in water consumption are from owned and purchased electricity that serves our customers. All other reductions are from owned generating plants.
**Coal ash and water consumption data are as of 2021.
As we prepare for early coal plant retirements, employees are provided advanced notice and offered retraining and relocation opportunities. To date, we have been successful in avoiding lay offs associated with our early coal plant retirements. We also help foster economic development opportunities to offset community economic impacts associated with coal plant closures. Xcel Energy has a long track record of working with our communities on energy, climate and environmental initiatives that impact them and has publicly committed to furthering environmental justice.
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Significant transmission expansion will also be required to enable the clean energy transition, and Xcel Energy is already investing towards its goals. For example, our $2 billion Pathway project in Colorado will provide over 560 miles of transmission lines and enable nearly 5,500 MW of new renewable energy. In addition, as part of MISO’s planned transmission expansion over the next decade, Xcel Energy has been awarded $1.2 billion of projects as part of Tranche 1.
Natural Gas Use in Buildings – Net Zero GHG by 2050
In 2021, we committed to reduce GHG emissions 25% by 2030 (from 2020 levels) and provide net-zero natural gas service by 2050 from the supply, distribution and end-use of natural gas. Similar to our electric plan, our vision to deliver gas service with net-zero emissions by 2050 aligns with science-based scenarios likely to limit warming by 1.5 C.
Our net-zero natural gas strategy includes:
•Working with suppliers to purchase only low emissions gas supply by 2030.
•Operating the cleanest possible system to achieve net-zero methane emissions on the system by 2030.
•Offering customer options that promote conservation, encourage electrification, where beneficial, and incorporate clean fuels such as hydrogen and renewable natural gas.
•Applying high quality carbon offsets through projects that remove emissions from other parts of the economy while providing additional environmental and social benefit.
Electrification of the Transportation Sector
In addition to transitioning our own generation fleet, we are helping to decarbonize other sectors, starting with transportation. We aim to enable one out of five vehicles in our service areas to be electric by 2030, representing a nearly $2 billion investment, 0.6% to 0.7% incremental annual retail sales growth and avoidance of roughly 5 million tons of CO2 emissions annually. By 2050, our vision is to run all vehicles in our service area with carbon-free electricity or other clean energy. We have launched new products and services across our service territories. In addition, we have an approved, transportation electrification plan in Colorado and comprehensive transportation plans in Minnesota and Wisconsin that are pending commission approval.
Innovation and Policy
Passage of the IRA is expected to reduce the cost of renewables for our customers, improve the competitiveness of our renewable projects and improve liquidity and credit metrics. The IRA is expected to reduce the cost of future wind projects by 50-60% and solar projects by 25-40% (levelized cost of energy basis). The IRA also lowers the costs of hydrogen production that could be used for generation and the natural gas system. Finally, the IRA is likely to provide customers additional benefits from PTCs for the generation of electricity from our nuclear fleet.
New and emerging technologies are foundational to fulfilling our strategic priorities. Advancement of economical, resilient and reliable zero-carbon 24/7 power technologies, as well as advanced storage and new low-carbon fuels, are needed to deliver on our clean energy goals by 2050.
We actively monitor and participate in emerging and advanced energy technologies through collaborations with researchers, technology developers, venture investors and others in our industry. We have several initiatives, pilots and demonstration projects underway that are advancing and testing the real-world applications of cutting-edge technologies. Our recently announced partnership with Form Energy to develop two 10 MW, 100-hour energy storage pilot projects is an example.
ENHANCE THE CUSTOMER EXPERIENCE
Xcel Energy has a comprehensive suite of renewable and conservation programs that provide customers with clean energy options and help keep their bills low. We are also transforming and expanding our electric grid to accommodate load growth, renewable energy and distributed energy resources. We are in the process of installing smart meters, which will deliver numerous customer and operational benefits, providing near-real-time communication, allowing customers to know how much energy they are using and what it will cost them. Along with the smart meters, customers will have new digital tools to make it easier to access their energy information, gain useful insights to better understand and manage their energy use and make smarter energy choices that lower their bills.
KEEP BILLS LOW
Customer affordability is critical to successful strategy execution. From 2013 - 2022, we have kept residential electric bill growth to 1.8% per year and below the rate of inflation. Residential gas bills were near flat, growing 0.3% per year from 2013 - 2021. Global pressures on natural gas prices increased customer natural gas bills in 2022. We pass the cost of natural gas directly to customers (without markup) through fuel clauses in most of our states, and higher gas prices affected the affordability of the service we provide.
We have taken several steps to address this concern:
•Low-income customers are eligible to receive assistance with their bills. In 2022, we set a company record for energy assistance outreach as 193,000 customers were connected to programs that provided $216 million in funding.
•Xcel Energy has invested more than $2 billion over the past decade in a comprehensive suite of electric and natural gas conservation programs.
•We also kept O&M expenses flat from 2014 through 2021. While O&M increased in 2022 due to global inflation pressures and other drivers, our goal is to reduce 2023 O&M expenses 2% from 2022 levels and keep them relatively flat thereafter.
•We continue to invest to reduce operating costs through ongoing process and technology improvements, including the use of drone technologies, automated work processes, artificial intelligence and continuous improvement methodologies.
•In addition, we are augmenting our One Xcel Energy Way program in 2023, which we expect to drive increased productivity and efficiency across all levels of the Company.
•As previously discussed, our geographic advantages in wind and solar also enable customer savings, which we call our “Steel for Fuel” strategy. High capacity factors, coupled with renewable tax credits and avoided fuel costs, enable Xcel Energy to add renewable energy while saving customers money.
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REACHING OUR GOALS RESPONSIBLY
We instituted oversight of environmental performance by the Board of Directors beginning in 2000 and was among the first U.S. energy providers to tie carbon reduction to executive compensation over fifteen years ago.
Xcel Energy has provided a voluntary, third-party verified annual GHG disclosure since 2005, longer than any other U.S. utility. We are a founding member of The Climate Registry and a supporter of the Task Force on Climate-Related Financial Disclosures. Our disclosures also align with the Global Reporting Initiative, Sustainability Accounting Standards Board and United Nations Sustainable Development Goals frameworks.
STRENGTHEN OUR COMMUNITIES
We provide a fundamental service, powering communities with safe, reliable, affordable and increasingly clean energy.
For our local communities, we initiated 40 economic development projects in 2022, which are projected to create over $1.8 billion in capital investments and 2,900 jobs. Additionally, nearly 60% of our supply chain spend was local and we spent approximately $550 million with diverse suppliers.
Our employees served on more than 520 nonprofit organization or local community boards in 2022. The Xcel Energy Foundation contributed $4.4 million to 426 nonprofit organizations that support its three charitable giving focus areas: STEM Career Pathways, Environmental Sustainability, and Community Vitality.
The Foundation, Company, employees and retirees also contributed more than $5 million to local communities through Xcel Energy’s annual United Way Giving Campaign and nearly 3,000 volunteers participated in Xcel Energy’s annual Day of Service, supporting more than 100 nonprofit projects.
VALUE PEOPLE AND OPERATE WITH INTEGRITY
Champion Safety
Continuously elevating the quality and safety of the workplace is a top priority. We are considered a benchmark company for our Safety Always approach, focused on eliminating life-altering injuries through a trusted, transparent culture and the use of critical controls. All employees have “stop work authority” and are expected to keep each other, our customers and the public safe. Employees are encouraged to speak up, share experiences and learn from events to help protect themselves, their coworkers and the public.
The Board of Directors has oversight for employee and public safety through the Operations, Nuclear, Environmental and Safety committee, both of which are also tied to annual incentive compensation.
Cultivate a Diverse, Best-in-Class Workforce
We aim to create an inclusive culture where employees are treated equitably, and diversity is not only accepted but celebrated. This starts with our Board of Directors.
The Board of Directors oversees our workforce strategy, including diversity and inclusion initiatives. In 2021, Xcel Energy added an incentive-based metric focused on diverse interview panels, executive sponsorship and employee feedback on inclusion in the workplace. A total of 70% of annual incentive pay was tied to safety, system reliability and diversity, equity and inclusion metrics.
Management continuously evaluates benefits to maintain a market-competitive, performance-based, shareholder-aligned total rewards package that supports our ability to attract, engage and retain a talented and diverse workforce, while reinforcing and rewarding strong performance.
We partner with educational and community organizations to attract and hire diverse employees who reflect the communities we serve and live our values. Xcel Energy had 11,982 full-time employees and workforce demographics as of December 2022 were as follows:
| Female | Ethnically Diverse | |||||||
| Board of Directors | 33 | % | 17 | % | ||||
| CEO direct reports | 33 | 22 | ||||||
| Management | 25 | 12 | ||||||
| Employees | 24 | 18 | ||||||
| New hires | 35 | 24 | ||||||
| Interns (hired throughout 2022) | 32 | 25 | ||||||
To help foster a culture of inclusivity, we offer leaders and employees training on microinequities and unconscious bias. The Company hosts 12 business resource groups to support employee interests and obtain diverse perspectives when solving challenges and achieving goals.
Xcel Energy also respects employees’ freedom of association and their right to collectively organize. As of Dec. 31, 2022, approximately 42% of our employees (5,087) were covered by collective bargaining agreements.
Employee turnover for 2022 and future projected retirement eligibility:
| Employee Turnover | Retirement Eligibility | |||||||||||||
| Bargaining | 7 | % | Within next 5 years | 24 | % | |||||||||
| Non-Bargaining | 15 | Within next 10 years | 35 | |||||||||||
Overall (a) | 11 | |||||||||||||
(a)24% of turnover was due to retirements.
We have publicly confirmed our commitment to the advancement and protection of human rights, consistent with U.S. human rights laws and the general principles in the International Labour Organization Conventions.
Annual Code of Conduct training is required for all employees and the Board of Directors.
We do not tolerate Code of Conduct violations or other unacceptable behaviors. We expect and offer employees multiple avenues to raise concerns or report wrong-doing and do not permit any retaliation.
Xcel Energy received the following recognitions in 2022:
 |  |  |  | ||||||||
| Fortune | Human Rights Campaign | Ethisphere | GI Jobs | ||||||||
| World’s Most Admired Companies | Best Places to Work for LGBTQ Equality | World’s Most Ethical Companies | Military Friendly Employer | ||||||||
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Utility Subsidiaries
NSP-Minnesota | |||||||||||||||||
 | |||||||||||||||||
| Electric customers | 1.5 million | NSP-Minnesota conducts business in Minnesota, North Dakota and South Dakota and has electric operations in all three states including the generation, purchase, transmission, distribution and sale of electricity. NSP-Minnesota and NSP-Wisconsin electric operations are managed on the NSP System. NSP-Minnesota also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas in Minnesota and North Dakota. | |||||||||||||||
| Natural gas customers | 0.5 million | ||||||||||||||||
| Total assets | $23.7 billion | ||||||||||||||||
| Rate Base (estimated) | $15.1 billion | ||||||||||||||||
| ROE (net income / average stockholder's equity) | 8.76% | ||||||||||||||||
| Electric generating capacity | 8,949 MW | ||||||||||||||||
| Gas storage capacity | 17.1 Bcf | ||||||||||||||||
| Electric transmission lines (conductor miles) | 33,000 miles | ||||||||||||||||
| Electric distribution lines (conductor miles) | 82,000 miles | ||||||||||||||||
| Natural gas transmission lines | 78 miles | ||||||||||||||||
| Natural gas distribution lines | 11,000 miles | ||||||||||||||||
NSP-Wisconsin | |||||||||||||||||
 | |||||||||||||||||
| Electric customers | 0.3 million | NSP-Wisconsin conducts business in Wisconsin and Michigan and generates, transmits, distributes and sells electricity. NSP-Minnesota and NSP-Wisconsin electric operations are managed on the NSP System. NSP-Wisconsin also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas. | |||||||||||||||
| Natural gas customers | 0.1 million | ||||||||||||||||
| Total assets | $3.4 billion | ||||||||||||||||
| Rate Base (estimated) | $2.1 billion | ||||||||||||||||
| ROE (net income / average stockholder's equity) | 10.57% | ||||||||||||||||
| Electric generating capacity | 548 MW | ||||||||||||||||
| Gas storage capacity | 4.3 Bcf | ||||||||||||||||
| Electric transmission lines (conductor miles) | 12,000 miles | ||||||||||||||||
| Electric distribution lines (conductor miles) | 28,000 miles | ||||||||||||||||
| Natural gas transmission lines | 3 miles | ||||||||||||||||
| Natural gas distribution lines | 3,000 miles | ||||||||||||||||
PSCo | |||||||||||||||||
 | |||||||||||||||||
| Electric customers | 1.6 million | PSCo conducts business in Colorado and generates, purchases, transmits, distributes and sells electricity. PSCo also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas. | |||||||||||||||
| Natural gas customers | 1.5 million | ||||||||||||||||
| Total assets | $23.6 billion | ||||||||||||||||
| Rate Base (estimated) | $14.9 billion | ||||||||||||||||
| ROE (net income / average stockholder's equity) | 8.23% | ||||||||||||||||
| Electric generating capacity | 6,151 MW | ||||||||||||||||
| Gas storage capacity | 32.1 Bcf | ||||||||||||||||
| Electric transmission lines (conductor miles) | 25,000 miles | ||||||||||||||||
| Electric distribution lines (conductor miles) | 79,000 miles | ||||||||||||||||
| Natural gas transmission lines | 2,000 miles | ||||||||||||||||
| Natural gas distribution lines | 24,000 miles | ||||||||||||||||
| SPS | |||||||||||||||||
 | |||||||||||||||||
SPS conducts business in Texas and New Mexico and generates, purchases, transmits, distributes and sells electricity. | |||||||||||||||||
| Electric customers | 0.4 million | ||||||||||||||||
| Total assets | $9.7 billion | ||||||||||||||||
| Rate Base (estimated) | $6.7 billion | ||||||||||||||||
| ROE (net income / average stockholder's equity) | 9.36% | ||||||||||||||||
| Electric generating capacity | 5,249 MW | ||||||||||||||||
| Electric transmission lines (conductor miles) | 41,000 miles | ||||||||||||||||
| Electric distribution lines (conductor miles) | 24,000 miles | ||||||||||||||||
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Operations Overview | ||
Utility operations are generally conducted as either electric or gas utilities in our four utility subsidiaries.
Electric Operations | ||
Electric operations consist of energy supply, generation, transmission and distribution activities across all four operating companies. Xcel Energy had electric sales volume of 116,885 (millions of KWh), 3.8 million customers and electric revenues of $12,123 million for 2022.
| Electric Operations (percentage of total) | Sales Volume | Number of Customers | Revenues | |||||||||||||||||
| Residential | 23 | % | 86 | % | 29 | % | ||||||||||||||
| C&I | 55 | 12 | 48 | |||||||||||||||||
| Other | 22 | 2 | 23 | |||||||||||||||||
Retail Sales/Revenue Statistics (a)
| 2022 | 2021 | |||||||||||||
| KWh sales per retail customer | 24,285 | 23,968 | ||||||||||||
| Revenue per retail customer | $ | 2,513 | $ | 2,405 | ||||||||||
| Residential revenue per KWh | 13.41 | ¢ | 12.94 | ¢ | ||||||||||
| C&I revenue per KWh | 9.02 | ¢ | 8.73 | ¢ | ||||||||||
| Total retail revenue per KWh | 10.35 | ¢ | 10.03 | ¢ | ||||||||||
(a) See Note 6 to the consolidated financial statements for further information.
Owned and Purchased Energy Generation — 2022
Electric Energy Sources
Total electric energy generation by source for the year ended Dec. 31:
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Carbon-Free
Xcel Energy’s carbon-free energy portfolio includes wind, nuclear, hydroelectric, biomass and solar power from both owned generation facilities and PPAs. Carbon-free percentages will vary year-over-year based on system additions, commodity costs, weather, system demand and transmission constraints.
See Item 2 — Properties for further information.
Wind
Owned — Owned and operated wind farms with corresponding capacity:
| Utility Subsidiary | 2022 | 2021 | ||||||||||||||||||||||||
| Wind Farms | Capacity (MW) (a) | Wind Farms | Capacity (MW) (b) | |||||||||||||||||||||||
| NSP System | 16 | 2,352 | 14 | 2,031 | ||||||||||||||||||||||
| PSCo | 2 | 1,059 | 2 | 1,059 | ||||||||||||||||||||||
| SPS | 2 | 984 | 2 | 984 | ||||||||||||||||||||||
| Total | 20 | 4,395 | 18 | 4,074 | ||||||||||||||||||||||
(a) Summer 2022 net dependable capacity.
(b) Summer 2021 net dependable capacity.
PPAs — Number of PPAs with capacity range:
| Utility Subsidiary | 2022 | 2021 | ||||||||||||||||||||||||
| PPAs | Range (MW) | PPAs | Range (MW) | |||||||||||||||||||||||
| NSP System | 129 | 1 — 206 | 128 | 1 — 206 | ||||||||||||||||||||||
| PSCo | 17 | 23 — 301 | 17 | 23 — 301 | ||||||||||||||||||||||
| SPS | 17 | 1 — 250 | 17 | 1 — 250 | ||||||||||||||||||||||
Capacity — Wind capacity (MW) for owned wind farms and PPAs:
| Utility Subsidiary | 2022 | 2021 | ||||||||||||
| NSP System | 4,515 | 3,997 | ||||||||||||
| PSCo | 4,082 | 4,085 | ||||||||||||
| SPS | 2,548 | 2,548 | ||||||||||||
Average Cost (Owned) — Average cost per MWh of wind energy from owned generation:
| Utility Subsidiary | 2022 | 2021 | ||||||||||||
| NSP System | $ | 18 | $ | 25 | ||||||||||
| PSCo | 11 | 17 | ||||||||||||
| SPS | 13 | 17 | ||||||||||||
Average Cost (PPAs) — Average cost per MWh of wind energy under existing PPAs:
| Utility Subsidiary | 2022 | 2021 | ||||||||||||
| NSP System | $ | 37 | $ | 37 | ||||||||||
| PSCo | 38 | 35 | ||||||||||||
| SPS | 27 | 27 | ||||||||||||
Wind Development — Xcel Energy placed into service, repowered, or contracted for the following during 2022:
| Project | Utility Subsidiary | Capacity (MW) | |||||||||||||||
| Dakota Range | NSP-Minnesota | 298 | (a)(b) | ||||||||||||||
| Nobles Repower | NSP-Minnesota | 200 | (a)(b) | ||||||||||||||
| Rock Aetna | NSP-Minnesota | 20 | (a)(b) | ||||||||||||||
| Various PPAs | Various | 220 | (c) | ||||||||||||||
(a) Summer 2022 net dependable capacity.
(b) Values disclosed are the maximum generation levels. Capacity is attainable only when wind conditions are sufficiently available.
(c) Based on contracted capacity.
Xcel Energy currently has approximately 550 MW of owned wind under development or being repowered.
| Project | Utility Subsidiary | Capacity (MW) | Estimated Completion | ||||||||||||||||||||
| Northern Wind | NSP-Minnesota | 100 | 2023 | (a) | |||||||||||||||||||
| Grand Meadow Repower | NSP-Minnesota | 100 | 2023 | ||||||||||||||||||||
| Border Winds Repower | NSP-Minnesota | 150 | 2025 | ||||||||||||||||||||
| Pleasant Valley Repower | NSP-Minnesota | 200 | 2025 | ||||||||||||||||||||
(a)Placed in service in January 2023.
Solar
PPAs — Solar PPAs capacity by type:
| Type | Utility Subsidiary | Capacity (MW) | ||||||||||||
| Distributed Generation | NSP System | 1,074 | ||||||||||||
| Utility-Scale | NSP System | 269 | ||||||||||||
| Distributed Generation | PSCo | 848 | ||||||||||||
| Utility-Scale | PSCo | 732 | ||||||||||||
| Distributed Generation | SPS | 20 | ||||||||||||
| Utility-Scale | SPS | 192 | ||||||||||||
| Total | 3,135 | |||||||||||||
Average Cost (PPAs) — Average cost per MWh of solar energy under existing PPAs:
| Utility Subsidiary | 2022 | 2021 | ||||||||||||
| NSP System | $ | 79 | $ | 90 | ||||||||||
| PSCo | 69 | 67 | ||||||||||||
| SPS | 62 | 61 | ||||||||||||
Solar Development — In September 2022, the MPUC approved NSP-Minnesota's proposal to add 460 MW of solar facilities at the Sherco site. The project is expected to cost approximately $690 million (two phases to be completed in 2024 and 2025). As a result of the IRA, the levelized cost of the project is expected to be approximately 30% lower than previously estimated.
PSCo placed approximately 200 MW of PPAs into service during 2022 and expects to place approximately 800 MW (including storage) of PPAs into service during 2023.
Nuclear
Xcel Energy has two nuclear plants with approximately 1,700 MW of total 2022 net summer dependable capacity that serve the NSP System. Our nuclear fleet has become one of the best performing and dependable in the nation, as rated by both the NRC and INPO. Xcel Energy secures contracts for uranium concentrates, uranium conversion, uranium enrichment and fuel fabrication to operate its nuclear plants. We use varying contract lengths as well as multiple producers for uranium concentrates, conversion services and enrichment services to minimize potential impacts caused by supply interruptions due to geographical and world political issues.
Nuclear Fuel Cost — Delivered cost per MMBtu of nuclear fuel consumed for owned electric generation and the percentage of total fuel requirements (nuclear, natural gas and coal):
| Utility Subsidiary | Nuclear | |||||||||||||
| NSP System | Cost | Percent | ||||||||||||
| 2022 | $ | 0.76 | 51 | % | ||||||||||
| 2021 | 0.77 | 50 | ||||||||||||
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Other — Xcel Energy’s other carbon-free energy portfolio includes hydro from owned generating facilities.
See Item 2 — Properties for further information.
Fossil Fuel
Xcel Energy’s fossil fuel energy portfolio includes coal and natural gas power from both owned generating facilities and PPAs.
Coal
Xcel Energy owns and operates coal units with approximately 6,200 MW of total 2022 net summer dependable capacity, which provided 23% of Xcel Energy’s energy mix in 2022.
Xcel Energy has plans to retire all of its existing coal generation by the end of 2030. Approved early coal plant retirements:
| Year | Utility Subsidiary | Plant Unit | Capacity (MW) | ||||||||||||||||||||
| 2023 | NSP-Minnesota | Sherco 2 | 682 | ||||||||||||||||||||
| 2024 | SPS | Harrington (a) | 1,018 | ||||||||||||||||||||
| 2025 | PSCo | Comanche 2 | 335 | ||||||||||||||||||||
| 2025 | PSCo | Craig 1 | 42 | (b) | |||||||||||||||||||
| 2025 | PSCo | Pawnee (c) | 505 | ||||||||||||||||||||
| 2026 | NSP-Minnesota | Sherco 1 | 680 | ||||||||||||||||||||
| 2027 | PSCo | Hayden 2 | 98 | (b) | |||||||||||||||||||
| 2028 | PSCo | Hayden 1 | 135 | (b) | |||||||||||||||||||
| 2028 | PSCo | Craig 2 | 40 | (b) | |||||||||||||||||||
| 2028 | NSP-Minnesota | A.S. King | 511 | ||||||||||||||||||||
| 2030 | NSP-Minnesota | Sherco 3 | 517 | (b) | |||||||||||||||||||
| 2030 | PSCo | Comanche 3 | 500 | (b) | |||||||||||||||||||
| 2034 | SPS | Tolk 1 (d) | 532 | ||||||||||||||||||||
| 2034 | SPS | Tolk 2 (d) | 535 | ||||||||||||||||||||
(a)Reflects expected conversion from coal to natural gas following the TCEQ order that Harrington cease use of coal fuel by Jan. 1, 2025.
(b)Based on Xcel Energy’s ownership interest.
(c)Reflects conversion from coal to natural gas.
(d)Tolk Unit 1 and 2 are approved to be retired early in 2034. SPS proposed to retire both units in 2028 in the pending New Mexico and Texas rate cases.
Coal Fuel Cost — Delivered cost per MMBtu of coal consumed for owned electric generation and the percentage of fuel requirements (nuclear, natural gas and coal):
Coal (a) | ||||||||||||||
| Utility Subsidiary | Cost | Percent | ||||||||||||
| NSP System | ||||||||||||||
| 2022 | $ | 2.27 | 37 | % | ||||||||||
| 2021 | 1.95 | 34 | ||||||||||||
| PSCo | ||||||||||||||
| 2022 | 1.48 | 55 | ||||||||||||
| 2021 | 1.43 | 62 | ||||||||||||
| SPS | ||||||||||||||
| 2022 | 2.37 | 59 | ||||||||||||
| 2021 | 2.07 | 66 | ||||||||||||
(a) Includes refuse-derived fuel and wood for the NSP System.
Natural Gas
Xcel Energy has 23 natural gas plants with approximately 8,100 MW of total 2022 net summer dependable capacity, which provided 24% of Xcel Energy’s mix in 2022.
Natural gas supplies, transportation and storage services for power plants are procured to provide an adequate supply of fuel. Remaining requirements are procured through a liquid spot market. Generally, natural gas supply contracts have variable pricing that is tied to natural gas indices. Natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes or payments in lieu of delivery.
Natural Gas Cost — Delivered cost per MMBtu of natural gas consumed for owned electric generation and the percentage of total fuel requirements (nuclear, natural gas and coal):
| Natural Gas | ||||||||||||||
| Utility Subsidiary | Cost | Percent | ||||||||||||
| NSP System | ||||||||||||||
| 2022 | $ | 7.58 | 12 | % | ||||||||||
2021 (a) | 4.98 | 16 | ||||||||||||
| PSCo | ||||||||||||||
| 2022 | 7.09 | 45 | ||||||||||||
2021 (a) | 8.38 | 38 | ||||||||||||
| SPS | ||||||||||||||
| 2022 | 5.87 | 41 | ||||||||||||
2021 (a) | 6.72 | 34 | ||||||||||||
(a)Reflective of Winter Storm Uri.
Capacity and Demand
Uninterrupted system peak demand and occurrence date:
| System Peak Demand (MW) | ||||||||||||||||||||||||||
| 2022 | 2021 | |||||||||||||||||||||||||
NSP System | 9,245 | June 20 | 8,837 | June 9 | ||||||||||||||||||||||
| PSCo | 6,821 | Sept. 6 | 6,958 | July 28 | ||||||||||||||||||||||
| SPS | 4,280 | July 19 | 4,054 | Aug. 9 | ||||||||||||||||||||||
Transmission
Transmission lines deliver electricity at high voltages and over long distances from power sources to transmission substations closer to customers. A strong transmission system ensures continued reliable and affordable service, ability to meet state and regional energy policy goals, and support for a diverse generation mix, including renewable energy. Xcel Energy owns approximately 110,000 conductor miles of transmission lines, serving 22,000 MW of customer load, across its service territory.
Between 2023 and 2028, Xcel Energy plans to build approximately 1,700 additional conductor miles of transmission lines, primarily as part of the MISO Tranche 1 and Colorado Power Pathway projects.
See Item 2 - Properties for further information.
Distribution
Distribution lines allow electricity to travel at lower voltages from substations directly to customers. Xcel Energy has a vast distribution network, owning and operating approximately 210,000 conductor miles of distribution lines across our eight-state service territory.
To continue providing reliable, affordable electric service and enable more flexibility for customers, we are working to digitize the distribution grid, while at the same time keeping it secure. Xcel Energy plans to invest approximately $1.7 billion implementing new network infrastructure, smart meters, advanced software, equipment sensors and related data analytics capabilities. As of Dec. 31, 2022, Xcel Energy had spent approximately $765 million on these investments.
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Investments of this nature will further improve reliability and reduce outage restoration times for our customers, while at the same time enabling new options and opportunities for increased efficiency savings. The new capabilities will also enable integration of battery storage and other distributed energy resources into the grid, including electric vehicles.
See Item 2 - Properties for further information.
| Natural Gas Operations | ||
Natural gas operations consist of purchase, transportation and distribution of natural gas to end-use residential, C&I and transport customers in NSP-Minnesota, NSP-Wisconsin and PSCo. Xcel Energy had natural gas deliveries of 400,741 (thousands of MMBtu), 2.1 million customers and natural gas revenues of $3,080 million for 2022.
| Natural Gas (percentage of total) | Deliveries | Number of Customers | Revenues | |||||||||||||||||
| Residential | 38 | % | 92 | % | 59 | % | ||||||||||||||
| C&I | 24 | 8 | 32 | |||||||||||||||||
| Transportation and other | 38 | <1 | 9 | |||||||||||||||||
Sales/Revenue Statistics (a)
| 2022 | 2021 | |||||||||||||
| MMBtu sales per retail customer | 116 | 114 | ||||||||||||
| Revenue per retail customer | $ | 1,318 | $ | 917 | ||||||||||
| Residential revenue per MMBtu | 11.97 | 8.61 | ||||||||||||
| C&I revenue per MMBtu | 10.45 | 7.20 | ||||||||||||
| Transportation and other revenue per MMBtu | 1.16 | 1.20 | ||||||||||||
(a)See Note 6 to the consolidated financial statements for further information.
Capability and Demand
Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply).
Maximum daily output (firm and interruptible) and occurrence date:
| 2022 | 2021 | |||||||||||||||||||||||||
| Utility Subsidiary | MMBtu | Date | MMBtu | Date (a) | ||||||||||||||||||||||
| NSP-Minnesota | 867,385 | Feb. 12 | 899,133 | Feb. 11 | ||||||||||||||||||||||
| NSP-Wisconsin | 187,961 | Jan. 6 | 167,656 | Feb. 11 | ||||||||||||||||||||||
| PSCo | 2,243,552 | Dec. 22 | 2,316,283 | Feb. 14 | ||||||||||||||||||||||
(a)Reflective of Winter Storm Uri.
Natural Gas Supply and Cost
Xcel Energy seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio, which increases flexibility, decreases interruption, financial risks and customer rates. In addition, the utility subsidiaries conduct natural gas price hedging activities approved by their states’ commissions.
Average delivered cost per MMBtu of natural gas for regulated retail distribution:
| Utility Subsidiary | 2022 | 2021 (a) | ||||||||||||
| NSP-Minnesota | $ | 7.00 | $ | 7.48 | ||||||||||
| NSP-Wisconsin | 6.68 | 7.11 | ||||||||||||
| PSCo | 6.33 | 6.06 | ||||||||||||
(a)Reflective of Winter Storm Uri.
NSP-Minnesota, NSP-Wisconsin and PSCo have natural gas supply transportation and storage agreements that include obligations for purchase and/or delivery of specified volumes or to make payments in lieu of delivery.
| General | ||
General Economic Conditions
Economic conditions may have a material impact on Xcel Energy’s operating results. Management cannot predict the impact of fluctuating energy or commodity prices, pandemics, terrorist activity, war or the threat of war. We could experience a material impact to our results of operations, future growth or ability to raise capital resulting from a sustained general slowdown in economic growth or a significant increase in interest rates or inflation.
Seasonality
Demand for electric power and natural gas is affected by seasonal differences in the weather. In general, peak sales of electricity occur in the summer months and peak sales of natural gas occur in the winter months. As a result, the overall operating results may fluctuate substantially on a seasonal basis. Additionally, Xcel Energy’s operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.
Competition
Xcel Energy is subject to public policies that promote competition and development of energy markets. Xcel Energy’s industrial and large commercial customers have the ability to generate their own electricity. In addition, customers may have the option of substituting other fuels or relocating their facilities to a lower cost region.
Customers have the opportunity to supply their own power with distributed generation including solar generation and in most jurisdictions can currently avoid paying for most of the fixed production, transmission and distribution costs incurred to serve them.
Several states have incentives for the development of rooftop solar, community solar gardens and other distributed energy resources. Distributed generating resources are potential competitors to Xcel Energy’s electric service business with these incentives and federal tax subsidies.
The FERC has continued to promote competitive wholesale markets through open access transmission and other means. Xcel Energy’s wholesale customers can purchase their output from generation resources of competing suppliers or non-contracted quantities and use the transmission systems of the utility subsidiaries on a comparable basis to serve their native load.
FERC Order No. 1000 established competition for ownership of certain new electric transmission facilities under Federal regulations. Some states have state laws that allow the incumbent a Right of First Refusal to own these transmission facilities.
FERC Order 2222 requires that RTO and ISO markets allow participation of aggregations of distributed energy resources. This order is expected to incentivize distributed energy resource adoption, however implementation is expected to vary by RTO/ISO and the near, medium, and long-term impacts of Order 2222 remain unclear.
Xcel Energy Inc.’s utility subsidiaries have franchise agreements with cities subject to periodic renewal; however, a city could seek alternative means to access electric power or gas, such as municipalization. No municipalization activities are occurring presently.
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While each utility subsidiary faces these challenges, Xcel Energy believes their rates and services are competitive with alternatives currently available.
| Governmental Regulations | ||
Public Utility Regulation
See Item 7 for discussion of public utility regulation.
Environmental Regulation
Our facilities are regulated by federal and state agencies that have jurisdiction over air emissions, water quality, wastewater discharges, solid and hazardous wastes or substances. Certain Xcel Energy activities require registrations, permits, licenses, inspections and approvals from these agencies.
Xcel Energy has received necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. Our facilities strive to operate in compliance with applicable environmental standards and related monitoring and reporting requirements.
However, it is not possible to determine what additional facilities or modifications to existing or planned facilities will be required as a result of changes to regulations, interpretations or enforcement policies or what effect future laws or regulations may have. We may be required to incur expenditures in the future for remediation of historic and current operating sites and other waste treatment, storage and disposal sites.
There are significant environmental regulations to encourage use of clean energy technologies and regulate emissions of GHGs. We have undertaken numerous initiatives to meet current requirements and prepare for potential future regulations, reduce GHG emissions and respond to state renewable and energy efficiency goals. Future environmental regulations may result in substantial costs.
Emerging Environmental Regulation
Clean Air Act — In April 2022, the EPA proposed regulations under the "Good Neighbor" provisions of the Clean Air Act. The proposed rules apply to Minnesota, Texas and Wisconsin. The proposal establishes an allowance trading program for NOx, potentially impacting Xcel Energy fossil fuel generating facilities. Under the proposed rule, facilities without NOx controls will have to secure additional allowances, install NOx controls, or develop a strategy of operations that utilizes the existing allowance allocations. The EPA has indicated that it intends for the rule to be final and applicable in the first half of 2023. While the financial impacts of the proposed regulation are uncertain and dependent on market forces, Xcel Energy anticipates that costs will be approximately $60 million annually and will be recoverable through regulatory mechanisms based on prior state commission practices.
In a June 2022 ruling, the United States Supreme Court held that an economy-wide approach to reducing greenhouse gas emissions from coal-fired power plants was not consistent with the Clean Air Act. Therefore, if the EPA proceeds with new rules, it cannot set a standard based on economy-wide generation shifting to other sources, such as renewable energy. It is anticipated that EPA will propose rules to limit GHG emissions from new and existing coal and natural gas-fired electric generating units in 2023. If any new rules require additional investment, Xcel Energy believes that the cost of these initiatives or replacement generation would be recoverable through rates based on prior state commission practices.
Coal Ash Regulation — In February 2023, the EPA entered into a Consent Decree, committing the agency to either issue new proposed rules by May 5, 2023, to regulate inactive CCR landfills under the CCR Rule for the first time, or to determine no such rules are necessary by that date. If proposed rules are issued in May, the EPA has committed to a May 2024 effective date for the new rules. Until proposed rules are issued, it is not certain what the impact will be on Xcel Energy, but we anticipate that additional inactive ash units could become regulated for the first time. It is also anticipated that the EPA may issue other CCR proposed rules in 2023 that further expand the scope of the CCR Rule.
Emerging Contaminants of Concern — PFAS are man-made chemicals that are widely used in consumer products and can persist and bio-accumulate in the environment. Xcel Energy does not manufacture PFAS but because PFAS are so ubiquitous in products and the environment, it may impact our operations. In September 2022, the EPA proposed to designate two types of PFAS as “hazardous substances” under the Comprehensive Environmental Response, Compensation, and Liability Act, specifically perfluorooctanoic acid and perfluorooctanesulfonic acid. This proposed rule could result in new obligations for investigation and cleanup wherever PFAS are found to be present. The impact the proposed regulation may have on electric and gas utilities is currently uncertain.
Environmental Costs
Environmental costs include amounts for nuclear plant decommissioning and payments for storage of spent nuclear fuel, disposal of hazardous materials and waste, remediation of contaminated sites, monitoring of discharges to the environment and compliance with laws and permits with respect to emissions.
Costs charged to operating expenses for nuclear decommissioning, spent nuclear fuel disposal, environmental monitoring and remediation and disposal of hazardous materials and waste and depreciation of previously incurred capital expenditures for environmental improvements were approximately:
•$365 million in 2022.
•$365 million in 2021.
•$400 million in 2020.
Average annual expense of approximately $430 million from 2023 – 2027 is estimated for similar costs. The precise timing and amount of environmental costs, including those for site remediation and disposal of hazardous materials, are unknown. Additionally, the extent to which environmental costs will be included in and recovered through rates may fluctuate.
Capital expenditures for environmental improvements were approximately:
•$20 million in 2022.
•$60 million in 2021.
•$30 million in 2020.
Certain previously collected nuclear storage costs for the federal nuclear waste program are reimbursed to customers by the federal government as a result of a settlement we pursued regarding the government’s failure to deliver a disposal program. Installments received are reimbursed to customers as approved by the MPUC and other state regulators.
15
Other
Our operations are subject to workplace safety standards under the Federal Occupational Safety and Health Act of 1970 (“OSHA”) and comparable state laws that regulate the protection of worker health and safety. In addition, the Company is subject to other government regulations impacting such matters as labor, competition, data privacy, etc. Based on information to date and because our policies and business practices are designed to comply with all applicable laws, we do not believe the effects of compliance on our operations, financial condition or cash flows are material.
| Capital Spending and Financing | ||
See Item 7 for discussion of capital expenditures and funding sources.
Information about our Executive Officers (a) | ||||||||||||||||||||
| Name | Age (b) | Current and Recent Positions | Time in Position | |||||||||||||||||
| Robert C. Frenzel | 52 | Chairman of the Board of Directors, Xcel Energy Inc. | December 2021 — Present | |||||||||||||||||
| President and Chief Executive Officer and Director, Xcel Energy Inc. | August 2021 — Present | |||||||||||||||||||
| Chief Executive Officer, NSP-Minnesota, NSP-Wisconsin, PSCo, and SPS | August 2021 — Present | |||||||||||||||||||
| President and Chief Operating Officer, Xcel Energy Inc. | March 2020 — August 2021 | |||||||||||||||||||
| Executive Vice President, Chief Financial Officer, Xcel Energy Inc. | May 2016 — March 2020 | |||||||||||||||||||
Senior Vice President and Chief Financial Officer, Luminant, a subsidiary of Energy Future Holdings Corp. (c) | February 2012 — April 2016 | |||||||||||||||||||
| Brett C. Carter | 56 | Executive Vice President, Group President, Utilities, and Chief Customer Officer, Xcel Energy Inc. | March 2022 — Present | |||||||||||||||||
| Executive Vice President and Chief Customer and Innovation Officer, Xcel Energy Inc. | May 2018 — March 2022 | |||||||||||||||||||
| Senior Vice President and Shared Services Executive, Bank of America, an institutional investment bank and financial services company | October 2015 — May 2018 | |||||||||||||||||||
| Patricia Correa | 49 | Senior Vice President, Chief Human Resources Officer, Xcel Energy Inc. | February 2022 — Present | |||||||||||||||||
| Senior Vice President, Human Resources, Eaton Corporation, a power management company | July 2019 — January 2022 | |||||||||||||||||||
| Vice President, Human Resources, Eaton Corporation | March 2016 — July 2019 | |||||||||||||||||||
| Timothy O’Connor | 63 | Executive Vice President, Chief Operations Officer, Xcel Energy Inc. | August 2021 — Present | |||||||||||||||||
| Executive Vice President, Chief Generation Officer, Xcel Energy Inc. | March 2020 — August 2021 | |||||||||||||||||||
| Senior Vice President, Chief Nuclear Officer, Xcel Energy Services Inc | February 2013 — March 2020 | |||||||||||||||||||
| Frank Prager | 60 | Senior Vice President, Strategy, Security and External Affairs and Chief Sustainability Officer, Xcel Energy Inc. | March 2022 — Present | |||||||||||||||||
| Senior Vice President, Strategy, Planning and External Affairs, Xcel Energy Inc. | March 2020 — March 2022 | |||||||||||||||||||
| Vice President, Policy and Federal Affairs, Xcel Energy Services Inc. | January 2015 — March 2020 | |||||||||||||||||||
| Amanda Rome | 42 | Executive Vice President, Chief Legal and Compliance Officer, Xcel Energy Inc. | June 2022 — Present | |||||||||||||||||
| Executive Vice President, General Counsel, Xcel Energy Inc. | June 2020 — June 2022 | |||||||||||||||||||
| Vice President and Deputy General Counsel, Xcel Energy Services Inc. | October 2019 — June 2020 | |||||||||||||||||||
| Managing Attorney, Xcel Energy Services Inc. | July 2018 — October 2019 | |||||||||||||||||||
| Rotational Position, Xcel Energy Services Inc. | January 2018 — July 2018 | |||||||||||||||||||
| Lead Assistant General Counsel, Xcel Energy Services Inc. | July 2015 — January 2018 | |||||||||||||||||||
| Brian J. Van Abel | 41 | Executive Vice President, Chief Financial Officer, Xcel Energy Inc. | March 2020 — Present | |||||||||||||||||
| Senior Vice President, Finance and Corporate Development, Xcel Energy Services Inc. | September 2018 — March 2020 | |||||||||||||||||||
| Vice President, Treasurer, Xcel Energy Services Inc. | July 2015 — September 2018 | |||||||||||||||||||
(a) No family relationships exist between any of the executive officers or directors.
(b)Ages as of Feb. 23, 2023.
(c)In April 2014, Energy Future Holdings Corp., the majority of its subsidiaries, including Texas Competitive Energy Holdings the parent company of Luminant, filed a voluntary bankruptcy petition under Chapter 11 of the United States Bankruptcy Code. Texas Competitive Energy Holdings emerged from Chapter 11 in October 2016.
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ITEM 1A — RISK FACTORS | ||
Xcel Energy 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
The Board of Directors is responsible for the oversight of material risk and maintaining an effective risk monitoring process. Management and the Board of Directors’ committees have responsibility for overseeing the identification and mitigation of key risks and reporting its assessments and activities to the full Board of Directors.
Xcel Energy 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. Xcel Energy 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 Xcel Energy’s 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 key stakeholders 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 Xcel Energy. The Board of Directors assigns oversight of critical risks to each of its four committees to confirm these risks are well understood and given appropriate focus.
The Audit Committee is responsible for reviewing the adequacy of the committees’ risk oversight and affirming appropriate aggregate oversight occurs. Committees regularly report on their oversight activities and certain risk issues may be brought to the full Board of Directors for consideration when deemed appropriate.
Emerging risks are considered and assigned as appropriate during the annual Board of Directors and committee evaluation process, resulting in updates to the committee charters and annual work plans. Additionally, the Board of Directors conducts an annual strategy session where Xcel Energy’s future plans and initiatives are reviewed.
Risks Associated with Our Business
Operational Risks
Our natural gas and electric generation/transmission and distribution operations involve numerous risks that may result in accidents and other operating risks and costs.
Our natural gas transmission and distribution activities include inherent hazards and operating risks, such as leaks, explosions, outages and mechanical problems. Our electric generation, transmission and distribution activities include inherent hazards and operating risks such as contact, fire and outages.
These risks could result in loss of life, significant property damage, environmental pollution, impairment of our operations and substantial financial losses to employees, third-party contractors, customers or the public. We maintain insurance against most, but not all, of these risks and losses.
The occurrence of these events, if not fully covered by insurance, could have a material effect on our financial condition, results of operations and cash flows as well as potential loss of reputation.
Other uncertainties and risks inherent in operating and maintaining Xcel Energy's facilities include, but are not limited to:
•Risks associated with facility start-up operations, such as whether the facility will achieve projected operating performance on schedule and otherwise as planned.
•Failures in the availability, acquisition or transportation of fuel or other supplies.
•Impact of adverse weather conditions and natural disasters, including, tornadoes, icing events, floods and droughts.
•Performance below expected or contracted levels of output or efficiency.
•Availability of replacement equipment.
•Availability of adequate water resources and ability to satisfy water intake and discharge requirements.
•Availability or changes to wind patterns.
•Inability to identify, manage properly or mitigate equipment defects.
•Use of new or unproven technology.
•Risks associated with dependence on a specific type of fuel or fuel source, such as commodity price risk, availability of adequate fuel supply and transportation and lack of available alternative fuel sources.
•Increased competition due to, among other factors, new facilities, excess supply, shifting demand and regulatory changes.
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Additionally, compliance with existing and potential new regulations related to the operation and maintenance of our natural gas infrastructure could result in significant costs. The PHMSA is responsible for administering the DOT’s national regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipelines. The PHMSA continues to develop regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance and emergency response of natural gas pipeline infrastructure. We have programs in place to comply with these regulations and systematically monitor and renew infrastructure over time, however, a significant incident or material finding of non-compliance could result in penalties and higher costs of operations.
Our natural gas and electric transmission and distribution operations are dependent upon complex information technology systems and network infrastructure, the failure of which could disrupt our normal business operations, which could have a material adverse effect on our ability to process transactions and provide services.
Our utility operations are subject to long-term planning and project risks.
Most electric utility investments are planned to be used for decades. Transmission and generation investments typically have long lead times and are planned well in advance of in-service dates and typically subject to long-term resource plans. These plans are based on numerous assumptions such as: sales growth, customer usage, commodity prices, economic activity, costs, regulatory mechanisms, customer behavior, available technology and public policy. Xcel Energy’s long-term resource plan is dependent on our ability to obtain required approvals, develop necessary technical expertise, allocate and coordinate sufficient resources and adhere to budgets and timelines.
In addition, the long-term nature of both our planning processes and our asset lives are subject to risk. The electric utility sector is undergoing significant change (e.g., increases in energy efficiency, wider adoption of distributed generation and shifts away from fossil fuel generation to renewable generation). Customer adoption of these technologies and increased energy efficiency could result in excess transmission and generation resources, downward pressure on sales growth, and potentially stranded costs if we are not able to fully recover costs and investments.
The magnitude and timing of resource additions and changes in customer demand may not coincide with evolving customer preference for generation resources and end-uses, which introduces further uncertainty into long-term planning. Efforts to electrify the transportation and building sectors to reduce GHG emissions may result in higher electric demand and lower natural gas demand over time. Higher electric demand may require us to adopt new technologies and make significant transmission and distribution investments including advanced grid infrastructure, which increases exposure to overall grid instability and technology obsolescence. Evolving stakeholder preference for lower emissions from generation sources and end-uses, like heating, may impact our resource mix and put pressure on our ability to recover capital investments in natural gas generation and delivery. Multiple states may not agree as to the appropriate resource mix, which may lead to costs to comply with one jurisdiction that are not recoverable across all jurisdictions served by the same assets.
We require inputs such as coal, natural gas, uranium and water to cool our facilities. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate.
Our utilities 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 Xcel Energy 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 in most of our states, 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, Xcel Energy 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, the Company cannot fully assure that its controls will be effective against all potential risks. If such programs and procedures are not effective, Xcel Energy’s results of operations, financial condition or cash flows could be materially impacted.
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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.
Xcel Energy 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.
Our subsidiary, NSP-Minnesota, is subject to the risks of nuclear generation.
NSP-Minnesota has two nuclear generation plants, PI and Monticello. Risks of nuclear generation include:
•Hazards associated with the use of radioactive material in energy production, including management, handling, storage and disposal.
•Limitations on insurance available to cover losses that may arise in connection with nuclear operations, as well as obligations to contribute to an insurance pool in the event of damages at a covered U.S. reactor.
•Technological and financial uncertainties related to the costs of decommissioning nuclear plants may cause our funding obligations to change.
The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities, including the ability to impose fines and/or shut down a unit until compliance is achieved. NRC safety requirements could necessitate substantial capital expenditures or an increase in operating expenses. In addition, the INPO reviews NSP-Minnesota’s nuclear operations. Compliance with the INPO’s recommendations could result in substantial capital expenditures or a substantial increase in operating expenses.
If a nuclear incident did occur, it could have a material impact on our results of operations, financial condition or cash flows. Furthermore, non-compliance or the occurrence of a serious incident at other nuclear facilities could result in increased industry regulation, which may increase NSP-Minnesota’s compliance costs.
Financial Risks
Our profitability depends on the ability of our utility subsidiaries to recover their costs and changes in regulation may impair the ability of our utility subsidiaries to recover costs from their 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 utility 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 the utility’s costs incurred in a test year. The utility subsidiaries are subject to both future and historical test years depending upon the regulatory jurisdiction. Thus, the rates a utility is allowed to charge may or may not match its 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 the costs of our utility subsidiaries 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 the ability of our utility subsidiaries to recover costs historically collected from customers, or these subsidiaries 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 our utility subsidiaries will not be able to fully recover their fuel costs from their 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.
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Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.
We cannot be assured that our current credit ratings will remain in effect, or that a rating will not be lowered or withdrawn by a rating agency. Significant events including disallowance of costs, use of historic test years, elimination of riders or interim rates, increasing depreciation lives, lower returns on equity, changes to equity ratios and impacts of tax policy may impact our cash flows and credit metrics, potentially resulting in a change in our credit ratings. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies.
Any credit ratings downgrade could lead to higher borrowing costs or lower proceeds from equity issuances. It could also impact our ability to access capital markets. Also, our utility subsidiaries may enter into contracts that require posting of collateral or settlement if credit ratings fall below investment grade.
We are subject to capital market and interest rate risks.
Utility operations require significant capital investment. As a result, we frequently need to access capital markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital market disruption and financial market distress could prevent us from issuing commercial paper, issuing new securities or cause us to issue securities with unfavorable terms and conditions, such as higher interest rates or lower proceeds from equity issuances. Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results.
The performance of capital markets impacts the value of assets held in trusts to satisfy future obligations to decommission NSP-Minnesota’s nuclear plants and satisfy our defined benefit pension and postretirement benefit plan obligations. These assets are subject to market fluctuations and yield uncertain returns, which may fall below expected returns. A decline in the market value of these assets may increase funding requirements. Additionally, the fair value of the debt securities held in the nuclear decommissioning and/or pension trusts may be impacted by changes in interest rates.
We are subject to credit risks.
Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in our liquidity and an increase in bad debt expense. Credit risk is comprised of numerous factors including the price of products and services provided, the economy and unemployment rates.
Credit risk also includes the risk that counterparties that owe us money or product will become insolvent and may breach their obligations. Should the counterparties fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and incur losses.
Xcel Energy may have direct credit exposure in our short-term wholesale and commodity trading activity to financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties. We may also have some indirect credit exposure due to participation in organized markets, (e.g., MISO, SPP, Electric Reliability Council of Texas and California Independent System Operator), 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.
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 Xcel Energy 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.
We must rely on cash from our subsidiaries to make dividend payments.
Investments in our subsidiaries are our primary assets. Substantially all our operations are conducted by our subsidiaries. Consequently, our operating cash flow and ability to service our debt and pay dividends depends upon the operating cash flows of our subsidiaries and their payment of dividends.
Our subsidiaries are separate legal entities that have no obligation to pay any amounts due pursuant to our obligations or to make any funds available for dividends on our common stock. In addition, each subsidiary’s ability to pay dividends depends on statutory and/or contractual restrictions which may include requirements to maintain minimum levels of equity ratios, working capital or assets.
If the utility subsidiaries were to cease making dividend payments, our ability to pay dividends on our common stock or otherwise meet our financial obligations could be adversely affected. Our utility subsidiaries are regulated by state utility commissions, which possess broad powers to prioritize that the needs of the utility customers are met. We may be negatively impacted by the actions of state commissions that limit the payment of dividends by our utility subsidiaries.
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Federal tax law may significantly impact our business.
Our utility subsidiaries collect 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.
Xcel Energy’s 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.
Our utility subsidiaries face 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 (particularly in Colorado), 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. Xcel Energy 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, shareholders and other individuals.
Xcel Energy’s 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.
Xcel Energy’s 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.
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Our supply chain for procurement of digital equipment and services may expose software or hardware to these risks and could result in a breach or significant costs of remediation. We are unable to quantify the potential impact of cyber security threats or subsequent related actions. Cyber security incidents and regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third-party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.
We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cyber security incidents, including asset failure or unauthorized access to assets or information.
A failure or breach of our technology systems or those of our third-party service providers could disrupt critical business functions and may negatively impact our business, our brand, and our reputation. The cyber security threat is dynamic and evolves continually, and our efforts to prioritize network protection may not be effective given the constant changes to threat vulnerability.
While the Company maintains insurance relating to cybersecurity events, such insurance is subject to a number of exclusions and may be insufficient to offset any losses, costs or damages experienced. Also, the market for cybersecurity insurance is relatively new and coverage available for cybersecurity events is evolving as the industry matures.
Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.
Our electric and natural gas utility businesses are seasonal and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand depends heavily upon weather patterns. A significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of operations or cash flows.
Public Policy Risks
Increased risks of regulatory penalties could negatively impact our business.
The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. FERC can impose penalties of up to $1.5 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Also, the PHMSA, Occupational Safety and Health Administration and other federal agencies have the authority to assess penalties.
In the event of serious incidents, these agencies may pursue penalties. In addition, certain states have the authority to impose substantial penalties. If a serious reliability, cyber or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows.
The continued use of natural gas for both power generation and gas distribution have increasingly become a public policy advocacy target. These efforts may result in a limitation of natural gas as an energy source for both power generation and heating, which could impact our ability to reliably and affordably serve our customers.
In recent years, there have been various local and state agency proposals within and outside our service territories that would attempt to restrict the use and availability of natural gas. If such policies were to prevail, we may be forced to make new resource investment decisions which could potentially result in stranded costs if we are not able to fully recover costs and investments and impact the overall reliability of our service.
Environmental Policy Risks
We may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.
Legislative and regulatory responses related to climate change may create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. International agreements could additionally lead to future federal or state regulations.
In 2015, the United Nations Framework Convention on Climate Change reached consensus among 190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries, with a goal of holding the increase in global average temperature to below 2º Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5º Celsius.
International commitments and agreements could result in future additional GHG reductions in the United States. In addition, in 2023 the EPA intends to publish draft regulations for GHG emissions from the power sector consistent with the agency’s Clean Air Act authorities.
Many states and localities continue to pursue their own climate policies. The steps Xcel Energy 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.
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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 Xcel Energy's electric and natural gas infrastructure.
Other potential risks associated with wildfires include the inability to secure sufficient insurance coverage, or increased costs of insurance, regulatory recovery risk, and the potential for a credit downgrade and subsequent additional costs to access capital markets.
While we carry liability insurance, given an extreme event, if Xcel Energy 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.
ITEM 1B — UNRESOLVED STAFF COMMENTS | ||
None.
23
ITEM 2 — PROPERTIES | ||
Virtually all of the utility plant property of the operating companies is subject to the lien of their respective first mortgage bond indentures.
NSP-Minnesota Station, Location and Unit at Dec. 31, 2022 | Fuel | Installed | MW (a) | ||||||||||||||||||||
| Steam: | |||||||||||||||||||||||
| A.S. King-Bayport, MN, 1 Unit | Coal | 1968 | 511 | ||||||||||||||||||||
| Sherco-Becker, MN | |||||||||||||||||||||||
| Unit 1 | Coal | 1976 | 680 | ||||||||||||||||||||
| Unit 2 | Coal | 1977 | 682 | ||||||||||||||||||||
| Unit 3 | Coal | 1987 | 517 | (b) | |||||||||||||||||||
| Monticello, MN, 1 Unit | Nuclear | 1971 | 617 | ||||||||||||||||||||
| PI-Welch, MN | |||||||||||||||||||||||
| Unit 1 | Nuclear | 1973 | 521 | ||||||||||||||||||||
| Unit 2 | Nuclear | 1974 | 519 | ||||||||||||||||||||
| Various locations, 4 Units | Wood/Refuse | Various | 36 | (c) | |||||||||||||||||||
| Combustion Turbine: | |||||||||||||||||||||||
| Angus Anson-Sioux Falls, SD, 3 Units | Natural Gas | 1994 - 2005 | 327 | ||||||||||||||||||||
| Black Dog-Burnsville, MN, 3 Units | Natural Gas | 1987 - 2018 | 494 | ||||||||||||||||||||
| Blue Lake-Shakopee, MN, 6 Units | Natural Gas | 1974 - 2005 | 447 | ||||||||||||||||||||
| High Bridge-St. Paul, MN, 3 Units | Natural Gas | 2008 | 530 | ||||||||||||||||||||
| Inver Hills-Inver Grove Heights, MN, 6 Units | Natural Gas | 1972 | 252 | ||||||||||||||||||||
| Riverside-Minneapolis, MN, 3 Units | Natural Gas | 2009 | 454 | ||||||||||||||||||||
| Various locations, 7 Units | Natural Gas | Various | 10 | ||||||||||||||||||||
| Wind: | |||||||||||||||||||||||
| Blazing Star 1-Lincoln County, MN, 100 Units | Wind | 2020 | 200 | (d) | |||||||||||||||||||
| Blazing Star 2-Lincoln County, MN, 100 Units | Wind | 2021 | 200 | (d) | |||||||||||||||||||
| Border-Rolette County, ND, 75 Units | Wind | 2015 | 148 | (d) | |||||||||||||||||||
| Community Wind North-Lincoln County, MN, 12 Units | Wind | 2020 | 26 | (d) | |||||||||||||||||||
| Courtenay Wind-Stutsman County, ND, 100 Units | Wind | 2016 | 190 | (d) | |||||||||||||||||||
| Crowned Ridge 2-Grant County, SD, 88 Units | Wind | 2020 | 192 | (d) | |||||||||||||||||||
| Dakota Range, SD, 72 Units | Wind | 2022 | 298 | (d) | |||||||||||||||||||
| Foxtail-Dickey County, ND, 75 Units | Wind | 2019 | 150 | (d) | |||||||||||||||||||
| Freeborn-Freeborn County, MN, 100 Units | Wind | 2021 | 200 | (d) | |||||||||||||||||||
| Grand Meadow-Mower County, MN, 67 Units | Wind | 2008 | 99 | (d) | |||||||||||||||||||
| Jeffers-Cottonwood County, MN, 20 Units | Wind | 2020 | 43 | (d) | |||||||||||||||||||
| Lake Benton-Pipestone County, MN, 44 Units | Wind | 2019 | 99 | (d) | |||||||||||||||||||
| Mower-Mower County, MN, 43 Units | Wind | 2021 | 91 | (d) | |||||||||||||||||||
Nobles-Nobles County, MN, 133 Units (e) | Wind | 2010 | 200 | (d) | |||||||||||||||||||
| Pleasant Valley-Mower County, MN, 100 Units | Wind | 2015 | 196 | (d) | |||||||||||||||||||
| Rock Aetna - Murray County, MN, 8 Units | Wind | 2022 | 20 | (d) | |||||||||||||||||||
| Total | 8,949 | ||||||||||||||||||||||
(a)Summer 2022 net dependable capacity.
(b)Based on NSP-Minnesota’s ownership of 59%.
(c)Refuse-derived fuel is made from municipal solid waste.
(d)Capacity is attainable only when wind conditions are sufficiently available.
(e)Repowered in 2022.
NSP-Wisconsin Station, Location and Unit at Dec. 31, 2022 | Fuel | Installed | MW (a) | ||||||||||||||||||||
| Steam: | |||||||||||||||||||||||
| Bay Front-Ashland, WI, 2 Units | Wood/Natural Gas | 1948 - 1956 | 41 | ||||||||||||||||||||
| French Island-La Crosse, WI, 2 Units | Wood/Refuse | 1940 - 1948 | 16 | (b) | |||||||||||||||||||
| Combustion Turbine: | |||||||||||||||||||||||
| French Island-La Crosse, WI, 2 Units | Oil | 1974 | 122 | ||||||||||||||||||||
| Wheaton-Eau Claire, WI, 5 Units | Natural Gas/Oil | 1973 | 234 | ||||||||||||||||||||
| Hydro: | |||||||||||||||||||||||
| Various locations, 62 Units | Hydro | Various | 135 | ||||||||||||||||||||
| Total | 548 | ||||||||||||||||||||||
(a)Summer 2022 net dependable capacity.
(b)Refuse-derived fuel is made from municipal solid waste.
PSCo Station, Location and Unit at Dec. 31, 2022 | Fuel | Installed | MW (a) | ||||||||||||||||||||
| Steam: | |||||||||||||||||||||||
| Comanche-Pueblo, CO | |||||||||||||||||||||||
| Unit 2 | Coal | 1975 | 335 | ||||||||||||||||||||
| Unit 3 | Coal | 2010 | 500 | (b) | |||||||||||||||||||
| Craig-Craig, CO, 2 Units | Coal | 1979 - 1980 | 82 | (c) | |||||||||||||||||||
Hayden-Hayden, CO, 2 Units | Coal | 1965 - 1976 | 233 | (d) | |||||||||||||||||||
| Pawnee-Brush, CO, 1 Unit | Coal | 1981 | 505 | ||||||||||||||||||||
| Cherokee-Denver, CO, 1 Unit | Natural Gas | 1968 | 310 | ||||||||||||||||||||
| Combustion Turbine: | |||||||||||||||||||||||
| Blue Spruce-Aurora, CO, 2 Units | Natural Gas | 2003 | 264 | ||||||||||||||||||||
| Cherokee-Denver, CO, 3 Units | Natural Gas | 2015 | 576 | ||||||||||||||||||||
| Fort St. Vrain-Platteville, CO, 6 Units | Natural Gas | 1972 - 2009 | 973 | ||||||||||||||||||||
Manchief, CO, 2 Units (e) | Natural Gas | 2000 | 250 | ||||||||||||||||||||
| Rocky Mountain-Keenesburg, CO, 3 Units | Natural Gas | 2004 | 580 | ||||||||||||||||||||
| Various locations, 8 Units | Natural Gas | Various | 251 | ||||||||||||||||||||
| Hydro: | |||||||||||||||||||||||
| Cabin Creek-Georgetown, CO | |||||||||||||||||||||||
| Pumped Storage, 2 Units | Hydro | 1967 | 210 | ||||||||||||||||||||
| Various locations, 6 Units | Hydro | Various | 23 | ||||||||||||||||||||
| Wind: | |||||||||||||||||||||||
| Rush Creek, CO, 300 units | Wind | 2018 | 582 | (f) | |||||||||||||||||||
| Cheyenne Ridge, CO, 229 units | Wind | 2020 | 477 | (f) | |||||||||||||||||||
| Total | 6,151 | ||||||||||||||||||||||
(a)Summer 2022 net dependable capacity.
(b)Based on PSCo’s ownership of 67%.
(c)Based on PSCo’s ownership of 10%.
(d)Based on PSCo’s ownership of 76% of Unit 1 and 37% of Unit 2.
(e)Purchased in 2022.
(f)Capacity is attainable only when wind conditions are sufficiently available.
24
SPS 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 at Dec. 31, 2022:
| Conductor Miles | NSP-Minnesota | NSP-Wisconsin | PSCo | SPS | ||||||||||||||||||||||
| Transmission | ||||||||||||||||||||||||||
| 500 KV | 2,915 | — | — | — | ||||||||||||||||||||||
| 345 KV | 12,183 | 2,457 | 5,418 | 11,676 | ||||||||||||||||||||||
| 230 KV | 2,300 | — | 12,141 | 9,829 | ||||||||||||||||||||||
| 161 KV | 626 | 1,795 | — | — | ||||||||||||||||||||||
| 138 KV | — | — | 92 | — | ||||||||||||||||||||||
| 115 KV | 8,033 | 1,829 | 5,011 | 14,905 | ||||||||||||||||||||||
| Less than 115 KV | 6,537 | 5,571 | 1,839 | 4,469 | ||||||||||||||||||||||
| Total Transmission | 32,594 | 11,652 | 24,501 | 40,879 | ||||||||||||||||||||||
| Distribution | ||||||||||||||||||||||||||
| Less than 115 KV | 82,024 | 27,817 | 79,331 | 23,538 | ||||||||||||||||||||||
| Total | 114,618 | 39,469 | 103,832 | 64,417 | ||||||||||||||||||||||
Electric utility transmission and distribution substations at Dec. 31, 2022:
| NSP-Minnesota | NSP-Wisconsin | PSCo | SPS | |||||||||||||||||||||||
| Substations | 352 | 206 | 238 | 457 | ||||||||||||||||||||||
Natural gas utility mains at Dec. 31, 2022:
| Miles | NSP-Minnesota | NSP-Wisconsin | PSCo | SPS | WGI | |||||||||||||||||||||||||||
| Transmission | 78 | 3 | 2,067 | 20 | 11 | |||||||||||||||||||||||||||
| Distribution | 10,902 | 2,570 | 23,542 | — | — | |||||||||||||||||||||||||||
ITEM 3 — LEGAL PROCEEDINGS | ||
Xcel Energy 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 Xcel Energy’s consolidated financial statements. Legal fees are generally expensed as incurred.
See Note 12 to the consolidated financial statements, Item 1 and Item 7 for further information.
ITEM 4 — MINE SAFETY DISCLOSURES | ||
None.
PART II
ITEM 5 — MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES. | ||
Stock Data
Xcel Energy Inc.’s common stock is listed on the Nasdaq Global Select Market (Nasdaq). The trading symbol is XEL. The number of common stockholders of record as of Feb. 16, 2023 was 47,359.
The following compares our cumulative TSR on common stock with the cumulative TSR of the EEI Investor-Owned Electrics Index and the S&P 500 Composite Stock Price Index over the last five years.
The EEI Investor-Owned Electrics Index (market capitalization-weighted) included 39 companies at year-end and is a broad measure of industry performance.
Comparison of Five Year Cumulative Total Return*
* $100 invested on Dec. 31, 2017 in stock or index — including reinvestment of dividends. Fiscal years ended Dec. 31.
25
Purchases of Equity Securities by Issuer and Affiliated Purchasers
For the quarter ended Dec. 31, 2022, no equity securities that are registered by Xcel Energy Inc. pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of us or any of our affiliated purchasers.
ITEM 6 — [RESERVED] | ||
| ITEM 7 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS | ||
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 ROE, ongoing earnings and ongoing diluted EPS. 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.
Xcel Energy’s management uses non-GAAP measures for financial planning and analysis, for reporting of results to the Board of Directors, in determining performance-based compensation and communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.
Ongoing ROE
Ongoing ROE is calculated by dividing the net income or loss of Xcel Energy or each subsidiary, adjusted for certain nonrecurring items, by each entity’s average stockholder’s equity. We use these non-GAAP financial measures to evaluate and provide details of earnings results.
Earnings Adjusted for Certain Items (Ongoing Earnings and Ongoing Diluted EPS)
GAAP diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.’s diluted EPS is calculated using the treasury stock method. Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items. Ongoing diluted EPS is calculated by dividing the net income or loss of each subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. Ongoing diluted EPS for each subsidiary is calculated by dividing the net income or loss of such subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period.
We use these non-GAAP financial measures to evaluate and provide details of Xcel Energy’s core earnings and underlying performance. We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries. 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 | ||
Diluted EPS for Xcel Energy at Dec. 31:
| 2022 | 2021 | |||||||||||||
| Diluted Earnings (Loss) Per Share | GAAP and Ongoing Diluted EPS | GAAP and Ongoing Diluted EPS | ||||||||||||
| PSCo | $ | 1.33 | $ | 1.22 | ||||||||||
| NSP-Minnesota | 1.23 | 1.12 | ||||||||||||
| SPS | 0.64 | 0.59 | ||||||||||||
| NSP-Wisconsin | 0.23 | 0.20 | ||||||||||||
| Earnings from equity method investments — WYCO | 0.04 | 0.05 | ||||||||||||
Regulated utility (a) | 3.47 | 3.18 | ||||||||||||
| Xcel Energy Inc. and Other | (0.29) | (0.22) | ||||||||||||
Total (a) | $ | 3.17 | $ | 2.96 | ||||||||||
(a) Amounts may not add due to rounding.
Xcel Energy’s management believes that ongoing earnings reflects management’s performance in operating Xcel Energy and provides a meaningful representation of the performance of Xcel Energy’s core business. In addition, Xcel Energy’s management uses ongoing earnings internally for financial planning and analysis, reporting results to the Board of Directors and when communicating its earnings outlook to analysts and investors.
2022 Comparison with 2021
Xcel Energy — GAAP and ongoing earnings increased $0.21 per share for 2022. The increase was driven by regulatory outcomes, partially offset by higher depreciation, O&M expenses and interest charges. Costs for natural gas significantly increased in 2022 due to market conditions. However, fluctuations in electric and natural gas revenues associated with changes in fuel and purchased power and/or natural gas sold and transported generally do not significantly impact earnings (changes in revenues are offset by the related variation in costs).
PSCo — Earnings increased $0.11 per share for 2022, driven by regulatory outcomes and favorable weather. Higher revenues were partially offset by higher depreciation, O&M expenses and interest charges.
NSP-Minnesota — Earnings increased $0.11 per share for 2022 compared to 2021, driven by regulatory rate outcomes, partially offset by additional depreciation and O&M expenses.
SPS — Earnings increased $0.05 per share for 2022, largely related to regulatory rate outcomes, strong sales growth and favorable weather, partially offset by higher depreciation and O&M expenses.
NSP-Wisconsin — Earnings increased $0.03 per share for 2022 compared to 2021. The increase is due to regulatory rate outcomes and sales growth, partially offset by higher depreciation and O&M expenses.
Xcel Energy Inc. and Other — Earnings decreased $0.07 per share year-to-date due to higher interest charges and decreased earnings from EIP investments.
26
Changes in Diluted EPS
Components significantly contributing to changes in EPS:
| 2022 vs. 2021 | ||||||||
| Diluted Earnings (Loss) Per Share | Dec. 31 | |||||||
| GAAP and ongoing diluted EPS — 2021 | $ | 2.96 | ||||||
| Components of change — 2022 vs. 2021 | ||||||||
| Higher electric revenues, net of electric fuel and purchased power | 0.89 | |||||||
| Higher natural gas revenues, net of cost of natural gas sold and transported | 0.16 | |||||||
Lower ETR (a) | 0.15 | |||||||
| Higher depreciation and amortization | (0.40) | |||||||
| Higher O&M expenses | (0.24) | |||||||
| Higher interest expense | (0.15) | |||||||
| Higher taxes (other than income taxes) | (0.08) | |||||||
| Other (net) | (0.12) | |||||||
| GAAP and ongoing diluted EPS — 2022 | $ | 3.17 | ||||||
(a) Includes PTCs and plant regulatory amounts, which are primarily offset as a reduction to electric revenues.
ROE for Xcel Energy and its utility subsidiaries:
| 2022 | 2021 | |||||||||||||
| ROE | GAAP and Ongoing ROE | GAAP and Ongoing ROE | ||||||||||||
| PSCo | 8.23 | % | 8.23 | % | ||||||||||
| NSP-Minnesota | 8.76 | 8.45 | ||||||||||||
| SPS | 9.36 | 9.22 | ||||||||||||
| NSP-Wisconsin | 10.57 | 9.92 | ||||||||||||
| Operating Companies | 8.74 | 8.58 | ||||||||||||
| Xcel Energy | 10.76 | 10.58 | ||||||||||||
Statement of Income Analysis
The following summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income.
Estimated Impact of Temperature Changes on Regulated Earnings — Unusually hot summers or cold winters increase electric and natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances, the amount of natural gas or electricity historically used per degree of temperature and excludes any incremental related operating expenses that could result due to storm activity or vegetation management requirements.
As a result, weather deviations from normal levels can affect Xcel Energy’s financial performance. However, sales true-up and decoupling mechanisms in Minnesota and Colorado predominately mitigate the positive and adverse impacts of weather.
Degree-day or THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature and humidity.
HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit.
Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD.
In Xcel Energy’s more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy’s residential and commercial customers. Industrial customers are less sensitive to weather.
Normal weather conditions are defined as either the 10, 20 or 30-year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction, based on regulatory practice. To calculate the impact of weather on demand, a demand factor is applied to the weather impact on sales. Extreme weather variations, windchill and cloud cover may not be reflected in weather-normalized estimates.
Percentage increase (decrease) in normal and actual HDD, CDD and THI:
| 2022 vs. Normal | 2021 vs. Normal | 2022 vs. 2021 | |||||||||||||||
| HDD | 6.5 | % | (6.6) | % | 13.0 | % | |||||||||||
| CDD | 23.7 | 12.2 | 16.1 | ||||||||||||||
| THI | 5.6 | 26.8 | (15.8) | ||||||||||||||
Weather — Estimated impact of temperature variations on EPS compared with normal weather conditions:
| 2022 vs. Normal | 2021 vs. Normal | 2022 vs. 2021 | |||||||||||||||
| Retail electric | $ | 0.138 | $ | 0.096 | $ | 0.042 | |||||||||||
| Decoupling and sales true-up | (0.061) | (0.066) | 0.005 | ||||||||||||||
| Electric total | $ | 0.077 | $ | 0.030 | $ | 0.047 | |||||||||||
| Firm natural gas | 0.037 | (0.025) | 0.062 | ||||||||||||||
| Total | $ | 0.114 | $ | 0.005 | $ | 0.109 | |||||||||||
Sales — Sales growth (decline) for actual and weather-normalized sales:
| 2022 vs. 2021 | ||||||||||||||||||||||||||||||||
| PSCo | NSP-Minnesota | SPS | NSP-Wisconsin | Xcel Energy | ||||||||||||||||||||||||||||
| Actual | ||||||||||||||||||||||||||||||||
| Electric residential | (1.5) | % | (1.2) | % | 6.5 | % | 1.1 | % | (0.1) | % | ||||||||||||||||||||||
| Electric C&I | — | 1.7 | 8.9 | 3.3 | 3.3 | |||||||||||||||||||||||||||
| Total retail electric sales | (0.5) | 0.8 | 8.4 | 2.6 | 2.3 | |||||||||||||||||||||||||||
| Firm natural gas sales | 5.4 | 18.3 | N/A | 17.3 | 10.1 | |||||||||||||||||||||||||||
| 2022 vs. 2021 | ||||||||||||||||||||||||||||||||
| PSCo | NSP-Minnesota | SPS | NSP-Wisconsin | Xcel Energy | ||||||||||||||||||||||||||||
| Weather-normalized | ||||||||||||||||||||||||||||||||
| Electric residential | (3.6) | % | (0.2) | % | 0.8 | % | — | % | (1.3) | % | ||||||||||||||||||||||
| Electric C&I | (0.3) | 2.1 | 8.4 | 3.4 | 3.2 | |||||||||||||||||||||||||||
| Total retail electric sales | (1.4) | 1.3 | 6.9 | 2.4 | 1.8 | |||||||||||||||||||||||||||
| Firm natural gas sales | (3.1) | 5.5 | N/A | 5.8 | 0.1 | |||||||||||||||||||||||||||
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Weather-normalized electric sales growth (decline) — year-to-date
•PSCo — Residential sales declined due to decreased use per customer, partially offset by a 1.1% increase in customers. C&I sales decline was attributable to decreased use per customer, primarily in the manufacturing sector (largely due to an alternative generation arrangement with a significant customer), partially offset by strong small C&I sales in the food services and health care sectors.
•NSP-Minnesota — Residential sales decline reflects a decreased use per customer, partially offset by a 1.1% increase in customers. Growth in C&I sales was primarily due to higher use per customer, particularly in the manufacturing, real estate and leasing, and food service sectors.
•SPS — Residential sales growth was primarily attributable to a 0.9% increase in customers, partially offset by lower use per customer. C&I sales increased due to higher use per customer, primarily driven by the energy sector.
•NSP-Wisconsin — C&I sales growth was associated with higher use per customer, experienced primarily in the transportation and manufacturing sectors.
Weather-normalized natural gas sales growth (decline) — year-to-date
•Natural gas sales reflect growth in NSP-Minnesota and NSP-Wisconsin attributable primarily to increased residential use per customer and customer growth as well as increases in C&I sales due to higher use per customer. These increases were offset by a reduction in PSCo natural gas sales, primarily driven by declines in residential use per customer.
Electric Margin
Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Expenses incurred for electric fuel and purchased power are generally recovered through various regulatory recovery mechanisms.
As a result, changes in these expenses are generally offset in operating revenues.
Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and uranium. 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 | $ | 12,123 | $ | 11,205 | ||||||||||
| Electric fuel and purchased power | (5,005) | (4,733) | ||||||||||||
| Electric margin | $ | 7,118 | $ | 6,472 | ||||||||||
Change in Electric Margin
| (Millions of Dollars) | 2022 vs. 2021 | |||||||
| Regulatory rate outcomes (Minnesota, Colorado, Texas, New Mexico and Wisconsin) | $ | 506 | ||||||
Revenue recognition for the Texas rate case surcharge (a) | 85 | |||||||
Sales and demand (b) | 80 | |||||||
| Non-fuel riders | 64 | |||||||
| Wholesale transmission (net) | 50 | |||||||
| Estimated impact of weather (net of decoupling/sales true-up) | 33 | |||||||
| PTCs flowed back to customers (offset by lower ETR) | (150) | |||||||
| Other (net) | (22) | |||||||
| Total increase | $ | 646 | ||||||
(a)Recognition of revenue from the Texas rate case outcome is largely offset by recognition of previously deferred costs.
(b)Sales excludes weather impact, net of decoupling in Colorado and proposed sales true-up mechanism in Minnesota.
Natural Gas Margin
Natural gas margin is presented as natural gas revenues less the cost of natural gas sold and transported. Expenses incurred for the cost of natural gas sold are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues.
Natural gas expense varies with changing sales and the cost of natural gas. However, fluctuations in the cost of natural gas generally have minimal earnings impact due to cost recovery mechanisms.
Natural Gas Revenues, Cost of Natural Gas Sold and Transported and Natural Gas Margin
| (Millions of Dollars) | 2022 | 2021 | ||||||||||||
| Natural gas revenues | $ | 3,080 | $ | 2,132 | ||||||||||
| Cost of natural gas sold and transported | (1,910) | (1,081) | ||||||||||||
| Natural gas margin | $ | 1,170 | $ | 1,051 | ||||||||||
Change in Natural Gas Margin
| (Millions of Dollars) | 2022 vs. 2021 | |||||||
| Regulatory rate outcomes (Minnesota, Colorado, Wisconsin, North Dakota) | $ | 61 | ||||||
| Estimated impact of weather | 46 | |||||||
| Conservation revenue (offset in expenses) | 13 | |||||||
| Infrastructure and integrity riders | 9 | |||||||
| Winter Storm Uri disallowances | (20) | |||||||
| Other (net) | 10 | |||||||
| Total increase | $ | 119 | ||||||
Non-Fuel Operating Expenses and Other Items
O&M Expenses — O&M expenses increased $170 million year-to-date, due to the following approximately equal drivers: inflation and impacts of supply chain constraints; operational activities (vegetation management, repairs/maintenance and storms); costs for technology and customer programs; insurance-related costs; recognition of previously deferred amounts related to the 2021 Texas rate case; and other.
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Depreciation and Amortization — Depreciation and amortization increased $292 million year-to-date. The increase was primarily driven by capital investment, recognition of previously deferred costs related to the Texas Electric Rate Case and several wind farms going into service.
Other Income (Expense) — Other income (expense) decreased $18 million year-to-date, largely related to rabbi trust performance, which is primarily offset in O&M expenses (employee benefit costs).
Earnings from Equity Method Investments — Earnings from equity method investments decreased $26 million year-to-date. The year-to-date change was largely attributable to the performance of the EIP funds, which invest in energy technology companies.
Interest Charges — Interest charges increased $111 million year-to-date. The increase was largely due to higher long-term debt levels to fund capital investments and higher interest rates.
Income Taxes — Income tax benefit increased $65 million year-to-date. The year-to-date increase was primarily driven by an increase in wind PTCs due to greater production at existing wind farms, several new wind farms going into service and an increase in the PTC rate partially offset by higher pretax earnings.
Xcel Energy Inc. and Other Results
Net income and diluted EPS contributions of Xcel Energy Inc. and its nonregulated businesses:
| Contribution (Millions of Dollars) | ||||||||||||||
| 2022 | 2021 | |||||||||||||
| Xcel Energy Inc. financing costs | $ | (153) | $ | (129) | ||||||||||
Venture Holdings (a) | 5 | 21 | ||||||||||||
| Xcel Energy Inc. taxes and other results | (12) | (12) | ||||||||||||
| Total Xcel Energy Inc. and other costs | $ | (160) | $ | (120) | ||||||||||
| Contribution (Diluted Earnings (Loss) Per Share) | ||||||||||||||
| 2022 | 2021 | |||||||||||||
| Xcel Energy Inc. financing costs | $ | (0.28) | $ | (0.24) | ||||||||||
Venture Holdings (a) | 0.01 | 0.04 | ||||||||||||
| Xcel Energy Inc. taxes and other results | (0.02) | (0.02) | ||||||||||||
| Total Xcel Energy Inc. and other costs | $ | (0.29) | $ | (0.22) | ||||||||||
(a)Amounts include gains or losses associated with EIP investments.
Xcel Energy Inc.’s results include interest charges, which are incurred at Xcel Energy Inc. and are not directly assigned to individual subsidiaries.
2021 Comparison with 2020
A discussion of changes in Xcel Energy’s results of operations, cash flows and liquidity and capital resources from the year ended Dec. 31, 2020 to Dec. 31, 2021 can be found in Part II, “Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the fiscal year 2021, which was filed with the SEC on Feb. 23, 2022. However, such discussion is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.
| Public Utility Regulation | ||
The FERC and various state and local regulatory commissions regulate Xcel Energy Inc.’s utility subsidiaries and West Gas Interstate. Xcel Energy is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico and Texas.
Rates are designed to recover plant investment, operating costs and an allowed return on investment. Our utility subsidiaries request changes in utility rates through commission filings. Changes in operating costs can affect Xcel Energy’s financial results, depending on the timing of rate cases and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and 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 Xcel Energy’s results of operations and credit quality.
See Rate Matters within Note 12 to the consolidated financial statements for further information.
NSP-Minnesota
Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
| Regulatory Body / RTO | Additional Information | |||||||
| MPUC | Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. | |||||||
| NDPSC | Retail rates, services and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance. | |||||||
| SDPUC | Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance. | |||||||
| FERC | Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. | |||||||
| MISO | NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC. | |||||||
| DOT | Pipeline safety compliance. | |||||||
| Minnesota Office of Pipeline Safety | Pipeline safety compliance. | |||||||
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Recovery Mechanisms
| Mechanism | Additional Information | |||||||
CIP Rider (a) | Recovers costs of conservation and DSM programs in Minnesota. | |||||||
| Environmental Improvement Rider | Recovers costs of environmental improvement projects in Minnesota. | |||||||
| Renewable Development Fund | Allocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota. | |||||||
| RES | Recovers cost of renewable generation in Minnesota. | |||||||
| Renewable Energy Rider | Recovers cost of renewable generation in North Dakota. | |||||||
| Transmission Cost Recovery | Recovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. | |||||||
| Infrastructure Rider | Recovers costs for investments in generation in South Dakota. | |||||||
| FCA | Recovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota). | |||||||
| Purchased Gas Adjustment | Provides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs. | |||||||
| GUIC Rider | Recovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota. The statute authorizing the GUIC Rider is set to expire June 30, 2023. | |||||||
| Sales True-up | NSP-Minnesota has historically had a sales true-up mechanism for all electric customer classes which ended in 2021. We are requesting implementation of a new sales true-up mechanism for 2022 - 2024. These mechanisms mitigate the impact of changes to sales levels as compared to a baseline. | |||||||
(a)Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.
Pending and Recently Concluded Regulatory Proceedings
2022 Minnesota Electric Rate Case — In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. The request is based on a ROE of 10.2%, a 52.5% equity ratio and forward test years.
In December 2021, the MPUC approved interim rates, subject to refund, of $247 million, effective Jan. 1, 2022. In November 2022, NSP-Minnesota revised its rate request to $498 million over three years.
The revised request is detailed as follows:
| (Amounts in Millions) | 2022 | 2023 | 2024 | Total | ||||||||||||||||||||||
| Rate request (annual increase) | $ | 234 | $ | 94 | $ | 170 | $ | 498 | ||||||||||||||||||
| Rate base | 10,923 | 11,425 | 11,902 | N/A | ||||||||||||||||||||||
In 2022, several parties filed testimony with various recommendations. The DOC provided the following recommendations in surrebuttal testimony.
| 2022 | 2023 | 2024 | ||||||||||||||||||
| NSP-Minnesota’s filed base revenue request | $ | 396 | $ | 546 | $ | 677 | ||||||||||||||
| Recommended adjustments: | ||||||||||||||||||||
| Rate base and rate of return | (72) | (65) | (65) | |||||||||||||||||
| MISO capacity credits | (66) | (112) | (111) | |||||||||||||||||
| Sales forecast update | (51) | — | — | |||||||||||||||||
| Monticello and wind farm life extension | (21) | (54) | (51) | |||||||||||||||||
| PTC forecast | (28) | (1) | (1) | |||||||||||||||||
| Property tax | (14) | (23) | (34) | |||||||||||||||||
| Prepaid pension asset and liability | (13) | (21) | (32) | |||||||||||||||||
| O&M expenses | (37) | (39) | (44) | |||||||||||||||||
| Sherco 3 and King remaining life | — | 29 | 28 | |||||||||||||||||
| Other, net | (23) | (33) | (43) | |||||||||||||||||
| Total adjustments | (325) | (319) | (353) | |||||||||||||||||
| Total proposed revenue change | $ | 71 | $ | 227 | $ | 324 | ||||||||||||||
Next steps in the procedural schedule are expected to be as follows:
•ALJ Report: March 31, 2023.
•MPUC Order: June 30, 2023.
2022 Minnesota Natural Gas Rate Case — In November 2021, NSP-Minnesota filed a request with the MPUC for a natural gas rate increase of $36 million, or 6.6%. The filing is based on a 2022 forecast test year and includes a requested ROE of 10.5%, an equity ratio of 52.5% and a rate base of $934 million. In December 2021, the MPUC approved an interim rate increase of $25 million, subject to refund, effective Jan. 1, 2022.
In October 2022, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following key terms:
•Base rate revenue increase of $21 million, with a true up to weather normalized actual sales for 2022.
•Revenue decoupling mechanism.
•Symmetrical property tax true-up.
•ROE of 9.57%.
•Equity ratio of 52.5%.
In December 2022, the ALJ recommended MPUC approval of the settlement. A MPUC decision is expected in the first half of 2023.
2021 North Dakota Natural Gas Rate Case — In September 2021, NSP-Minnesota filed a request with the NDPSC for a natural gas rate increase of $7 million, or 10.5%. The filing is based on a ROE of 10.5%, an equity ratio of 52.54%, a 2022 forecast test year and rate base of $124 million. Interim rates of $7 million, subject to refund, were implemented on Nov. 1, 2021.
In May 2022, NSP-Minnesota and NDPSC Staff reached a settlement, which reflects a rate increase of $5 million, based on a 9.8% ROE and 52.54% equity ratio. In October 2022, the NDPSC approved the settlement and final rates were implemented on Nov. 1, 2022.
South Dakota Electric Rate Case — In June 2022, NSP-Minnesota filed a South Dakota electric rate case seeking a revenue increase of approximately $44 million. The filing is based on a 2021 historic test year adjusted for certain known and measurable changes for 2022 and 2023, a ROE of 10.75%, rate base of approximately $947 million and an equity ratio of 53%. Interim rates were implemented on Jan. 1, 2023. Final rates are expected to be approved by the SDPUC in mid-2023.
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Wind Repowering — In January 2021, the MPUC approved NSP-Minnesota’s request for the repowering of 651 MW of owned wind projects. Two of the four repowering projects, where construction has not yet begun (in-service dates in 2025), now expect costs in excess of the original approval. While the capital costs have increased, the passage of the IRA and other changes result in a levelized cost of energy that is approximately 30% lower than the original approval.
In October 2022, NSP-Minnesota filed a request with the MPUC seeking approval of the higher capital costs for these repowering projects. In February 2023, the DOC filed comments recommending approval of recovery of the increased costs of these projects through the RES Rider. A final decision is pending.
2022 Upper Midwest RFP — In August 2022, NSP-Minnesota launched a RFP for 900 MW of solar or solar-plus-storage hybrid resources to come online by the end of 2025, including up to 300 MW of capacity to reuse the Sherco Unit 2 interconnection rights when the coal facility retires at the end of 2023.
NSP-Minnesota completed its bid evaluation process in December 2022 and will file for approval of the selected projects in early 2023.
2022 Minnesota Electric Vehicle Proposal — In August 2022, NSP-Minnesota filed a request with the MPUC for approval of approximately $320 million of capital investments (2022 through 2026) to support a public charging network, electric school bus pilot, and other expansions and modifications to its residential and commercial electric vehicle programs.
In October 2022, the MPUC referred the matter to the Office of Administrative Hearings to conduct a contested case on the proposals. In February 2023, other parties to the contested proceeding filed their direct testimony ranging in levels of support / opposition to the proposals. The evidentiary hearing is scheduled in Q2 2023 with a report from the ALJ expected in Q3 2023. A MPUC decision is expected in late 2023.
Nuclear Power Operations
Nuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.
NRC Regulation — The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.
Low-Level Waste Disposal — Low level waste from Monticello and PI is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site at PI and Monticello which would allow both plants to continue to operate until the end of their current licensed lives if off-site low-level waste disposal facilities become unavailable.
High-Level Radioactive Waste Disposal — The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management.
This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.
Nuclear Spent Fuel Storage — NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and PI nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until the end of the operating licenses in 2030 for Monticello, 2033 for PI Unit 1, and 2034 for PI Unit 2.
In September 2021, NSP-Minnesota filed an application for a CON for additional spent fuel storage (existing Independent spent fuel storage installation) at the Monticello Nuclear Power Generating Plant to allow continued operation of the Monticello Plant until 2040.
A decision is expected in late 2023. Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations.
In February 2023, NSP-Minnesota also filed an application with the NDPSC for an Advance Determination of Prudence for continued operation of the Monticello Plant until at least 2040. A decision is expected in 2023.
Wholesale and Commodity Marketing Operations
NSP-Minnesota conducts wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy-related products. NSP-Minnesota uses physical and financial instruments to minimize commodity price risk and to hedge sales and purchases.
NSP-Minnesota also engages in trading activity unrelated to these hedging activities. Sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement. NSP-Minnesota does not serve any wholesale requirements customers at cost-based regulated rates.
NSP-Wisconsin
Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
| Regulatory Body / RTO | Additional Information | |||||||
| PSCW | Retail rates, services and other aspects of electric and natural gas operations. Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built. The PSCW has a biennial base rate filing requirement. By June of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January. Pipeline safety compliance. | |||||||
| Michigan Public Service Commission | Retail rates, services and other aspects of electric and natural gas operations. Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built. Pipeline safety compliance. | |||||||
| FERC | Wholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce. | |||||||
| MISO | NSP-Wisconsin is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices. | |||||||
| DOT | Pipeline safety compliance. | |||||||
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Recovery Mechanisms
| Mechanism | Additional Information | |||||||
| Annual Fuel Cost Plan | NSP-Wisconsin does not have an automatic electric fuel adjustment clause. Under Wisconsin rules, utilities submit a forward-looking annual fuel cost plan to the PSCW. Once the PSCW approves the plan, utilities defer the amount of any fuel cost under-recovery or over-recovery in excess of a 2% annual tolerance band, for future rate recovery or refund. Approval of a fuel cost plan and any rate adjustment for refund or recovery of deferred costs is determined by the PSCW. Rate recovery of deferred fuel cost is subject to an earnings test based on the most recently authorized ROE. Under-collections that exceed the 2% annual tolerance band may not be recovered if the utility earnings for that year exceed the authorized ROE. | |||||||
| Power Supply Cost Recovery Factors | NSP-Wisconsin’s retail electric rate schedules for Michigan customers include power supply cost recovery factors, based on 12-month projections. After each 12-month period, a reconciliation is submitted whereby over-recoveries are refunded and any under-recoveries are collected from customers. | |||||||
| Wisconsin Energy Efficiency Program | The primary energy efficiency program is funded by the utilities, but operated by independent contractors subject to oversight by the PSCW and utilities. NSP-Wisconsin recovers these costs from customers. | |||||||
| Purchased Gas Adjustment | A retail cost-recovery mechanism to recover the actual cost of natural gas, transportation, and storage services. | |||||||
| Natural Gas Cost-Recovery Factor (MI) | NSP-Wisconsin’s natural gas rates for Michigan customers include a natural gas cost-recovery factor, based on 12-month projections and trued-up to actual amounts on an annual basis. | |||||||
Purchased Power and Transmission Services
The NSP System expects to use power plants, power purchases, conservation and DSM options, new generation facilities and expansion of power plants to meet its system capacity requirements.
Purchased Power — Through the Interchange Agreement, NSP-Wisconsin receives power purchased by NSP-Minnesota from other utilities and independent power producers. Long-term purchased power contracts for dispatchable resources typically require a capacity charge and an energy charge. NSP-Minnesota makes short-term purchases to meet system requirements, replace company owned generation, meet operating reserve obligations or obtain energy at a lower cost.
Purchased Transmission Services — NSP-Minnesota and NSP-Wisconsin have contracts with MISO and other regional transmission service providers to deliver power and energy to their customers.
Wholesale and Commodity Marketing Operations
NSP-Wisconsin does not serve any wholesale requirements customers at cost-based regulated rates.
PSCo
Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
| Regulatory Body / RTO | Additional Information on Regulatory Authority | |||||||
| CPUC | Retail rates, accounts, services, issuance of securities and other aspects of electric, natural gas and steam operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plans greater than 50 MW. Pipeline safety compliance. | |||||||
| FERC | Wholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce. Wholesale electric sales at cost-based prices to customers inside PSCo’s balancing authority area and at market-based prices to customers outside PSCo’s balancing authority area. PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction. | |||||||
| RTO | PSCo is not presently a member of an RTO and does not operate within an RTO energy market. However, PSCo does make certain sales to other RTO’s, including SPP and participates in a joint dispatch agreement with neighboring utilities. | |||||||
| DOT | Pipeline safety compliance. | |||||||
Recovery Mechanisms
| Mechanism | Additional Information | |||||||
| ECA | Recovers fuel and purchased energy costs. Short-term sales margins are shared with customers. The ECA is revised quarterly. | |||||||
| Purchased Capacity Cost Adjustment | Recovers purchased capacity payments. | |||||||
| Steam Cost Adjustment | Recovers fuel costs to operate the steam system. The Steam Cost Adjustment rate is revised quarterly. | |||||||
| DSM Cost Adjustment | Recovers electric and gas DSM, interruptible service costs and performance initiatives for achieving energy savings goals. | |||||||
| RES Adjustment | Recovers the incremental costs of compliance with the RES with a maximum of 1% of the customer’s bill. | |||||||
| Colorado Energy Plan Adjustment | Recovers the early retirement costs of Comanche units 1 and 2 to a maximum of 1% of the customer’s bill. | |||||||
| Wind Cost Adjustment | Recovers costs for customers who choose renewable resources. | |||||||
| Transmission Cost Adjustment | Recovers costs for transmission investment between rate cases. | |||||||
| FCA | PSCo recovers fuel and purchased energy costs from wholesale electric customers through a fuel cost adjustment clause approved by the FERC. Wholesale customers pay production costs through a forecasted formula rate subject to true-up. | |||||||
| GCA | Recovers costs of purchased natural gas and transportation and is revised quarterly to allow for changes in natural gas rates. | |||||||
| Pipeline system integrity adjustment | Recovers costs for transmission and distribution pipeline integrity management programs (rider ended on Dec. 31, 2022). | |||||||
| Decoupling | Mechanism to true-up revenue to a baseline amount for residential (excluding lighting and demand) and metered non-demand small C&I classes. | |||||||
| Transportation Electrification Plan | Recovers costs associated with the investment in and adoption of transportation electrification infrastructure. | |||||||
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Pending and Recently Concluded Regulatory Proceedings
Colorado Natural Gas Rate Case — In January 2022, PSCo filed a request with the CPUC seeking a net increase to retail natural gas rates of $107 million. The total change to base rates is $215 million, which reflects the transfer of $108 million previously recovered from customers through the pipeline system integrity adjustment rider. The request was based on a 10.25% ROE, an equity ratio of 55.66% and a 2022 current test year with a projected rate base of $3.6 billion.
PSCo’s request also included step revenue increases of $40 million (effective Nov. 1, 2023) and $41 million (effective Nov. 1, 2024) related to continued capital investment.
In October 2022, the CPUC approved a rate increase net of rider roll-ins of $64 million. The decision reflects a stated WACC of 6.7%, a historic test year with a year-end rate base and $16 million of incremental depreciation expense. PSCo has the option to determine its ROE within a range of 9.2% to 9.5% and its equity ratio within a range of 52% to 55%, as long as it results in a WACC of 6.7%. The CPUC denied the 2023-2024 step increases. Base rates were placed in effect November 1, 2022.
Colorado Electric Rate Case — In November 2022, PSCo filed an electric rate case seeking a net increase of $262 million, or 8.2%. The total request reflects a $312 million increase, which includes $50 million of authorized costs currently recovered through various rider mechanisms. The request is based on a 10.25% ROE, an equity ratio of 55.7% and a 2023 forecast test year with a 2023 year-end rate base of $11.3 billion. PSCo requested rates effective in September 2023. A procedural schedule is expected to be established by the CPUC in the first quarter of 2023.
Colorado Resource Plan — In August 2022, the CPUC approved an updated settlement, which will result in the further acceleration of the retirement of the Comanche Unit 3 coal plant, an expected carbon reduction of at least 85% and an 80% renewable mix by 2030. The CPUC deferred a decision on the method of cost recovery for the retiring coal units to a separate docket, which will consider accelerated depreciation, creation of regulatory assets and securitization. PSCo filed the recovery method docket in the fourth quarter of 2022.
Key settlement terms include:
•Early retirement of Hayden: Unit 2 in 2027 (was 2036); and Unit 1 in 2028 (was 2030).
•Conversion of the Pawnee coal plant to natural gas by no later than Jan. 1, 2026.
•Early retirement of Comanche Unit 3 by Jan. 1, 2031 (was 2070) with reduced operations beginning in 2025.
•Addition of ~2,400 MW of wind.
•Addition of ~1,600 MW of universal-scale solar.
•Addition of 400 MW of storage.
•Addition of 1,300 MW of flexible, dispatchable generation.
•Addition of ~1,200 MW of distributed solar resources through our renewable energy programs.
In December 2022, the Company commenced the RFP process for generation resources with a bid receipt date of March 1, 2023. After reviewing the bids received, PSCo will file a report with the CPUC with recommended resource acquisitions and a CPUC decision on the resources to be acquired is expected in October 2023.
Decoupling Filing — PSCo has a decoupling program, effective April 1, 2020 through Dec. 31, 2023. The program applies to Residential and metered small C&I customers who do not pay a demand charge. The program includes a refund and surcharge cap not to exceed 3% of forecasted base rate revenue for a specified period.
In October 2021, a settlement was reached on Winter Storm Uri costs and also addressed certain components of the 2020 decoupling refunds.
In April 2022, PSCo made its annual filing on this matter. In December 2022, the ALJ approved a settlement between PSCo, CPUC Staff and the UCA. The settlement requires PSCo to file a petition for declaratory judgment to address the treatment of any expired balance under the 3% soft cap provisions.
As of Dec. 31, 2022, PSCo has recognized a refund for Residential customers and a surcharge for small C&I customers based on 2020, 2021 and 2022 results.
Transmission Cost Adjustment — In December 2022, the CPUC suspended PSCo’s request for 2023 TCA rate changes. The CPUC Staff protested the TCA on the grounds that only projects resulting in new transmission should be included and no repair or replacement of existing infrastructure should be included. The CPUC consolidated the matter with the pending electric rate case for assessment.
ECA Fuel Recovery — In December 2022, PSCo filed its first quarter 2023 ECA Advice Letter, which sought to recover $123 million of under-recovered 2022 fuel costs over two quarters (instead of the typical one). In December 2022, the CPUC found that the $123 million should be removed from the proposed ECA rates and required PSCo to file a separate application to recover these fuel costs. Proposed ECA rates were updated to remove the 2022 under-recovered balance and were implemented on Jan. 1, 2023. In February 2023, PSCo submitted an interim ECA filing which included $70 million of the 2022 under-recovered costs. A filing for the remaining amount is anticipated in the first quarter of 2023.
GCA NOPR — In June 2021, the CPUC issued a NOPR addressing the recovery of costs through the GCA. The CPUC has reopened the GCA NOPR and proposed a 2-step process aimed at 1) considering near term process changes to the GCA and 2) a longer term process to evaluate potential performance incentive structures. In step 1, consensus proposed rule amendments to update the process and filing requirements for GCA and related filings have been submitted to the CPUC for consideration. PSCo worked with other utilities and stakeholders regarding consensus proposed rule amendments for step 2, including a provision that each LDC bring forward its own performance incentive mechanism in a future filing. In December 2022, the CPUC approved the consensus proposal.
In February 2023, the Governor of Colorado issued an open letter to the CPUC, utilities, and other stakeholders directing agencies to take additional steps to address energy costs. It is likely this request will result in the opening of additional dockets to further explore the GCA and other related mechanisms. Additionally, the Colorado Legislature announced the formation of a Joint Select Committee to investigate the source of rising utility rates and explore potential actions to prevent future price instability.
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Natural Gas Planning NOPR — In October 2021, the CPUC issued a NOPR to implement recent state legislation requiring natural gas utilities to develop clean heat plans to meet state greenhouse gas emission reduction targets, as well as updated demand-side management criteria. Additionally, the proposed rules included new comprehensive natural gas infrastructure planning requirements and related Certificate of Public Convenience and Necessity application procedures, changes in natural gas line extension policy, and details on emission accounting related to clean heat plans. PSCo recommended changes to the proposed rules, which may be incorporated into the final rules issued in the first quarter of 2023.
Purchased Power and Transmission Service Providers
PSCo expects to meet its system capacity requirements through electric generating stations, power purchases, new generation facilities, DSM options and expansion of generation plants.
Purchased Power — PSCo purchases power from other utilities and IPPs. Long-term purchased power contracts for dispatchable resources typically require capacity and energy charges. It also contracts to purchase power for both wind and solar resources. PSCo makes short-term purchases to meet system load and energy requirements, replace owned generation, meet operating reserve obligations, or obtain energy at a lower cost.
Energy Markets — PSCo plans to join the SPP Western Energy Imbalance Service Market in April 2023. This market is an incremental step in the participation in the organized wholesale market. Energy imbalance markets allow participants to buy and sell power close to the time electricity is consumed and gives system operators real-time visibility across neighboring grids. The result improves balancing supply and demand at a lower cost.
Purchased Transmission Services — In addition to using its own transmission system, PSCo has contracts with regional transmission service providers to deliver energy to its customers.
Wholesale and Commodity Marketing Operations
PSCo conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy related products. PSCo uses physical and financial instruments to minimize commodity price risk and hedge sales and purchases. PSCo also engages in trading activity unrelated to these hedging activities.
Sharing of any margin is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement.
SPS
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. | |||||||
| DOT | Pipeline safety compliance. | |||||||
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.
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| (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.
SPS and LP&L Contract Termination — SPS and LP&L have 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 (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 pending PUCT and FERC approval.
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, DOT 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 risk and to hedge sales and purchases. Sharing of any margin is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement.
| 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. Xcel Energy 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. Xcel Energy continues to seek alternative suppliers and prioritize work plans to mitigate impacts of supply constraints.
Solar Resources
In April 2022, the U.S. Department of Commerce initiated an anti-circumvention investigation that would subject CSPV solar panels and cells imported from Malaysia, Vietnam, Thailand, and Cambodia with potential incremental tariffs ranging from 50% to 250%. These countries account for more than 80% of CSPV panel imports.
An interim stay on tariffs has been issued and many significant solar projects have resumed with modified costs and projected in-service dates, including the Sherco Solar facility in Minnesota and certain PPAs in PSCo. Further policy action or other restrictions on solar imports (i.e., as a result of implementation of the Uyghur Forced Labor Protection Act) could impact project timelines and costs.
Marshall Wildfire
In December 2021, a wildfire ignited in Boulder County, Colorado (the “Marshall Fire”), which burned over 6,000 acres and destroyed or damaged over 1,000 structures. Boulder County authorities are currently investigating the fire and have not yet determined a cause. There were no downed power lines in the ignition area, and nothing the Company has seen to this point indicates that our equipment or operations caused the fire.
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In Colorado, the standard of review governing liability differs from the “inverse condemnation” or strict liability standard utilized in California. In Colorado, courts look to whether electric power companies have operated their system with a heightened duty of care consistent with the practical conduct of its business, and liability does not extend to occurrences that cannot be reasonably anticipated. In addition, PSCo has been operating under a commission approved wildfire mitigation plan and carries wildfire liability insurance.
In March 2022, a class action suit was filed in Boulder County pertaining to the Marshall Fire. In the remote event PSCo was found liable related to this litigation and were required to pay damages, such amounts could exceed our insurance coverage and have a material adverse effect on our financial condition, results of operations or cash flows. In December 2022, the District Court judge denied PSCo’s Motion to Dismiss.
MISO Capacity Credits
The NSP System offered 1,500 MW of excess capacity into the MISO planning resource auction for June 2022 through May 2023. Due to a projected overall capacity shortfall in the MISO region, the 1,500 MWs offered cleared the auction at maximum pricing, generating revenues of approximately $90 million in 2022, with approximately $60 million expected in 2023. These amounts will primarily be used to mitigate customer rate increases or returned through earnings sharing or other mechanisms.
Inflation Reduction Act
In August 2022, the IRA was signed into law.
Key provisions impacting Xcel Energy include:
•Extends current PTC and ITC for renewable technologies (e.g., wind and solar).
•Restores full value of the PTC and ITC for qualifying facilities placed in-service after 2021.
•Creates a PTC for solar, clean hydrogen and nuclear.
•Establishes an ITC for energy storage, microgrids, interconnection facilities, etc.
•Allows companies to monetize or sell credits to unrelated parties.
Xcel Energy anticipates the IRA will materially reduce the cost of renewable energy, resulting in significant customer savings.
The IRA is expected to allow Xcel Energy to monetize tax credits more efficiently with the incremental benefits passed through to customers. Transferability provisions apply to eligible tax credits generated starting in 2023 for both new and existing facilities. Xcel Energy anticipates tax credit transferability from existing renewable projects will improve cash from operations by $1.8 billion (2023 - 2027), assuming constructive regulatory outcomes and the development of a market.
The IRA creates a nuclear PTC beginning in 2024 that may also provide additional customer savings. The annual customer benefit from these PTCs could range from $0 to $300 million, depending on locational marginal pricing, as well as constructive U.S. Treasury guidance regarding computation of the credits.
In addition, the IRA created a new corporate AMT. Xcel Energy does not anticipate AMT having a material cash impact based on current estimates and our interpretation of its application.
Winter Storm Uri
In February 2021, the United States experienced Winter Storm Uri. Extreme cold temperatures impacted certain operational assets as well as the availability of renewable generation. The cold weather also affected the country’s supply and demand for natural gas.
These factors contributed to extremely high market prices for natural gas and electricity. As a result of the extremely high market prices, Xcel Energy incurred net natural gas, fuel and purchased energy costs of approximately $1 billion (largely deferred as regulatory assets).
Xcel Energy has received recovery approval from all of our impacted states except for Texas, which is pending. A summary of pending and recently approved regulatory requests for Winter Storm Uri cost recovery is listed below.
| Utility Subsidiary | Jurisdiction | Regulatory Status | ||||||
| NSP-Minnesota | Minnesota | In 2021, the MPUC allowed recovery of $179 million of costs (with no financing charge) starting in September 2021, pending a prudency review. The C&I class ($82 million) will be recovered over 27 months and the residential class ($97 million) will be recovered over a 63-month recovery period. In August 2022, the MPUC approved recovery of Uri storm costs with a $19 million disallowance. | ||||||
| PSCo | Colorado | In May 2021, PSCo filed a request with the CPUC to recover $263 million in weather-related electric costs, $287 million in incremental natural gas costs and $4 million in incremental steam costs over 24 months with no financing charge. In July 2022, the CPUC approved a partial settlement providing full recovery of fuel costs, with the exception of an $8 million disallowance, over 24 months for electric and 30 months for natural gas customers. | ||||||
| SPS | Texas | 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 ALJs found that costs were prudently incurred and recommended no disallowances. A final PUCT decision is anticipated in the first quarter of 2023. | ||||||
Critical Accounting Policies and Estimates | ||
Preparation of the consolidated financial statements requires the application of accounting rules and guidance, as well as the use of estimates. Application of these policies involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments could materially impact the consolidated financial statements, based on varying assumptions. In addition, the financial and operating environment also may have a significant effect on the operation of the business and results reported.
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Accounting policies and estimates that are most significant to Xcel Energy’s results of operations, financial condition or cash flows, and require management’s most difficult, subjective or complex judgments are outlined below. Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. Each critical accounting policy has been reviewed and discussed with the Audit Committee of Xcel Energy Inc.’s Board of Directors on a quarterly basis.
Regulatory Accounting
Xcel Energy is subject to the accounting for Regulated Operations, which 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. Our rates are derived through the ratemaking process, which results 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. In other businesses or industries, regulatory assets and regulatory liabilities would generally be charged to net income or other comprehensive income.
Each reporting period we assess the probability of future recoveries and obligations associated with regulatory assets and liabilities. Factors such as the current regulatory environment, recently issued rate orders and historical precedents are considered. Decisions made by regulatory agencies can directly impact the amount and timing of cost recovery as well as the rate of return on invested capital, and may materially impact our results of operations, financial condition or cash flows.
As of Dec. 31, 2022 and 2021, Xcel Energy had regulatory assets of $3.9 billion and $3.8 billion, respectively and regulatory liabilities of $6.0 billion and $5.7 billion, respectively. Each subsidiary is subject to regulation that varies from jurisdiction to jurisdiction. If future recovery of costs in any such jurisdiction is no longer probable, Xcel Energy would be required to charge these assets to current net income or other comprehensive income.
At Dec. 31, 2022, in assessing the probability of recovery of recognized regulatory assets, unless otherwise disclosed, Xcel Energy noted no current or anticipated proposals or changes in the regulatory environment that it expects will materially impact the recovery of the assets.
See Notes 4 and 12 to the consolidated financial statements for further information.
Income Tax Accruals
Judgment, uncertainty and estimates are a significant aspect of the income tax accrual process that accounts for the effects of current and deferred income taxes. Uncertainty associated with the application of tax statutes and regulations and outcomes of tax audits and appeals require that judgment and estimates be made in the accrual process and in the calculation of the ETR.
Changes in tax laws and rates may affect recorded deferred tax assets and liabilities and our future ETR. ETR calculations are revised every quarter based on best available year-end tax assumptions, adjusted in the following year after returns are filed. Tax accrual estimates are trued-up to the actual amounts claimed on the tax returns and further adjusted after examinations by taxing authorities, as needed.
In accordance with the interim period reporting guidance, income tax expense for the first three quarters in a year is based on the forecasted annual ETR. The forecasted ETR reflects a number of estimates, including forecasted annual income, permanent tax adjustments and tax credits.
Valuation allowances are applied to deferred tax assets if it is more likely than not that at least a portion may not be realized based on an evaluation of expected future taxable income. Accounting for income taxes also requires that only tax benefits that meet the more likely than not recognition threshold can be recognized or continue to be recognized.
We may adjust our unrecognized tax benefits and interest accruals as disputes with the IRS and state tax authorities are resolved, and as new developments occur. These adjustments may increase or decrease earnings.
See Note 7 to the consolidated financial statements for further information.
Employee Benefits
We sponsor several noncontributory, defined benefit pension plans and other postretirement benefit plans that cover almost all employees and certain retirees. Projected benefit costs are based on historical information and actuarial calculations that include key assumptions (annual return level on pension and postretirement health care investment assets, discount rates, mortality rates and health care cost trend rates, etc.). In addition, the pension cost calculation uses a methodology to reduce the volatility of investment performance over time. Pension assumptions are continually reviewed.
At Dec. 31, 2022, Xcel Energy set the rate of return on assets used to measure pension costs at 6.93%, which is 44 basis points higher than the rate set in 2021. The rate of return used to measure postretirement health care costs is 5.00% at Dec. 31, 2022, which is 90 basis points higher than the rate set in 2021. Xcel Energy’s pension investment strategy is based on plan-specific investments that seek to minimize investment and interest rate risk as a plan’s funded status increases over time. This strategy results in a greater percentage of interest rate sensitive securities being allocated to plans with higher funded status ratios and a greater percentage of growth assets being allocated to plans having lower funded status ratios.
Xcel Energy set the discount rates used to value the pension obligations and postretirement health care obligations at 5.80% at Dec. 31, 2022. This represents a 272 basis point and 271 basis point increase, respectively, from 2021. Xcel Energy uses a bond matching study as its primary basis for determining the discount rate used to value pension and postretirement health care obligations. The bond matching study utilizes a portfolio of high grade (Aa or higher) bonds that matches the expected cash flows of Xcel Energy’s benefit plans in amount and duration.
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The effective yield on this cash flow matched bond portfolio determines the discount rate for the individual plans. The bond matching study is validated for reasonableness against the Bank of America US Corporate 15+ Bond Index. In addition, Xcel Energy reviews general actuarial survey data to assess the reasonableness of the discount rate selected.
If Xcel Energy were to use alternative assumptions, a 1% change would result in the following impact on 2022 pension costs:
| Pension Costs | ||||||||||||||
| (Millions of Dollars) | +1% | -1% | ||||||||||||
Rate of return (a) | $ | (11) | $ | 26 | ||||||||||
Discount rate (a) | $ | 1 | $ | 8 | ||||||||||
(a)These costs include the effects of regulation.
Mortality rates are developed from actual and projected plan experience for pension plan and postretirement benefits. Xcel Energy’s actuary conducts an experience study periodically to determine an estimate of mortality. Xcel Energy considers standard mortality tables, improvement factors and the plans actual experience when selecting a best estimate.
As of Dec. 31, 2022, the initial medical trend cost claim assumptions for Pre-65 was 6.5% and Post-65 was 5.5%. The ultimate trend assumption remained at 4.5% for both Pre-65 and Post-65 claims costs. Xcel Energy bases its medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost experienced by Xcel Energy’s retiree medical plan.
Funding contributions in 2022 were $50 million and will remain relatively consistent in future years. Investment returns were less than the assumed levels in 2022, but exceeded the assumed levels in 2021 and 2020.
The pension cost calculation uses a market-related valuation of pension assets. Xcel Energy uses a calculated value method to determine the market-related value of the plan assets. The market-related value is determined by adjusting the fair market value of assets at the beginning of the year to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20% per year.
As differences between actual and expected investment returns are incorporated into the market-related value, amounts are recognized in pension cost over the expected average remaining years of service for active employees (approximately 13 years in 2022).
Xcel Energy currently projects the pension costs recognized for financial reporting purposes will be $66 million in 2023 and $58 million in 2024, while the actual pension costs were $114 million in 2022 and $121 million in 2021. The expected decrease in 2023 is primarily due to the reductions in loss amortizations.
Pension funding contributions across all four of Xcel Energy’s pension plans, both voluntary and required, for 2020 - 2023:
•$50 million in January 2023.
•$50 million in 2022.
•$131 million in 2021.
•$150 million in 2020.
Future amounts may change based on actual market performance, changes in interest rates and any changes in governmental regulations. Therefore, additional contributions could be required in the future. Xcel Energy contributed $13 million, $15 million and $11 million during 2022, 2021 and 2020, respectively, to the postretirement health care plans. Xcel Energy expects to contribute approximately $12 million during 2023. Xcel Energy recovers employee benefits costs in its utility operations consistent with accounting guidance with the exception of the areas noted below.
•NSP-Minnesota recognizes pension expense in all regulatory jurisdictions using the aggregate normal cost actuarial method. Differences between aggregate normal cost and expense as calculated by pension accounting standards are deferred as a regulatory liability.
•In 2021, the PSCW approved NSP-Wisconsin’s request for deferred accounting treatment of the 2021 pension settlement accounting expense. Escrow accounting treatment was also approved for ongoing pension and other post-employment benefit expenses, including settlement charges.
•Regulatory Commissions in Colorado, Texas, New Mexico and FERC jurisdictions allow the recovery of other postretirement benefit costs only to the extent that recognized expense is matched by cash contributions to an irrevocable trust. Xcel Energy has consistently funded at a level to allow full recovery of costs in these jurisdictions.
•PSCo is required to create a regulatory liability that adjusts the annual post-retirement benefits amount to zero in order to match the amount collected in rates.
•PSCo and SPS recognize pension expense in all regulatory jurisdictions based on GAAP. The Texas and Colorado electric retail jurisdictions and the Colorado gas retail jurisdiction, each record the difference between annual recognized pension expense and the annual amount of pension expense approved in their last respective general rate case as a deferral to a regulatory asset.
See Note 11 to the consolidated financial statements for further information.
Nuclear Decommissioning
Xcel Energy recognizes liabilities for the expected cost of retiring tangible long-lived assets for which a legal obligation exists. These AROs are recognized at fair value as incurred and are capitalized as part of the cost of the related long-lived assets. In the absence of quoted market prices, Xcel Energy estimates the fair value of its AROs using present value techniques, in which it makes assumptions including estimates of the amounts and timing of future cash flows associated with retirement activities, credit-adjusted risk free rates and cost escalation rates. When Xcel Energy revises any assumptions, it adjusts the carrying amount of both the ARO liability and related long-lived asset. ARO liabilities are accreted to reflect the passage of time using the interest method.
A significant portion of Xcel Energy’s AROs relates to the future decommissioning of NSP-Minnesota’s nuclear facilities. The nuclear decommissioning obligation is funded by the external decommissioning trust fund. Difference between regulatory funding (including depreciation expense less returns from the external trust fund) and expense recognized is deferred as a regulatory asset. The amounts recorded for AROs related to future nuclear decommissioning were $2.2 billion in 2022 and $2.1 billion in 2021.
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NSP-Minnesota obtains periodic independent cost studies to estimate the cost and timing of planned nuclear decommissioning activities. Estimates of future cash flows are highly uncertain and may vary significantly from actual results. NSP-Minnesota is required to file a nuclear decommissioning filing every three years. The filing covers all expenses for the decommissioning of the nuclear plants, including decontamination and removal of radioactive material.
The 2022 - 2024 Nuclear Decommissioning Study and Assumptions were approved by the MPUC in August 2022. The MPUC ordered the next triennial decommissioning study be filed by December 1, 2024, allowing for four years between filings.
The following assumptions have a significant effect on the estimated nuclear obligation:
Timing — Decommissioning cost estimates are impacted by each facility’s retirement date and timing of the actual decommissioning activities. Estimated retirement dates coincide with the approved retirement dates which can be different than the expiration dates of each unit’s operating license with the NRC (i.e., 2030 for Monticello and 2033 and 2034 for PI’s Unit 1 and 2, respectively).
In April 2022, the Company received approval from the MPUC, in the Integrated Resource Plan, to pursue extending the operating life of the Monticello Nuclear Generating Plant by ten years from 2030 to 2040. This life extension is subject to NRC approval of Monticello’s nuclear license extension request.
The retirement dates of the Prairie Island Unit 1 and Unit 2 remain unchanged, 2033 and 2034 respectively. The estimated timing of the decommissioning activities is based upon the DECON method, which assumes prompt removal and dismantlement. Decommissioning activities are expected to begin at the commission approved retirement date and be completed for both facilities by 2101.
Technology and Regulation — There is limited experience with actual decommissioning of large nuclear facilities. Changes in technology, experience and regulations could cause cost estimates to change significantly.
Escalation Rates — Escalation rates represent projected cost increases due to general inflation and increases in the cost of decommissioning activities. NSP-Minnesota used an escalation rate of 3.2% in calculating the ARO for nuclear decommissioning of its nuclear facilities, based on weighted averages of labor and non-labor escalation factors calculated by Goldman Sachs Asset Management.
Discount Rates — Changes in timing or estimated cash flows that result in upward revisions to the ARO are calculated using the then-current credit-adjusted risk-free interest rate. The credit-adjusted risk-free rate in effect when the change occurs is used to discount the revised estimate of the incremental expected cash flows of the retirement activity.
If the change in timing or estimated expected cash flows results in a downward revision of the ARO, the undiscounted revised estimate of expected cash flows is discounted using the credit-adjusted risk-free rate in effect at the date of initial measurement and recognition of the original ARO. Discount rates ranging from approximately 3% to 7% have been used to calculate the net present value of the expected future cash flows over time.
Significant uncertainties exist in estimating future costs including the method to be utilized, ultimate costs to decommission and planned method of disposing spent fuel. If different cost estimates, life assumptions or cost escalation rates were utilized, the AROs could change materially.
However, changes in estimates have minimal impact on results of operations as NSP-Minnesota expects to continue to recover all costs in future rates.
NSP-Minnesota continually makes judgments and estimates related to these critical accounting policy areas, based on an evaluation of the assumptions and uncertainties for each area. The information and assumptions of these judgments and estimates will be affected by events beyond the control of Xcel Energy, or otherwise change over time.
This may require adjustments to recorded results to better reflect updated information that becomes available. The accompanying financial statements reflect management’s best estimates and judgments of the impact of these factors as of Dec. 31, 2022.
See Note 12 to the consolidated financial statements for further information.
Derivatives, Risk Management and Market Risk | ||
We are 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.
Xcel Energy 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 we expect that the counterparties will perform on the contracts underlying our derivatives, the contracts expose us to credit and non-performance risk.
Distress in the financial markets may impact counterparty risk and the fair value of the securities in the nuclear decommissioning fund and pension fund.
Commodity Price Risk — We are exposed to commodity price risk in our electric and natural gas operations. Commodity price risk is managed by entering into long and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities.
Commodity price risk is also managed through the use of financial derivative instruments. Our risk management policy allows us to manage commodity price risk within each rate-regulated operation per commission approved hedge plans.
Wholesale and Commodity Trading Risk — Xcel Energy conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Our risk management policy allows management to conduct these activities within guidelines and limitations as approved by our risk management committee.
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Fair value of net commodity trading contracts as of Dec. 31, 2022:
| Futures / Forwards Maturity | ||||||||||||||||||||||||||||||||
| (Millions of Dollars) | Less Than 1 Year | 1 to 3 Years | 4 to 5 Years | Greater Than 5 Years | Total Fair Value | |||||||||||||||||||||||||||
NSP-Minnesota (a) | $ | (8) | $ | (6) | $ | (7) | $ | (2) | $ | (23) | ||||||||||||||||||||||
NSP-Minnesota (b) | 5 | (4) | — | (3) | (2) | |||||||||||||||||||||||||||
PSCo (a) | 10 | 3 | 3 | — | 16 | |||||||||||||||||||||||||||
PSCo (b) | (56) | (15) | 8 | — | (63) | |||||||||||||||||||||||||||
| $ | (49) | $ | (22) | $ | 4 | $ | (5) | $ | (72) | |||||||||||||||||||||||
| Options Maturity | ||||||||||||||||||||||||||||||||
| (Millions of Dollars) | Less Than 1 Year | 1 to 3 Years | 4 to 5 Years | Greater Than 5 Years | Total Fair Value | |||||||||||||||||||||||||||
NSP-Minnesota (b) | $ | — | $ | — | $ | — | $ | 15 | $ | 15 | ||||||||||||||||||||||
PSCo (b) | 40 | 7 | — | — | 47 | |||||||||||||||||||||||||||
| $ | 40 | $ | 7 | $ | — | $ | 15 | $ | 62 | |||||||||||||||||||||||
(a)Prices actively quoted or based on actively quoted prices.
(b)Prices based on models and other valuation methods.
Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the years ended Dec. 31:
| (Millions of Dollars) | 2022 | 2021 | ||||||||||||
| Fair value of commodity trading net contracts outstanding at Jan. 1 | $ | (33) | $ | (54) | ||||||||||
| Contracts realized or settled during the period | (15) | (54) | ||||||||||||
| Commodity trading contract additions and changes during the period | 38 | 75 | ||||||||||||
| Fair value of commodity trading net contracts outstanding at Dec. 31 | $ | (10) | $ | (33) | ||||||||||
A 10% increase and 10% decrease in forward market prices for Xcel Energy’s commodity trading contracts would have likewise increased and decreased pretax income from continuing operations, by approximately $8 million at Dec. 31, 2022 and $13 million at Dec. 31, 2021. Market price movements can exceed 10% under abnormal circumstances.
The utility subsidiaries’ commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations using an industry standard methodology known as VaR. VaR expresses the potential change in fair value of the outstanding contracts and obligations over a particular period of time under normal market conditions.
The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchases and normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:
| (Millions of Dollars) | Year Ended Dec. 31 | Average | High | Low | ||||||||||||||||||||||
| 2022 | $ | 2 | $ | 1 | $ | 5 | $ | — | ||||||||||||||||||
| 2021 | $ | 1 | $ | 2 | $ | 52 | $ | 1 | ||||||||||||||||||
A short-term increase in VaR occurred during the week of Feb. 12, 2021 through Feb. 18, 2021. On Feb. 17, 2021, the portfolio VaR reached a high of $52 million. This increase in VaR was driven by the unprecedented market conditions during Winter Storm Uri. Prior to this weather event, VaR was $1 million and returned to $1 million by Feb. 19, 2021.
Nuclear Fuel Supply — NSP-Minnesota has contracted for its 2023 and 2024 enriched nuclear material requirements, which are in various stages of processing in Canada, Europe, and the United States. NSP-Minnesota is scheduled to take delivery of approximately 26% of its average enriched nuclear material requirements from Russia through 2030. We are closely monitoring the evolving situation in Ukraine and its global impacts. NSP-Minnesota is in the process of entering into new contracts to reduce the risk of supply interruptions of nuclear material from Russia. NSP-Minnesota will take additional further action to reduce this risk as necessary.
Interest Rate Risk — Xcel Energy is subject to interest rate risk. Our 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 Xcel Energy’s variable rate debt would impact pretax interest expense annually by approximately $8 million and $11 million in 2022 and 2021, respectively.
NSP-Minnesota maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate and equity price risk. The fund is invested in a diversified portfolio of debt securities, equity securities and other investments. These investments may be used only for the purpose of decommissioning NSP-Minnesota’s nuclear generating plants.
Fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on earnings due to the application of regulatory accounting. Realized and unrealized gains on the decommissioning fund investments are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs.
The value of pension and postretirement plan assets and benefit costs are impacted by changes in discount rates and expected return on plan assets. Xcel Energy’s ongoing pension and postretirement investment strategy is based on plan-specific investment recommendations that seek to optimize potential investment risk and minimize interest rate risk associated with changes in the obligations as a plan’s funded status increases over time. The impacts of fluctuations in interest rates on pension and postretirement costs are mitigated by pension cost calculation methodologies and regulatory mechanisms that minimize the earnings impacts of such changes.
Credit Risk — Xcel Energy is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance on their contractual obligations. Xcel Energy 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 $56 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $47 million. At Dec. 31, 2021, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $36 million, while a decrease in prices of 10% would have resulted in an decrease in credit exposure of $26 million.
Xcel Energy 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 our credit risk.
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Fair Value Measurements
Derivative contracts, with the exception of those designated as normal purchases and normal sales, are reported at fair value. Xcel Energy’s investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value accounting. See Notes 10 and 11 to the consolidated financial statements for further information.
Liquidity and Capital Resources | ||
Cash Flows
Operating Cash Flows
| (Millions of Dollars) | Twelve Months Ended Dec. 31 | |||||||
| Cash provided by operating activities — 2021 | $ | 2,189 | ||||||
| Components of change — 2022 vs. 2021 | ||||||||
| Higher net income | 139 | |||||||
| Non-cash transactions | 257 | |||||||
| Changes in working capital | (300) | |||||||
| Changes in net regulatory and other assets and liabilities | 1,647 | |||||||
| Cash provided by operating activities — 2022 | $ | 3,932 | ||||||
Net cash provided by operating activities increased by $1,743 million for 2022 as compared to 2021. The increase was primarily due to the deferral of net natural gas, fuel and purchased energy costs incurred during Winter Storm Uri in the first quarter of 2021.
Investing Cash Flows
| (Millions of Dollars) | Twelve Months Ended Dec. 31 | |||||||
| Cash used in investing activities — 2021 | $ | (4,287) | ||||||
| Components of change — 2022 vs. 2021 | ||||||||
| Increased capital expenditures | (394) | |||||||
| Other investing activities | 28 | |||||||
| Cash used in investing activities — 2022 | $ | (4,653) | ||||||
Net cash used in investing activities increased by $366 million for 2022 as compared to 2021. The increase in capital expenditures was largely due to continued system expansion.
Financing Cash Flows
| (Millions of Dollars) | Twelve Months Ended Dec. 31 | |||||||
| Cash provided by financing activities — 2021 | $ | 2,135 | ||||||
| Components of change — 2022 vs. 2021 | ||||||||
| Lower debt issuances | (1,159) | |||||||
| Higher repayments of long-term debt | (184) | |||||||
| Lower proceeds from issuance of common stock | (44) | |||||||
| Higher dividends paid to shareholders | (77) | |||||||
| Other financing activities | (5) | |||||||
| Cash provided by financing activities — 2022 | $ | 666 | ||||||
Net cash provided by financing activities decreased by $1,469 million for 2022 as compared to 2021. The decrease was primarily related to the amount/timing of debt issuances and repayments associated with Winter Storm Uri.
See Note 5 to the consolidated financial statements for further information.
Capital Requirements
Xcel Energy has contractual obligations and other commitments that will need to be funded in the future. Xcel Energy expects to have adequate amounts of cash from operating and financing activities to meet both its short-term and long-term cash requirements. Xcel Energy’s financing requirements are dependent on both existing contractual obligations and other commitments, as well as projected capital forecasts. Xcel Energy expects to meet future financing requirements by periodically issuing short-term debt, long-term debt, common stock, hybrid and other securities to maintain desired capitalization ratios. Projected future financing requirements can be impacted by various factors including constraints to supply chain and labor, as well as inflation.
Recovery of the effects of inflation through higher customer rates is dependent upon receiving adequate and timely rate increases. Rate increases may not be retroactive and often lag increases in costs caused by inflation. On occasion, Xcel Energy may enter into rate settlement agreements, which require us to wait for a period of time to file the next base rate increase request. These agreements may result in regulatory lag whereby the impact of inflation may not yet be reflected in rates, or a delay may occur between capital project completion and the start of rate recovery. Xcel Energy attempts to mitigate the potential impact of inflation through the use of fuel, energy and other cost adjustment clauses and bill riders, by employing prudent risk management and hedging strategies and by considering, among other areas, its impact on purchases of energy, operating expenses, materials and equipment costs, contract negotiations, future capital spending programs and long-term debt issuances.
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Material Cash Requirements and Other Commitments
| Payments Due by Period (as of Dec. 31, 2022) | ||||||||||||||||||||||||||||||||
| (Millions of Dollars) | Total | Less than 1 Year | 1 to 3 Years | 3 to 5 Years | After 5 Years | |||||||||||||||||||||||||||
| Long-term debt, principal and interest payments | $ | 39,750 | $ | 2,059 | $ | 3,492 | $ | 2,714 | $ | 31,485 | ||||||||||||||||||||||
| Finance lease obligations | 228 | 10 | 20 | 17 | 181 | |||||||||||||||||||||||||||
Operating leases obligations (a) | 1,457 | 264 | 506 | 287 | 400 | |||||||||||||||||||||||||||
Unconditional purchase obligations (b) | 5,129 | 1,899 | 1,475 | 921 | 834 | |||||||||||||||||||||||||||
Other long-term obligations, including current portion (c) | 111 | 53 | 35 | 23 | — | |||||||||||||||||||||||||||
| Other short-term obligations | 436 | 436 | — | — | — | |||||||||||||||||||||||||||
| Short-term debt | 813 | 813 | — | — | — | |||||||||||||||||||||||||||
| Total contractual cash obligations | $ | 47,924 | $ | 5,534 | $ | 5,528 | $ | 3,962 | $ | 32,900 | ||||||||||||||||||||||
(a)Included in operating lease obligations are $231 million, $455 million, $251 million and $326 million, for the less than 1 year, 1 - 3 years, 3 - 5 years and after 5 years categories, respectively, pertaining to PPAs that were accounted for as operating leases.
(b)Xcel Energy Inc. and its subsidiaries have contracts providing for the purchase and delivery of a significant portion of its fuel (nuclear, natural gas and coal) requirements. Additionally, the utility subsidiaries of Xcel Energy Inc. have entered into non-lease purchase power agreements. Certain contractual purchase obligations are adjusted on indices. Effects of price changes are mitigated through cost of energy adjustment mechanisms.
(c)Primarily consists of contracts for information technology services.
Capital Expenditures — Base capital expenditures and incremental capital forecasts:
| Actual | Base Capital Forecast (Millions of Dollars) | |||||||||||||||||||||||||||||||||||||||||||
| By Regulated Utility | 2022 | 2023 | 2024 | 2025 | 2026 | 2027 | 2023 - 2027 Total | |||||||||||||||||||||||||||||||||||||
| PSCo | $ | 1,940 | $ | 2,140 | $ | 2,440 | $ | 2,550 | $ | 1,980 | $ | 2,190 | $ | 11,300 | ||||||||||||||||||||||||||||||
| NSP-Minnesota | 1,980 | 2,000 | 2,400 | 2,530 | 2,200 | 2,580 | 11,710 | |||||||||||||||||||||||||||||||||||||
| SPS | 610 | 710 | 780 | 720 | 770 | 900 | 3,880 | |||||||||||||||||||||||||||||||||||||
| NSP-Wisconsin | 370 | 540 | 570 | 500 | 450 | 540 | 2,600 | |||||||||||||||||||||||||||||||||||||
Other (a) | (10) | 10 | 10 | (30) | 10 | 10 | 10 | |||||||||||||||||||||||||||||||||||||
| Total base capital expenditures | $ | 4,890 | $ | 5,400 | $ | 6,200 | $ | 6,270 | $ | 5,410 | $ | 6,220 | $ | 29,500 | ||||||||||||||||||||||||||||||
(a) Other category includes intercompany transfers for safe harbor wind turbines.
| Actual | Base Capital Forecast (Millions of Dollars) | |||||||||||||||||||||||||||||||||||||||||||
| By Function | 2022 | 2023 | 2024 | 2025 | 2026 | 2027 | 2023 - 2027 Total | |||||||||||||||||||||||||||||||||||||
| Electric distribution | $ | 1,370 | $ | 1,610 | $ | 1,790 | $ | 1,680 | $ | 2,000 | $ | 2,450 | $ | 9,530 | ||||||||||||||||||||||||||||||
| Electric transmission | 960 | 1,280 | 1,650 | 1,890 | 1,690 | 1,900 | 8,410 | |||||||||||||||||||||||||||||||||||||
| Electric generation | 720 | 710 | 910 | 900 | 560 | 650 | 3,730 | |||||||||||||||||||||||||||||||||||||
| Natural gas | 730 | 740 | 730 | 760 | 650 | 680 | 3,560 | |||||||||||||||||||||||||||||||||||||
| Other | 700 | 780 | 840 | 570 | 510 | 540 | 3,240 | |||||||||||||||||||||||||||||||||||||
| Renewables | 410 | 280 | 280 | 470 | — | — | 1,030 | |||||||||||||||||||||||||||||||||||||
| Total base capital expenditures | $ | 4,890 | $ | 5,400 | $ | 6,200 | $ | 6,270 | $ | 5,410 | $ | 6,220 | $ | 29,500 | ||||||||||||||||||||||||||||||
The base five-year capital forecast includes transmission expansion through the proposed Colorado Pathway (approximately $1.7 billion) and MISO Tranche 1 (approximately $1.2 billion) as well as the proposed 460 MW Sherco Solar Generating Unit 1 and 2 (approximately $600 million).
The base capital investment plan does not include any potential renewable generation assets approved in our Minnesota and Colorado resource plans or additional transmission capital needed to integrate new renewable generation additions in Colorado, beyond the Pathway project.
We expect further clarification in the second half of 2023 after the commissions rule on the recommended resource plan portfolios, which could result in incremental capital expenditures of approximately $2 to $4 billion (assuming 50% ownership of the renewable projects). Furthermore, the base capital investment plan does not include any potential generation assets associated with our 2022 SPS Request for Proposal, which seeks up to 947 MW of new or existing capacity resources.
Xcel Energy’s capital expenditure forecast is subject to continuing review and modification. Actual capital expenditures may vary from estimates due to changes in electric and natural gas projected load growth, safety and reliability needs, regulatory decisions, legislative initiatives (e.g., federal clean energy and tax policy), reserve requirements, availability of purchased power, alternative plans for meeting long-term energy needs, environmental initiatives and regulation, and merger, acquisition and divestiture opportunities.
Financing for Capital Expenditures through 2027 — Xcel Energy issues debt and equity securities to refinance retiring maturities, reduce short-term debt, fund capital programs, infuse equity in subsidiaries, fund asset acquisitions and for other general corporate purposes.
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Current estimated financing plans of Xcel Energy for 2023 through 2027:
(a)Net of dividends and pension funding.
(b)Reflects a combination of short and long-term debt; net of refinancing.
Off-Balance Sheet Arrangements
Xcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.
Common Stock Dividends — Future dividend levels will be dependent on Xcel Energy’s results of operations, financial condition, cash flows, reinvestment opportunities and other factors, and will be evaluated by the Xcel Energy Inc. Board of Directors. In February 2023, Xcel Energy announced an increase in the annual dividend of 13 cents per share, which represents an increase of 6.7%.
Xcel Energy’s dividend policy balances the following:
•Projected cash generation.
•Projected capital investment.
•A reasonable rate of return on shareholder investment.
•The impact on Xcel Energy’s capital structure and credit ratings.
In addition, there are certain statutory limitations that could affect dividend levels. Federal law places limits on the ability of public utilities within a holding company to declare dividends. Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. The utility subsidiaries’ dividends may be limited directly or indirectly by state regulatory commissions or bond indenture covenants.
See Note 5 to the consolidated financial statements for further information.
Pension Fund — Xcel Energy’s pension assets are invested in a diversified portfolio of domestic and international equity securities, short-term to long-duration fixed income securities and alternative investments, including private equity, real estate and hedge funds.
Funded status and pension assumptions:
| (Millions of Dollars) | Dec. 31, 2022 | Dec. 31, 2021 | ||||||||||||
| Fair value of pension assets | $ | 2,685 | $ | 3,670 | ||||||||||
Projected pension obligation (a) | 2,871 | 3,718 | ||||||||||||
| Funded status | $ | (186) | $ | (48) | ||||||||||
(a)Excludes non-qualified plan of $11 million and $43 million at Dec. 31, 2022 and 2021, respectively.
| Pension Assumptions | 2022 | 2021 | ||||||||||||
| Discount rate | 5.80 | % | 3.08 | % | ||||||||||
| Expected long-term rate of return | 6.93 | 6.49 | ||||||||||||
Capital Sources
Short-Term Funding Sources — Xcel Energy generally funds short-term needs, through operating cash flows, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend on construction expenditures, working capital and dividend payments.
Short-Term Investments — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash and short-term investment accounts.
Short-Term Debt — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. Authorized levels for these commercial paper programs are:
•$1.50 billion for Xcel Energy Inc.
•$700 million for PSCo.
•$700 million for NSP-Minnesota.
•$500 million for SPS.
•$150 million for NSP-Wisconsin.
See Note 5 to the consolidated financial statements for further information.
Credit Facility Agreements — Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of the revolving credit facility for two additional one-year periods. NSP-Wisconsin has the right to request an extension of the revolving credit facility for an additional year. All extension requests are subject to majority bank group approval.
As of Feb. 22, 2023, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:
| (Millions of Dollars) | Facility (a) | Drawn (b) | Available | Cash | Liquidity | |||||||||||||||||||||||||||
| Xcel Energy Inc. | $ | 1,500 | $ | 328 | $ | 1,172 | $ | 6 | $ | 1,178 | ||||||||||||||||||||||
| PSCo | 700 | 123 | 577 | 5 | 582 | |||||||||||||||||||||||||||
| NSP-Minnesota | 700 | 186 | 514 | 6 | 520 | |||||||||||||||||||||||||||
| SPS | 500 | 91 | 409 | 2 | 411 | |||||||||||||||||||||||||||
| NSP-Wisconsin | 150 | 29 | 121 | 2 | 123 | |||||||||||||||||||||||||||
| Total | $ | 3,550 | $ | 757 | $ | 2,793 | $ | 21 | $ | 2,814 | ||||||||||||||||||||||
(a)Credit facilities expire in September 2027.
(b)Includes outstanding commercial paper and letters of credit.
Registration Statements — Xcel Energy Inc.’s Articles of Incorporation authorize the issuance of one billion shares of $2.50 par value common stock. As of Dec. 31, 2022 and 2021, Xcel Energy had approximately 550 million shares and 544 million shares of common stock outstanding, respectively.
Xcel Energy Inc. and its utility subsidiaries have registration statements on file with the SEC pursuant to which they may sell securities from time to time. These registration statements, which are uncapped, permit Xcel Energy Inc. and its utility subsidiaries to issue debt and other securities in the future at amounts, prices and with terms to be determined at the time of future offerings, and in the case of our utility subsidiaries, subject to commission approval.
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Planned Financing Activity — Xcel Energy’s 2023 financing plans reflect the following:
| (Millions of Dollars) | Security | Amount | Anticipated Timing | |||||||||||||||||
| Xcel Energy Inc. | Senior Unsecured Bonds | $ | 500 | Third Quarter | ||||||||||||||||
| PSCo | First Mortgage Bonds | 700 | Second Quarter | |||||||||||||||||
| SPS | First Mortgage Bonds | 100 | Third Quarter | |||||||||||||||||
| NSP-Minnesota | First Mortgage Bonds | 750 | Second Quarter | |||||||||||||||||
| NSP-Wisconsin | First Mortgage Bonds | 125 | Second Quarter | |||||||||||||||||
Long-Term Borrowings, Equity Issuances and Other Financing Instruments — Xcel Energy also plans to issue approximately $85 million of equity annually through the DRIP and benefit programs during the five-year forecast time period.
See Note 5 to the consolidated financial statements for further information.
Earnings Guidance and Long-Term EPS and Dividend Growth Rate Objectives
Xcel Energy 2023 Earnings Guidance — Xcel Energy’s 2023 GAAP and ongoing earnings guidance is a range of $3.30 to $3.40 per share.(a)
Key assumptions as compared with 2022 levels unless noted:
•Constructive outcomes in all rate case and regulatory proceedings.
•Normal weather patterns for the year.
•Weather-normalized retail electric sales are projected to increase ~1%.
•Weather-normalized retail firm natural gas sales are projected to increase ~1%.
•Capital rider revenue is projected to increase $90 million to $100 million (net of PTCs).
•O&M expenses are projected to decline ~2%.
•Depreciation expense is projected to increase approximately $130 million to $140 million.
•Property taxes are projected to increase approximately $35 million to $45 million.
•Interest expense (net of AFUDC - debt) is projected to increase $100 million to $110 million.
•AFUDC - equity is projected to increase $0 million to $10 million.
•ETR is projected to be ~(5%) to (7%).
(a)Ongoing earnings is calculated using net income and adjusting for certain nonrecurring or infrequent items that are, in management’s view, not reflective of ongoing operations. Ongoing earnings could differ from those prepared in accordance with GAAP for unplanned and/or unknown adjustments. Xcel Energy is unable to forecast if any of these items will occur or provide a quantitative reconciliation of the guidance for ongoing EPS to corresponding GAAP EPS.
Long-Term EPS and Dividend Growth Rate Objectives — Xcel Energy expects to deliver an attractive total return to our shareholders through a combination of earnings growth and dividend yield, based on the following long-term objectives:
• Deliver long-term annual EPS growth of 5% to 7% based off of a 2022 base of $3.15 per share, which represents the mid-point of the original 2022 guidance range of $3.10 to $3.20 per share.
• Deliver annual dividend increases of 5% to 7%.
• Target a dividend payout ratio of 60% to 70%.
• Maintain senior secured debt credit ratings in the A range.
ITEM 7A — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK | ||
See the “Derivatives, Risk Management and Market Risk” section in Item 7, incorporated by reference.
ITEM 8 — FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA | ||
See Item 15-1 for an index of financial statements included herein.
See Note 15 to the consolidated financial statements for further information.
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Management Report on Internal Control Over Financial Reporting
The management of Xcel Energy Inc. is responsible for establishing and maintaining adequate internal control over financial reporting. Xcel Energy Inc.’s internal control system was designed to provide reasonable assurance to Xcel Energy Inc.’s management and Board of Directors regarding the preparation and fair presentation of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Xcel Energy Inc. management assessed the effectiveness of Xcel Energy Inc.’s internal control over financial reporting as of Dec. 31, 2022. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (2013). Based on our assessment, we believe that, as of Dec. 31, 2022, Xcel Energy Inc.’s internal control over financial reporting is effective at the reasonable assurance level based on those criteria.
Xcel Energy Inc.’s independent registered public accounting firm has issued an attestation report on Xcel Energy Inc.’s internal control over financial reporting. Its report appears herein.
| /s/ ROBERT C. FRENZEL | /s/ BRIAN J. VAN ABEL | |||||||||||||
| Robert C. Frenzel | Brian J. Van Abel | |||||||||||||
| Chairman, President, Chief Executive Officer and Director | Executive Vice President, Chief Financial Officer | |||||||||||||
| Feb. 23, 2023 | Feb. 23, 2023 | |||||||||||||
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholders and the Board of Directors of Xcel Energy Inc.
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Xcel Energy Inc. and subsidiaries (the "Company") as of December 31, 2022 and 2021, the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows, for each of the three years in the period ended December 31, 2022, and the related notes and the schedules listed in the Index at Item 15 (collectively referred to as the "financial statements"). We also have audited the Company’s internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the financial statements referred to above 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. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.
Basis for Opinions
The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Controls over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to 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. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
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.
46
Regulatory Assets and Liabilities - Impact of Rate Regulation on the Financial Statements — Refer to Notes 4 and 12 to the consolidated financial statements.
Critical Audit Matter Description
The Company is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico, and Texas. The Company is also subject to the jurisdiction of the Federal Energy Regulatory Commission for its wholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with North American Electric Reliability Corporation standards, asset transactions and mergers and natural gas transactions in interstate commerce, (collectively with state utility regulatory agencies, the “Commissions”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation affects multiple financial statement line items and disclosures, including property, plant and equipment, regulatory assets and liabilities, operating revenues and expenses, and income taxes.
The Company is subject to regulatory rate setting processes. Rates are determined and approved in regulatory proceedings based on an analysis of the Company’s costs to provide utility service and a return on, and recovery of, the Company’s investment in assets required to deliver services to customers. Accounting for the Company’s regulated operations provides that rate-regulated entities report assets and liabilities consistent with the recovery of those incurred costs in rates, if it is probable that such rates will be charged and collected. The Commissions’ regulation of rates is premised on the full recovery of incurred costs and a reasonable rate of return on invested capital. Decisions by the Commissions in the future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. In the rate setting process, the Company’s rates result in the recording of regulatory assets and liabilities based on the probability of future cash flows. Regulatory assets generally represent incurred or accrued costs that have been deferred because future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant, and 3) a refund due to customers. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the recognition of regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the Commissions for the Company, regulatory statutes, interpretations, procedural schedules and memorandums, filings made by intervenors, experts’ testimony and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We also evaluated regulatory filings for any evidence that intervenors are challenging full recovery of the cost of any capital projects. If the full recovery of project costs is being challenged by intervenors, we evaluated management’s assessment of the probability of a disallowance. We evaluated the external information and compared to the Company’s recorded regulatory assets and liabilities for completeness.
•We obtained management’s analysis and correspondence from counsel, as appropriate, regarding regulatory assets or liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
/s/ DELOITTE & TOUCHE LLP | ||
| Minneapolis, Minnesota | ||
| February 23, 2023 | ||
| We have served as the Company’s auditor since 2002. | ||
47
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(amounts in millions, except per share data)
| Year Ended Dec. 31 | ||||||||||||||||||||
| 2022 | 2021 | 2020 | ||||||||||||||||||
| Operating revenues | ||||||||||||||||||||
| Electric | $ | 12,123 | $ | 11,205 | $ | 9,802 | ||||||||||||||
| Natural gas | 3,080 | 2,132 | 1,636 | |||||||||||||||||
| Other | 107 | 94 | 88 | |||||||||||||||||
| Total operating revenues | 15,310 | 13,431 | 11,526 | |||||||||||||||||
| Operating expenses | ||||||||||||||||||||
| Electric fuel and purchased power | 5,005 | 4,733 | 3,512 | |||||||||||||||||
| Cost of natural gas sold and transported | 1,910 | 1,081 | 689 | |||||||||||||||||
| Cost of sales — other | 44 | 38 | 37 | |||||||||||||||||
| Operating and maintenance expenses | 2,491 | 2,321 | 2,324 | |||||||||||||||||
| Conservation and demand side management expenses | 331 | 304 | 288 | |||||||||||||||||
| Depreciation and amortization | 2,413 | 2,121 | 1,948 | |||||||||||||||||
| Taxes (other than income taxes) | 688 | 630 | 612 | |||||||||||||||||
| Total operating expenses | 12,882 | 11,228 | 9,410 | |||||||||||||||||
| Operating income | 2,428 | 2,203 | 2,116 | |||||||||||||||||
| Other (expense) income, net | (13) | 5 | (6) | |||||||||||||||||
| Earnings from equity method investments | 36 | 62 | 40 | |||||||||||||||||
| Allowance for funds used during construction — equity | 75 | 73 | 115 | |||||||||||||||||
| Interest charges and financing costs | ||||||||||||||||||||
Interest charges — includes other financing costs of $31, $29 and $28, respectively | 953 | 842 | 840 | |||||||||||||||||
| Allowance for funds used during construction — debt | (28) | (26) | (42) | |||||||||||||||||
| Total interest charges and financing costs | 925 | 816 | 798 | |||||||||||||||||
| Income before income taxes | 1,601 | 1,527 | 1,467 | |||||||||||||||||
| Income tax benefit | (135) | (70) | (6) | |||||||||||||||||
| Net income | $ | 1,736 | $ | 1,597 | $ | 1,473 | ||||||||||||||
| Weighted average common shares outstanding: | ||||||||||||||||||||
| Basic | 547 | 539 | 527 | |||||||||||||||||
| Diluted | 547 | 540 | 528 | |||||||||||||||||
| Earnings per average common share: | ||||||||||||||||||||
| Basic | $ | 3.18 | $ | 2.96 | $ | 2.79 | ||||||||||||||
| Diluted | 3.17 | 2.96 | 2.79 | |||||||||||||||||
| See Notes to Consolidated Financial Statements | ||||||||||||||||||||
48
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(amounts in millions)
| Year Ended Dec. 31 | ||||||||||||||||||||
| 2022 | 2021 | 2020 | ||||||||||||||||||
| Net income | $ | 1,736 | $ | 1,597 | $ | 1,473 | ||||||||||||||
| Other comprehensive income | ||||||||||||||||||||
| Pension and retiree medical benefits: | ||||||||||||||||||||
Net pension and retiree medical gains (losses) arising during the period, net of tax of $1, $— and $(2), respectively | 5 | — | (5) | |||||||||||||||||
Reclassification of losses to net income, net of tax of $1, $3 and $3, respectively | 4 | 8 | 10 | |||||||||||||||||
| Derivative instruments: | ||||||||||||||||||||
Net fair value increase (decrease), net of tax of $6, $1 and $(3), respectively | 16 | 4 | (10) | |||||||||||||||||
Reclassification of losses to net income, net of tax of $2, $2 and $2, respectively | 5 | 6 | 5 | |||||||||||||||||
| Total other comprehensive income | 30 | 18 | — | |||||||||||||||||
| Total comprehensive income | $ | 1,766 | $ | 1,615 | $ | 1,473 | ||||||||||||||
| See Notes to Consolidated Financial Statements | ||||||||||||||||||||
49
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(amounts in millions)
| Year Ended Dec. 31 | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| Operating activities | |||||||||||||||||
| Net income | $ | 1,736 | $ | 1,597 | $ | 1,473 | |||||||||||
| Adjustments to reconcile net income to cash provided by operating activities: | |||||||||||||||||
| Depreciation and amortization | 2,436 | 2,143 | 1,959 | ||||||||||||||
| Nuclear fuel amortization | 118 | 114 | 123 | ||||||||||||||
| Deferred income taxes | (140) | (79) | (8) | ||||||||||||||
| Allowance for equity funds used during construction | (75) | (73) | (115) | ||||||||||||||
| Earnings from equity method investments | (36) | (62) | (40) | ||||||||||||||
| Dividends from equity method investments | 37 | 42 | 42 | ||||||||||||||
| Provision for bad debts | 73 | 60 | 60 | ||||||||||||||
| Share-based compensation expense | 20 | 31 | 73 | ||||||||||||||
| Changes in operating assets and liabilities: | |||||||||||||||||
| Accounts receivable | (429) | (164) | (154) | ||||||||||||||
| Accrued unbilled revenues | (243) | (149) | (3) | ||||||||||||||
| Inventories | (203) | (126) | (80) | ||||||||||||||
| Other current assets | (58) | (34) | (45) | ||||||||||||||
| Accounts payable | 195 | 138 | (33) | ||||||||||||||
| Net regulatory assets and liabilities | 570 | (973) | (144) | ||||||||||||||
| Other current liabilities | 102 | (1) | 29 | ||||||||||||||
| Pension and other employee benefit obligations | (49) | (135) | (125) | ||||||||||||||
| Other, net | (122) | (140) | (164) | ||||||||||||||
| Net cash provided by operating activities | 3,932 | 2,189 | 2,848 | ||||||||||||||
| Investing activities | |||||||||||||||||
| Capital/construction expenditures | (4,638) | (4,244) | (5,369) | ||||||||||||||
| Sale of MEC | — | — | 684 | ||||||||||||||
| Purchase of investment securities | (1,332) | (757) | (1,398) | ||||||||||||||
| Proceeds from the sale of investment securities | 1,297 | 743 | 1,378 | ||||||||||||||
| Other, net | 20 | (29) | (35) | ||||||||||||||
| Net cash used in investing activities | (4,653) | (4,287) | (4,740) | ||||||||||||||
| Financing activities | |||||||||||||||||
| (Repayments of) proceeds from short-term borrowings, net | (192) | 421 | (11) | ||||||||||||||
| Proceeds from issuances of long-term debt | 2,164 | 2,710 | 2,940 | ||||||||||||||
| Repayments of long-term debt | (601) | (417) | (1,001) | ||||||||||||||
| Proceeds from issuance of common stock | 322 | 366 | 727 | ||||||||||||||
| Dividends paid | (1,012) | (935) | (856) | ||||||||||||||
| Other, net | (15) | (10) | (26) | ||||||||||||||
| Net cash provided by financing activities | 666 | 2,135 | 1,773 | ||||||||||||||
| Net change in cash and cash equivalents | (55) | 37 | (119) | ||||||||||||||
| Cash, cash equivalents and restricted cash at beginning of period | 166 | 129 | 248 | ||||||||||||||
| Cash, cash equivalents and restricted cash at end of period | $ | 111 | $ | 166 | $ | 129 | |||||||||||
| Supplemental disclosure of cash flow information: | |||||||||||||||||
| Cash paid for interest (net of amounts capitalized) | $ | (887) | $ | (788) | $ | (758) | |||||||||||
| Cash (paid) received for income taxes, net | (15) | (4) | 12 | ||||||||||||||
| Supplemental disclosure of non-cash investing and financing transactions: | |||||||||||||||||
| Accrued property, plant and equipment additions | $ | 626 | $ | 501 | $ | 400 | |||||||||||
| Inventory transfers to property, plant and equipment | 78 | 87 | 275 | ||||||||||||||
| Operating lease right-of-use assets | 141 | 8 | 369 | ||||||||||||||
| Allowance for equity funds used during construction | 75 | 73 | 115 | ||||||||||||||
| Issuance of common stock for reinvested dividends and/or equity awards | 57 | 60 | 67 | ||||||||||||||
| See Notes to Consolidated Financial Statements | |||||||||||||||||
50
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(amounts in millions, except share and per share)
| Dec. 31 | ||||||||||||||
| 2022 | 2021 | |||||||||||||
| Assets | ||||||||||||||
| Current assets | ||||||||||||||
| Cash and cash equivalents | $ | 111 | $ | 166 | ||||||||||
| Accounts receivable, net | 1,373 | 1,018 | ||||||||||||
| Accrued unbilled revenues | 1,105 | 862 | ||||||||||||
| Inventories | 803 | 631 | ||||||||||||
| Regulatory assets | 1,059 | 1,106 | ||||||||||||
| Derivative instruments | 279 | 123 | ||||||||||||
| Prepaid taxes | 54 | 44 | ||||||||||||
| Prepayments and other | 360 | 289 | ||||||||||||
| Total current assets | 5,144 | 4,239 | ||||||||||||
| Property, plant and equipment, net | 48,253 | 45,457 | ||||||||||||
| Other assets | ||||||||||||||
| Nuclear decommissioning fund and other investments | 3,234 | 3,628 | ||||||||||||
| Regulatory assets | 2,871 | 2,738 | ||||||||||||
| Derivative instruments | 93 | 67 | ||||||||||||
| Operating lease right-of-use assets | 1,204 | 1,291 | ||||||||||||
| Other | 389 | 431 | ||||||||||||
| Total other assets | 7,791 | 8,155 | ||||||||||||
| Total assets | $ | 61,188 | $ | 57,851 | ||||||||||
| Liabilities and Equity | ||||||||||||||
| Current liabilities | ||||||||||||||
| Current portion of long-term debt | $ | 1,151 | $ | 601 | ||||||||||
| Short-term debt | 813 | 1,005 | ||||||||||||
| Accounts payable | 1,804 | 1,409 | ||||||||||||
| Regulatory liabilities | 418 | 271 | ||||||||||||
| Taxes accrued | 569 | 569 | ||||||||||||
| Accrued interest | 217 | 209 | ||||||||||||
| Dividends payable | 268 | 249 | ||||||||||||
| Derivative instruments | 76 | 69 | ||||||||||||
| Operating lease liabilities | 217 | 205 | ||||||||||||
| Other | 545 | 459 | ||||||||||||
| Total current liabilities | 6,078 | 5,046 | ||||||||||||
| Deferred credits and other liabilities | ||||||||||||||
| Deferred income taxes | 4,756 | 4,894 | ||||||||||||
| Deferred investment tax credits | 48 | 53 | ||||||||||||
| Regulatory liabilities | 5,569 | 5,405 | ||||||||||||
| Asset retirement obligations | 3,380 | 3,151 | ||||||||||||
| Derivative instruments | 113 | 105 | ||||||||||||
| Customer advances | 181 | 196 | ||||||||||||
| Pension and employee benefit obligations | 390 | 306 | ||||||||||||
| Operating lease liabilities | 1,038 | 1,146 | ||||||||||||
| Other | 147 | 158 | ||||||||||||
| Total deferred credits and other liabilities | 15,622 | 15,414 | ||||||||||||
| Commitments and contingencies | ||||||||||||||
| Capitalization | ||||||||||||||
| Long-term debt | 22,813 | 21,779 | ||||||||||||
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 549,578,018 and 544,025,269 shares outstanding at Dec. 31, 2022 and Dec. 31, 2021, respectively | 1,374 | 1,360 | ||||||||||||
| Additional paid in capital | 8,155 | 7,803 | ||||||||||||
| Retained earnings | 7,239 | 6,572 | ||||||||||||
| Accumulated other comprehensive loss | (93) | (123) | ||||||||||||
| Total common stockholders’ equity | 16,675 | 15,612 | ||||||||||||
| Total liabilities and equity | $ | 61,188 | $ | 57,851 | ||||||||||
| See Notes to Consolidated Financial Statements | ||||||||||||||
51
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
(amounts in millions, except per share data; shares in actual amounts)
| Common Stock Issued | Retained Earnings | Accumulated Other Comprehensive Loss | Total Common Stockholders’ Equity | ||||||||||||||||||||||||||||||||
| Shares | Par Value | Additional Paid In Capital | |||||||||||||||||||||||||||||||||
| Balance at Dec. 31, 2019 | 524,539,000 | $ | 1,311 | $ | 6,656 | $ | 5,413 | $ | (141) | $ | 13,239 | ||||||||||||||||||||||||
| Net income | 1,473 | 1,473 | |||||||||||||||||||||||||||||||||
Dividends declared on common stock ($1.72 per share) | (909) | (909) | |||||||||||||||||||||||||||||||||
| Issuances of common stock | 12,953,869 | 33 | 731 | 764 | |||||||||||||||||||||||||||||||
| Repurchases of common stock | (54,475) | — | (4) | (4) | |||||||||||||||||||||||||||||||
| Share-based compensation | 21 | (7) | 14 | ||||||||||||||||||||||||||||||||
| Adoption of ASC Topic 326 | (2) | (2) | |||||||||||||||||||||||||||||||||
| Balance at Dec. 31, 2020 | 537,438,394 | $ | 1,344 | $ | 7,404 | $ | 5,968 | $ | (141) | $ | 14,575 | ||||||||||||||||||||||||
| Net Income | 1,597 | 1,597 | |||||||||||||||||||||||||||||||||
| Other comprehensive loss | 18 | 18 | |||||||||||||||||||||||||||||||||
Dividends declared on common stock ($1.83 per share) | (989) | (989) | |||||||||||||||||||||||||||||||||
| Issuances of common stock | 6,586,875 | 16 | 387 | 403 | |||||||||||||||||||||||||||||||
| Share-based compensation | 12 | (4) | 8 | ||||||||||||||||||||||||||||||||
| Balance at Dec. 31, 2021 | 544,025,269 | $ | 1,360 | $ | 7,803 | $ | 6,572 | $ | (123) | $ | 15,612 | ||||||||||||||||||||||||
| Net income | 1,736 | 1,736 | |||||||||||||||||||||||||||||||||
| Other comprehensive income | 30 | 30 | |||||||||||||||||||||||||||||||||
Dividends declared on common stock ($1.95 per share) | (1,066) | (1,066) | |||||||||||||||||||||||||||||||||
| Issuances of common stock | 5,552,749 | 14 | 345 | 359 | |||||||||||||||||||||||||||||||
| Share-based compensation | 7 | (3) | 4 | ||||||||||||||||||||||||||||||||
| Balance at Dec. 31, 2022 | 549,578,018 | $ | 1,374 | $ | 8,155 | $ | 7,239 | $ | (93) | $ | 16,675 | ||||||||||||||||||||||||
| See Notes to Consolidated Financial Statements | |||||||||||||||||||||||||||||||||||
52
XCEL ENERGY INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
1. Summary of Significant Accounting Policies | ||
General — Xcel Energy Inc.’s utility subsidiaries are engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and the regulated purchase, transportation, distribution and sale of natural gas.
Xcel Energy’s regulated operations include the activities of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS. These utility subsidiaries serve electric and natural gas customers in portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin. Also included in regulated operations are WGI, an interstate natural gas pipeline company, and WYCO, a joint venture with CIG to develop and lease natural gas pipeline, storage and compression facilities.
Xcel Energy Inc.’s nonregulated subsidiaries include:
| Nonregulated Subsidiary | Purpose | |||||||
| Eloigne | Invests in rental housing projects that qualify for low-income housing tax credits. | |||||||
| Capital Services | Procures equipment for construction of renewable generation facilities at other subsidiaries. | |||||||
| Venture Holdings | Invests in limited partnerships, including EIP funds with portfolios of investments in energy technology companies. | |||||||
| Nicollet Project Holdings | Invests in nonregulated assets such as the Minnesota community solar gardens. | |||||||
Xcel Energy Inc. owns the following additional direct subsidiaries, some of which are intermediate holding companies with additional subsidiaries:
| Direct Subsidiary | ||
| Xcel Energy Wholesale Group Inc. | ||
| Xcel Energy Market Holdings Inc. | ||
| Xcel Energy Ventures Inc. | ||
| Xcel Energy Retail Holdings Inc. | ||
| Xcel Energy Communication Group, Inc. | ||
| Xcel Energy International Inc. | ||
| Xcel Energy Transmission Holding Company, LLC | ||
| Nicollet Holdings Company, LLC | ||
| Xcel Energy Nuclear Services Holdings, LLC | ||
| Xcel Energy Services Inc. | ||
Xcel Energy and its subsidiaries collectively are referred to as Xcel Energy.
Xcel Energy’s consolidated financial statements include its wholly-owned subsidiaries and VIEs for which it is the primary beneficiary. All intercompany transactions and balances are eliminated unless a different treatment is appropriate for rate regulated transactions. The equity method of accounting is used for its investments in EIP funds and WYCO.
Investments in certain plants and transmission facilities are jointly owned with nonaffiliated utilities. A proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets, and Xcel Energy’s share of operating costs associated with these facilities is included in the consolidated statements of income.
The consolidated financial statements are presented in accordance with GAAP. All of the utility subsidiaries’ underlying accounting records also conform to the FERC uniform system of accounts.
Certain amounts in the consolidated financial statements or notes have been reclassified for comparative purposes; however, such reclassifications did not affect net income, total assets, liabilities, equity or cash flows.
Xcel Energy has evaluated events occurring after Dec. 31, 2022 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.
Use of Estimates — Xcel Energy 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 — The regulated utility subsidiaries account 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, the utility subsidiaries 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 Xcel Energy’s results of operations, financial condition and cash flows.
See Note 4 for further information.
Income Taxes — Xcel Energy 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.
Rates are utilized 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.
Xcel Energy 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.
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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 Xcel Energy tax elections. For tax credits otherwise eligible to be recognized when earned, Xcel Energy 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.
Xcel Energy measures and discloses uncertain tax positions that it has taken or expects to take in its income tax returns. A tax position is recognized in the consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position. Recognition of changes in uncertain tax positions are reflected as a component of income tax expense.
Interest and penalties related to income taxes are reported within other (expense) income or interest charges in the consolidated statements of income.
Xcel Energy Inc. and its subsidiaries file consolidated federal income tax returns as well as consolidated or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to its subsidiaries based on separate company computations. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with consolidated state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries.
See Note 7 for further information.
Property, Plant and Equipment and Depreciation in Regulated Operations — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred.
Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary.
Depreciation expense is recorded using the straight-line method over the plant’s commission approved useful life. Actuarial life studies are performed and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Plant removal costs are typically recognized at the amounts recovered in rates as authorized by the applicable regulator. Accumulated removal costs are reflected in the consolidated balance sheet as a regulatory liability. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.7% for 2022, 3.5% for 2021 and 3.4% for 2020.
See Note 3 for further information.
AROs — Xcel Energy 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 12 for further information.
Nuclear Decommissioning — Nuclear decommissioning studies that estimate NSP-Minnesota’s costs of decommissioning its nuclear power plants are normally performed at least every years and submitted to the state commissions for approval. Due to other regulatory activity, the next decommissioning study has been deferred one year until 2024.
NSP-Minnesota recovers regulator-approved decommissioning costs of its nuclear power plants over each facility’s expected service life, typically based on the triennial decommissioning studies. The studies consider estimated future costs of decommissioning and the market value of investments in trust funds and recommend annual funding amounts. Amounts collected in rates are deposited in the trust funds. For financial reporting purposes, NSP-Minnesota accounts for nuclear decommissioning as an ARO.
Restricted funds for the payment of future decommissioning expenditures for NSP-Minnesota’s nuclear facilities are included in nuclear decommissioning fund and other assets on the consolidated balance sheets.
See Notes 10 and 12 for further information.
Benefit Plans and Other Postretirement Benefits — Xcel Energy 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 11 for further information.
Environmental Costs — Environmental costs are recorded when it is probable Xcel Energy 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.
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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 Xcel Energy’s expected share of the cost.
Future costs of restoring sites are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.
See Note 12 for further information.
Revenue from Contracts with Customers — Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. Xcel Energy 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. The utility subsidiaries recognize 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 — Xcel Energy considers investments in instruments with a remaining maturity of 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. Xcel Energy 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 $122 million and $106 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 | $ | 330 | $ | 289 | ||||||||||
| Fuel | 201 | 182 | ||||||||||||
| Natural gas | 272 | 160 | ||||||||||||
| Total inventories | $ | 803 | $ | 631 | ||||||||||
Equity Method Investments — The equity method of accounting is used for certain investments including WYCO and EIP funds, which requires Xcel Energy’s recognition of its share of these investees’ results, based on Xcel Energy’s proportional ownership interest. For investments in EIP funds, this includes Xcel Energy’s share of fund expenses and realized gains and losses, as well as unrealized gains and losses resulting from valuations of the funds’ investments in emerging energy technology companies.
Fair Value Measurements — Xcel Energy presents cash equivalents, interest rate derivatives, commodity derivatives and nuclear decommissioning fund assets at estimated fair values in its consolidated financial statements.
For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used to estimate fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price, quoted prices for similar contracts or internally prepared valuation models may be used to determine fair value.
For the pension and postretirement plan assets and nuclear decommissioning fund, published trading data and pricing models, generally using the most observable inputs available, are utilized to determine fair value for each security.
See Notes 10 and 11 for further information.
Derivative Instruments — Xcel Energy uses derivative instruments in connection with its commodity trading activities, and to manage risk associated with changes in interest rates, and utility commodity prices, including forward contracts, futures, swaps and options. Any derivative instruments not qualifying for the normal purchases and normal sales exception are recorded on the consolidated balance sheets at fair value as derivative instruments. Classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship.
Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.
Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues.
Normal Purchases and Normal Sales — Xcel Energy 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 10 for further information.
Commodity Trading Operations — All applicable gains and losses related to commodity trading activities are shown on a net basis in electric operating revenues in the consolidated statements of income.
Commodity trading activities are not associated with energy produced from generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms.
See Note 10 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 Xcel Energy’s rate base.
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Alternative Revenue — Certain rate rider mechanisms (including decoupling/sales true up and CIP/DSM programs) qualify as alternative revenue programs. These mechanisms arise from instances in which the regulator authorizes a future surcharge in response to past activities or completed events. When certain criteria are met, including expected collection within 24 months, revenue is recognized, which may include incentives and return on rate base items.
Billing amounts are revised periodically for differences between total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers.
See Note 6 for further information.
Conservation Programs — Costs incurred for DSM and CIP programs are deferred if it is probable future revenue will recover the incurred cost. Revenues recognized for incentive programs for the recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the year they are earned. Regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers.
Emissions Allowances — Emissions allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emissions allowances and any sales of these allowances are included in electric revenues.
Nuclear Refueling Outage Costs — Xcel Energy uses a deferral and amortization method for nuclear refueling costs. This method amortizes costs over the period between refueling outages consistent with rate recovery.
RECs — Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. In certain jurisdictions, Xcel Energy 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. The cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.
Cost of RECs that are utilized to support commodity trading activities are recorded in a similar manner as the associated commodities and are on a net basis in electric operating revenues in the consolidated statements of income.
2. Accounting Pronouncements | ||
As of Dec. 31, 2022, there was no material impact from the recent adoption of new accounting pronouncements, nor expected material impact from recently issued accounting pronouncements yet to be adopted, on Xcel Energy’s consolidated financial statements.
3. Property, Plant and Equipment | ||
Major classes of property, plant and equipment
| (Millions of Dollars) | Dec. 31, 2022 | Dec. 31, 2021 | ||||||||||||
| Property, plant and equipment, net | ||||||||||||||
| Electric plant | $ | 49,639 | $ | 48,680 | ||||||||||
| Natural gas plant | 8,514 | 7,758 | ||||||||||||
| Common and other property | 2,970 | 2,602 | ||||||||||||
Plant to be retired (a) | 2,217 | 1,200 | ||||||||||||
| CWIP | 2,124 | 1,969 | ||||||||||||
| Total property, plant and equipment | 65,464 | 62,209 | ||||||||||||
| Less accumulated depreciation | (17,502) | (17,060) | ||||||||||||
| Nuclear fuel | 3,183 | 3,081 | ||||||||||||
| Less accumulated amortization | (2,892) | (2,773) | ||||||||||||
| Property, plant and equipment, net | $ | 48,253 | $ | 45,457 | ||||||||||
(a)Amounts as of Dec. 31, 2021 include Sherco Units 1, 2 and 3 and A.S. King for NSP-Minnesota; Comanche Unit 1 and 2 and Craig Units 1 and 2 for PSCo; and Tolk and coal generation assets at Harrington pending facility gas conversion for SPS. Following the June 2022 approval of PSCo’s revised resource plan settlement, amounts as of Dec. 31, 2022 include the addition of Comanche Unit 3, Hayden Units 1 and 2 and coal generation assets at Pawnee pending facility gas conversion as well as the removal of Comanche Unit 1 that was retired in 2022. Amounts are presented net of accumulated depreciation.
Joint Ownership of Generation, Transmission and Gas Facilities
The utility subsidiaries’ jointly owned assets as of Dec. 31, 2022:
| (Millions of Dollars, Except Percent Owned) | Plant in Service | Accumulated Depreciation | Percent Owned | |||||||||||||||||
| NSP-Minnesota | ||||||||||||||||||||
| Electric generation: | ||||||||||||||||||||
| Sherco Unit 3 | $ | 623 | $ | 468 | 59 | % | ||||||||||||||
| Sherco common facilities | 180 | 115 | 80 | |||||||||||||||||
| Sherco substation | 5 | 4 | 59 | |||||||||||||||||
| Electric transmission: | ||||||||||||||||||||
| Grand Meadow | 11 | 3 | 50 | |||||||||||||||||
| Huntley Wilmarth | 49 | 1 | 50 | |||||||||||||||||
| CapX2020 | 818 | 124 | 51 | |||||||||||||||||
Total NSP-Minnesota (a) | $ | 1,686 | $ | 715 | ||||||||||||||||
(a)Projects additionally include $4 million in CWIP.
| (Millions of Dollars, Except Percent Owned) | Plant in Service | Accumulated Depreciation | Percent Owned | |||||||||||||||||
| NSP-Wisconsin | ||||||||||||||||||||
| Electric transmission: | ||||||||||||||||||||
| La Crosse, WI to Madison, WI | $ | 177 | $ | 20 | 37 | % | ||||||||||||||
| CapX2020 | 166 | 34 | 80 | |||||||||||||||||
Total NSP-Wisconsin (a) | $ | 343 | $ | 54 | ||||||||||||||||
(a)Projects additionally include $1 million in CWIP.
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| (Millions of Dollars, Except Percent Owned) | Plant in Service | Accumulated Depreciation | Percent Owned | |||||||||||||||||
| PSCo | ||||||||||||||||||||
| Electric generation: | ||||||||||||||||||||
| Hayden Unit 1 | $ | 157 | $ | 99 | 76 | % | ||||||||||||||
| Hayden Unit 2 | 151 | 81 | 37 | |||||||||||||||||
| Hayden common facilities | 42 | 29 | 53 | |||||||||||||||||
| Craig Units 1 and 2 | 82 | 51 | 10 | |||||||||||||||||
| Craig common facilities | 39 | 24 | 7 | |||||||||||||||||
| Comanche Unit 3 | 918 | 174 | 67 | |||||||||||||||||
| Comanche common facilities | 28 | 3 | 82 | |||||||||||||||||
| Electric transmission: | ||||||||||||||||||||
| Transmission and other facilities | 186 | 72 | Various | |||||||||||||||||
| Gas transmission: | ||||||||||||||||||||
| Rifle, CO to Avon, CO | 25 | 9 | 60 | |||||||||||||||||
| Gas transmission compressor | 8 | 2 | 50 | |||||||||||||||||
Total PSCo (a) | $ | 1,636 | $ | 544 | ||||||||||||||||
(a)Projects additionally include $10 million in CWIP.
Each company’s share of operating expenses and construction expenditures is included in the applicable utility accounts. Respective owners are responsible for providing their own financing.
4. Regulatory Assets and Liabilities | ||
Regulatory assets and liabilities are created for amounts that regulators may allow to be collected or may require to be paid back to customers in future electric and natural gas rates. Xcel Energy 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 | 11 | Various | $ | 22 | $ | 1,069 | $ | 77 | $ | 944 | ||||||||||||||||||||||||||||
Net AROs (b) | 1, 12 | Various | — | 339 | — | (112) | ||||||||||||||||||||||||||||||||
| Deferred natural gas, electric, steam energy/fuel costs | to years | 581 | 299 | 504 | 543 | |||||||||||||||||||||||||||||||||
| Recoverable deferred taxes on AFUDC | Plant lives | — | 292 | — | 289 | |||||||||||||||||||||||||||||||||
Excess deferred taxes — TCJA | 7 | Various | 13 | 205 | 14 | 219 | ||||||||||||||||||||||||||||||||
| Depreciation differences | to 12 years | 17 | 193 | 16 | 173 | |||||||||||||||||||||||||||||||||
| Environmental remediation costs | 1, 12 | Various | 20 | 92 | 14 | 92 | ||||||||||||||||||||||||||||||||
| Benson biomass PPA termination and asset purchase | years | 10 | 45 | 10 | 55 | |||||||||||||||||||||||||||||||||
| PI extended power uprate | 12 years | 4 | 42 | 4 | 46 | |||||||||||||||||||||||||||||||||
Conservation programs (c) | 1 | to years | 16 | 36 | 21 | 35 | ||||||||||||||||||||||||||||||||
| Purchased power contract costs | Term of related contract | 10 | 36 | 9 | 45 | |||||||||||||||||||||||||||||||||
| State commission adjustments | Plant lives | 1 | 33 | 1 | 32 | |||||||||||||||||||||||||||||||||
| Losses on reacquired debt | Term of related debt | 3 | 32 | 3 | 35 | |||||||||||||||||||||||||||||||||
Contract valuation adjustments (d) | 1, 10 | Term of related contract | 28 | 28 | 22 | 34 | ||||||||||||||||||||||||||||||||
| Grid modernization costs | Various | 14 | 24 | — | 36 | |||||||||||||||||||||||||||||||||
| Gas pipeline inspection and remediation costs | to years | 42 | 13 | 33 | 12 | |||||||||||||||||||||||||||||||||
| Nuclear refueling outage costs | 1 | to years | 30 | 12 | 37 | 16 | ||||||||||||||||||||||||||||||||
| Renewable resources and environmental initiatives | to years | 50 | 6 | 170 | 48 | |||||||||||||||||||||||||||||||||
| Texas revenue surcharges | Less than year | 69 | — | 20 | 64 | |||||||||||||||||||||||||||||||||
| Sales true-up and revenue decoupling | to years | 54 | — | 33 | 56 | |||||||||||||||||||||||||||||||||
| Other | Various | 75 | 75 | 118 | 76 | |||||||||||||||||||||||||||||||||
| Total regulatory assets | $ | 1,059 | $ | 2,871 | $ | 1,106 | $ | 2,738 | ||||||||||||||||||||||||||||||
(a)Prior period amounts have been restated to conform with current year presentation.
(b)Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.
(c)Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.
(d)Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.
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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 | $ | 9 | $ | 3,110 | $ | 26 | $ | 3,230 | ||||||||||||||||||||||||||||
| Plant removal costs | 1, 12 | Various | — | 1,819 | — | 1,655 | ||||||||||||||||||||||||||||||||
Effects of regulation on employee benefit costs (c) | Various | — | 247 | — | 235 | |||||||||||||||||||||||||||||||||
| Renewable resources and environmental initiatives | Various | 6 | 173 | 1 | 101 | |||||||||||||||||||||||||||||||||
| Revenue decoupling | to years | — | 77 | 9 | 41 | |||||||||||||||||||||||||||||||||
ITC deferrals | 1 | Various | 1 | 61 | — | 53 | ||||||||||||||||||||||||||||||||
| Formula rates | to years | 32 | 17 | 19 | 11 | |||||||||||||||||||||||||||||||||
Contract valuation adjustments (d) | 1, 10 | to years | 175 | 1 | 56 | 1 | ||||||||||||||||||||||||||||||||
| Deferred natural gas, electric, steam energy/fuel costs | Less than year | 39 | — | 50 | — | |||||||||||||||||||||||||||||||||
Conservation programs (e) | 1 | Less than year | 72 | — | 42 | — | ||||||||||||||||||||||||||||||||
| DOE settlement | Various | 12 | 3 | 14 | 14 | |||||||||||||||||||||||||||||||||
| Other | Various | 72 | 61 | 54 | 64 | |||||||||||||||||||||||||||||||||
Total regulatory liabilities (f) | $ | 418 | $ | 5,569 | $ | 271 | $ | 5,405 | ||||||||||||||||||||||||||||||
(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 regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the PSCo prepaid pension asset.
(d)Includes the fair value of FTR instruments utilized/intended to offset the impacts of transmission system congestion.
(e)Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.
(f)Revenue subject to refund of $67 million and $17 million for 2022 and 2021, respectively, is included in other current liabilities.
Xcel Energy’s regulatory assets not earning a return include the unfunded portion of pension and retiree medical obligations and net AROs (i.e. deferrals for which cash has not been disbursed). In addition, regulatory assets included $1,020 million and $1,718 million at Dec. 31, 2022 and 2021 respectively, of past expenditures not earning a return. Amounts are predominately related to purchased natural gas and electric energy costs (including certain costs related to Winter Storm Uri), sales true-up and revenue decoupling, various renewable resources/environmental initiatives and certain prepaid pension amounts.
5. Borrowings and Other Financing Instruments | ||
Short-Term Borrowings
Short-Term Debt — Xcel Energy meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities and term loan agreements.
Commercial paper and other borrowings outstanding:
| (Millions of Dollars, Except Interest Rates) | Three Months Ended Dec. 31, 2022 | Year Ended Dec. 31 | ||||||||||||||||||||||||
| 2022 | 2021 | 2020 | ||||||||||||||||||||||||
| Borrowing limit | $ | 3,550 | $ | 3,550 | $ | 3,100 | $ | 3,100 | ||||||||||||||||||
| Amount outstanding at period end | 813 | 813 | 1,005 | 584 | ||||||||||||||||||||||
| Average amount outstanding | 416 | 552 | 1,399 | 1,126 | ||||||||||||||||||||||
| Maximum amount outstanding | 813 | 1,357 | 2,054 | 2,080 | ||||||||||||||||||||||
| Weighted average interest rate, computed on a daily basis | 4.20 | % | 1.47 | % | 0.57 | % | 1.45 | % | ||||||||||||||||||
| Weighted average interest rate at period end | 4.66 | 4.66 | 0.31 | 0.23 | ||||||||||||||||||||||
Bilateral Credit Agreement — In April 2022, NSP-Minnesota’s uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit.
As of Dec. 31, 2022, NSP-Minnesota had $54 million outstanding letters of credit under the $75 million Bilateral Credit Agreement.
Letters of Credit — Xcel Energy uses letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. As of Dec. 31, 2022 and 2021, there were $43 million and $19 million of letters of credit outstanding under the credit facilities, respectively. Amounts approximate their fair value.
Credit Facilities — In order to use commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper exceeding available capacity under these credit facilities.
The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.
Amended Credit Agreements — In September 2022, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each entered into an amended five-year credit agreement with a syndicate of banks. The aggregate borrowing limit was increased to $3.55 billion. The amended credit agreements have substantially the same terms and conditions as the prior agreements, with the following changes:
•Maturities extended from June 2024 to September 2027.
•Borrowing limit for Xcel Energy Inc. increased from $1.25 billion to $1.5 billion.
•Borrowing limit for NSP-Minnesota increased from $500 million to $700 million.
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Features of the credit facilities:
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 | |||||||||||||||||||||||||
Xcel Energy Inc. (c) | 60 | % | 60 | % | $ | 350 | 2 | |||||||||||||||||||
| NSP-Minnesota | 48 | 47 | 150 | 2 | ||||||||||||||||||||||
| NSP-Wisconsin | 47 | 49 | N/A | 1 | ||||||||||||||||||||||
| SPS | 46 | 47 | 50 | 2 | ||||||||||||||||||||||
| PSCo | 44 | 44 | 100 | 2 | ||||||||||||||||||||||
(a) Each 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.
(c) The Xcel Energy Inc. credit facility has a cross-default provision that Xcel Energy Inc. would be in default on its borrowings under the facility if it or any of its subsidiaries (except NSP-Wisconsin as long as its total assets do not comprise more than 15% of Xcel Energy’s consolidated total assets) default on indebtedness in an aggregate principal amount exceeding $75 million.
If Xcel Energy Inc. or its utility subsidiaries do 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, Xcel Energy Inc. and its subsidiaries were in compliance with all financial covenants.
Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available as of Dec. 31, 2022:
| (Millions of Dollars) | Credit Facility (a) | Drawn (b) | Available | |||||||||||||||||
| Xcel Energy Inc. | $ | 1,500 | $ | 231 | $ | 1,269 | ||||||||||||||
| PSCo | 700 | 321 | 379 | |||||||||||||||||
| NSP-Minnesota | 700 | 222 | 478 | |||||||||||||||||
| SPS | 500 | 36 | 464 | |||||||||||||||||
| NSP-Wisconsin | 150 | 47 | 103 | |||||||||||||||||
| Total | $ | 3,550 | $ | 857 | $ | 2,693 | ||||||||||||||
(a)These credit facilities mature in September 2027.
(b)Includes outstanding commercial paper and letters of credit.
All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facilities. Xcel Energy Inc. and its utility subsidiaries had no direct advances on facilities outstanding as of Dec. 31, 2022 and 2021.
Long-Term Borrowings and Other Financing Instruments
Generally, the property of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS is subject to the liens of their respective first mortgage indentures 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 Xcel Energy Inc. and its utility subsidiaries as of Dec. 31 (in millions of dollars):
| Xcel Energy Inc. | ||||||||||||||||||||||||||
| Financing Instrument | Interest Rate | Maturity Date | 2022 | 2021 | ||||||||||||||||||||||
| Unsecured senior notes | 0.50 | Oct. 15, 2023 | 500 | 500 | ||||||||||||||||||||||
| Unsecured senior notes | 3.30 | June 1, 2025 | 250 | 250 | ||||||||||||||||||||||
| Unsecured senior notes | 3.30 | June 1, 2025 | 350 | 350 | ||||||||||||||||||||||
| Unsecured senior notes | 3.35 | Dec. 1, 2026 | 500 | 500 | ||||||||||||||||||||||
Unsecured senior notes (a) | 1.75 | March 15,2027 | 500 | 500 | ||||||||||||||||||||||
| Unsecured senior notes | 4.00 | June 15, 2028 | 130 | 130 | ||||||||||||||||||||||
| Unsecured senior notes | 4.00 | June 15, 2028 | 500 | 500 | ||||||||||||||||||||||
| Unsecured senior notes | 2.60 | Dec. 1, 2029 | 500 | 500 | ||||||||||||||||||||||
| Unsecured senior notes | 3.40 | June 1, 2030 | 600 | 600 | ||||||||||||||||||||||
Unsecured senior notes (a) | 2.35 | Nov. 15, 2031 | 300 | 300 | ||||||||||||||||||||||
Unsecured senior notes (b) | 4.60 | June 1, 2032 | 700 | — | ||||||||||||||||||||||
| Unsecured senior notes | 6.50 | July 1, 2036 | 300 | 300 | ||||||||||||||||||||||
| Unsecured senior notes | 4.80 | Sep. 15, 2041 | 250 | 250 | ||||||||||||||||||||||
| Unsecured senior notes | 3.50 | Dec. 1, 2049 | 500 | 500 | ||||||||||||||||||||||
| Unamortized discount | (7) | (8) | ||||||||||||||||||||||||
| Unamortized debt issuance cost | (35) | (33) | ||||||||||||||||||||||||
| Current maturities | (500) | — | ||||||||||||||||||||||||
| Total long-term debt | $ | 5,338 | $ | 5,139 | ||||||||||||||||||||||
(a)2021 financing.
(b)2022 financing.
| NSP-Minnesota | ||||||||||||||||||||||||||
| Financing Instrument | Interest Rate | Maturity Date | 2022 | 2021 | ||||||||||||||||||||||
| First mortgage bonds | 2.15 | % | Aug. 15, 2022 | $ | — | $ | 300 | |||||||||||||||||||
| First mortgage bonds | 2.60 | May 15, 2023 | 400 | 400 | ||||||||||||||||||||||
| First mortgage bonds | 7.125 | July 1, 2025 | 250 | 250 | ||||||||||||||||||||||
| First mortgage bonds | 6.50 | March 1, 2028 | 150 | 150 | ||||||||||||||||||||||
First mortgage bonds (a) | 2.25 | April 1, 2031 | 425 | 425 | ||||||||||||||||||||||
| First mortgage bonds | 5.25 | July 15, 2035 | 250 | 250 | ||||||||||||||||||||||
| First mortgage bonds | 6.25 | June 1, 2036 | 400 | 400 | ||||||||||||||||||||||
| First mortgage bonds | 6.20 | July 1, 2037 | 350 | 350 | ||||||||||||||||||||||
| First mortgage bonds | 5.35 | Nov. 1, 2039 | 300 | 300 | ||||||||||||||||||||||
| First mortgage bonds | 4.85 | Aug. 15, 2040 | 250 | 250 | ||||||||||||||||||||||
| First mortgage bonds | 3.40 | Aug. 15, 2042 | 500 | 500 | ||||||||||||||||||||||
| First mortgage bonds | 4.125 | May 15, 2044 | 300 | 300 | ||||||||||||||||||||||
| First mortgage bonds | 4.00 | Aug. 15, 2045 | 300 | 300 | ||||||||||||||||||||||
| First mortgage bonds | 3.60 | May 15, 2046 | 350 | 350 | ||||||||||||||||||||||
| First mortgage bonds | 3.60 | Sep. 15, 2047 | 600 | 600 | ||||||||||||||||||||||
| First mortgage bonds | 2.90 | March 1, 2050 | 600 | 600 | ||||||||||||||||||||||
| First mortgage bonds | 2.60 | June 1, 2051 | 700 | 700 | ||||||||||||||||||||||
First mortgage bonds (a) | 3.20 | April 1,2052 | 425 | 425 | ||||||||||||||||||||||
First mortgage bonds (b) | 4.50 | June 1, 2052 | 500 | — | ||||||||||||||||||||||
| Other long-term debt | 3 | 3 | ||||||||||||||||||||||||
| Unamortized discount | (45) | (44) | ||||||||||||||||||||||||
| Unamortized debt issuance cost | (66) | (62) | ||||||||||||||||||||||||
| Current maturities | (400) | (300) | ||||||||||||||||||||||||
| Total long-term debt | $ | 6,542 | $ | 6,447 | ||||||||||||||||||||||
(a)2021 financing.
(b)2022 financing.
59
| NSP-Wisconsin | ||||||||||||||||||||||||||
| Financing Instrument | Interest Rate | Maturity Date | 2022 | 2021 | ||||||||||||||||||||||
| First mortgage bonds | 3.30 | June 15, 2024 | 100 | 100 | ||||||||||||||||||||||
| First mortgage bonds | 3.30 | June 15, 2024 | 100 | 100 | ||||||||||||||||||||||
| First mortgage bonds | 6.375 | Sept. 1, 2038 | 200 | 200 | ||||||||||||||||||||||
| First mortgage bonds | 3.70 | Oct. 1, 2042 | 100 | 100 | ||||||||||||||||||||||
| First mortgage bonds | 3.75 | Dec. 1, 2047 | 100 | 100 | ||||||||||||||||||||||
| First mortgage bonds | 4.20 | Sept. 1, 2048 | 200 | 200 | ||||||||||||||||||||||
| First mortgage bonds | 3.05 | May 1, 2051 | 100 | 100 | ||||||||||||||||||||||
First mortgage bonds (a) | 2.82 | May 1, 2051 | 100 | 100 | ||||||||||||||||||||||
First mortgage bonds (b) | 4.86 | Sept. 15, 2052 | 100 | — | ||||||||||||||||||||||
| Other long-term debt | — | 1 | ||||||||||||||||||||||||
| Unamortized discount | (3) | (4) | ||||||||||||||||||||||||
| Unamortized debt issuance cost | (11) | (10) | ||||||||||||||||||||||||
| Total long-term debt | $ | 1,086 | $ | 987 | ||||||||||||||||||||||
(a)2021 financing.
(b)2022 financing.
| PSCo | ||||||||||||||||||||||||||
| Financing Instrument | Interest Rate | Maturity Date | 2022 | 2021 | ||||||||||||||||||||||
| First mortgage bonds | 2.25 | % | Sept. 15, 2022 | $ | — | $ | 300 | |||||||||||||||||||
| First mortgage bonds | 2.50 | March 15, 2023 | 250 | 250 | ||||||||||||||||||||||
| First mortgage bonds | 2.90 | May 15, 2025 | 250 | 250 | ||||||||||||||||||||||
| First mortgage bonds | 3.70 | June 15, 2028 | 350 | 350 | ||||||||||||||||||||||
| First mortgage bonds | 1.90 | Jan. 15, 2031 | 375 | 375 | ||||||||||||||||||||||
First mortgage bonds (a) | 1.875 | June 15, 2031 | 750 | 750 | ||||||||||||||||||||||
First mortgage bonds (b) | 4.10 | June 1, 2032 | 300 | — | ||||||||||||||||||||||
| First mortgage bonds | 6.25 | Sept. 1, 2037 | 350 | 350 | ||||||||||||||||||||||
| First mortgage bonds | 6.50 | Aug. 1, 2038 | 300 | 300 | ||||||||||||||||||||||
| First mortgage bonds | 4.75 | Aug. 15, 2041 | 250 | 250 | ||||||||||||||||||||||
| First mortgage bonds | 3.60 | Sept. 15, 2042 | 500 | 500 | ||||||||||||||||||||||
| First mortgage bonds | 3.95 | March 15, 2043 | 250 | 250 | ||||||||||||||||||||||
| First mortgage bonds | 4.30 | March 15, 2044 | 300 | 300 | ||||||||||||||||||||||
| First mortgage bonds | 3.55 | June 15, 2046 | 250 | 250 | ||||||||||||||||||||||
| First mortgage bonds | 3.80 | June 15, 2047 | 400 | 400 | ||||||||||||||||||||||
| First mortgage bonds | 4.10 | June 15, 2048 | 350 | 350 | ||||||||||||||||||||||
| First mortgage bonds | 4.05 | Sept. 15, 2049 | 400 | 400 | ||||||||||||||||||||||
| First mortgage bonds | 3.20 | March 1, 2050 | 550 | 550 | ||||||||||||||||||||||
| First mortgage bonds | 2.70 | Jan. 15, 2051 | 375 | 375 | ||||||||||||||||||||||
First mortgage bonds (b) | 4.50 | June 1, 2052 | 400 | — | ||||||||||||||||||||||
| Unamortized discount | (37) | (33) | ||||||||||||||||||||||||
| Unamortized debt issuance cost | (53) | (50) | ||||||||||||||||||||||||
| Current maturities | (250) | (300) | ||||||||||||||||||||||||
| Total long-term debt | $ | 6,610 | $ | 6,167 | ||||||||||||||||||||||
(a)2021 financing.
(b)2022 financing.
| SPS | ||||||||||||||||||||||||||
| 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.
| Other Subsidiaries | ||||||||||||||||||||||||||
| Financing Instrument | Interest Rate | Maturity Date | 2022 | 2021 | ||||||||||||||||||||||
| Various Eloigne affordable housing project notes | 0.00% - 8.00% | 2024 - 2055 | $ | 27 | $ | 27 | ||||||||||||||||||||
| Current maturities | (1) | (1) | ||||||||||||||||||||||||
| Total long-term debt | $ | 26 | $ | 26 | ||||||||||||||||||||||
Maturities of long-term debt:
| (Millions of Dollars) | ||||||||
| 2023 | $ | 1,151 | ||||||
| 2024 | 552 | |||||||
| 2025 | 1,103 | |||||||
| 2026 | 501 | |||||||
| 2027 | 501 | |||||||
Deferred Financing Costs — Deferred financing costs of approximately $193 million and $184 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt as of Dec. 31, 2022 and 2021, respectively.
Equity through DRIP and Benefits Program — Xcel Energy issued $84 million and $74 million of equity through the DRIP and benefits programs in 2022 and 2021, respectively. The program allows shareholders to reinvest their dividends directly in Xcel Energy Inc. common stock.
ATM Equity Offering — In November 2021, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $800 million of its common stock through an ATM program. In 2021, 5.33 million shares of common stock were issued (approximately $350 million). In 2022, 4.30 million shares of common stock were issued (approximately $300 million). As of Dec. 31, 2022, approximately $150 million remained available for sale under the ATM program.
60
Capital Stock — Preferred stock authorized/outstanding:
| Preferred Stock Authorized (Shares) | Par Value of Preferred Stock | Preferred Stock Outstanding (Shares) 2022 and 2021 | ||||||||||||||||||
| Xcel Energy Inc. | 7,000,000 | $ | 100 | — | ||||||||||||||||
| PSCo | 10,000,000 | 0.01 | — | |||||||||||||||||
| SPS | 10,000,000 | 1.00 | — | |||||||||||||||||
Xcel Energy Inc. had the following common stock authorized/outstanding:
| Common Stock Authorized (Shares) | Par Value of Common Stock | Common Stock Outstanding (Shares) as of Dec. 31, 2022 | Common Stock Outstanding (Shares) as of Dec. 31, 2021 | |||||||||||||||||
| 1,000,000,000 | $ | 2.50 | 549,578,018 | 544,025,269 | ||||||||||||||||
Dividend and Other Capital-Related Restrictions — Xcel Energy depends on its utility subsidiaries to pay dividends. Xcel Energy Inc.’s utility subsidiaries’ 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. Certain covenants also require Xcel Energy Inc. to be current on interest payments prior to dividend disbursements.
State regulatory commissions impose dividend limitations for NSP-Minnesota, NSP-Wisconsin and SPS, which are more restrictive than those imposed by the FERC.
Requirements and actuals as of Dec. 31, 2022:
| Equity to Total Capitalization Ratio Required Range | Equity to Total Capitalization Ratio Actual | |||||||||||||||||||
| Low | High | 2022 | ||||||||||||||||||
| NSP-Minnesota | 47.2 | % | 57.6 | % | 52.3 | % | ||||||||||||||
| NSP-Wisconsin | 52.5 | N/A | 52.8 | |||||||||||||||||
SPS (a) | 45.0 | 55.0 | 54.3 | |||||||||||||||||
(a) Excludes short-term debt.
| (Amounts in Millions) | Unrestricted Retained Earnings | Total Capitalization | Limit on Total Capitalization | |||||||||||||||||
| NSP-Minnesota | $ | 1,446 | $ | 14,984 | $ | 16,140 | ||||||||||||||
NSP-Wisconsin (a) | 11 | 2,280 | N/A | |||||||||||||||||
SPS (b) | 540 | 7,094 | N/A | |||||||||||||||||
(a) Cannot pay annual dividends in excess of forecasted levels if its average equity-to-total capitalization ratio falls below the commission authorized level.
(b) May not pay a dividend that would cause a loss of its investment grade bond rating.
Issuance of securities by Xcel Energy Inc. is not generally subject to regulatory approval. However, utility financings and intra-system financings are subject to the jurisdiction of state regulatory commissions and/or the FERC. Xcel Energy may seek additional authorization as necessary.
Amounts authorized to issue as of Dec. 31, 2022:
| (Millions of Dollars) | Long-Term Debt | Short-Term Debt | |||||||||||||||
| NSP-Minnesota | 52.8% of total capitalization | (a) | $ | 2,400 | (a) | ||||||||||||
| NSP-Wisconsin | $ | 50 | 150 | ||||||||||||||
| SPS | — | 600 | |||||||||||||||
| PSCo | 1,300 | 800 | |||||||||||||||
(a)NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization remains within the required range, and to issue short-term debt provided it does not exceed 15% of total capitalization.
6. Revenues | ||
Revenue is classified by the type of goods/services rendered and market/customer type. Xcel Energy’s operating revenues consisted of the following:
| Year Ended Dec. 31, 2022 | ||||||||||||||||||||||||||
| (Millions of Dollars) | Electric | Natural Gas | All Other | Total | ||||||||||||||||||||||
| Major revenue types | ||||||||||||||||||||||||||
| Revenue from contracts with customers: | ||||||||||||||||||||||||||
| Residential | $ | 3,542 | $ | 1,814 | $ | 53 | $ | 5,409 | ||||||||||||||||||
| C&I | 5,807 | 998 | 32 | 6,837 | ||||||||||||||||||||||
| Other | 148 | — | 10 | 158 | ||||||||||||||||||||||
| Total retail | 9,497 | 2,812 | 95 | 12,404 | ||||||||||||||||||||||
| Wholesale | 1,354 | — | — | 1,354 | ||||||||||||||||||||||
| Transmission | 675 | — | — | 675 | ||||||||||||||||||||||
| Other | 97 | 178 | — | 275 | ||||||||||||||||||||||
| Total revenue from contracts with customers | 11,623 | 2,990 | 95 | 14,708 | ||||||||||||||||||||||
| Alternative revenue and other | 500 | 90 | 12 | 602 | ||||||||||||||||||||||
| Total revenues | $ | 12,123 | $ | 3,080 | $ | 107 | $ | 15,310 | ||||||||||||||||||
| Year Ended Dec. 31, 2021 | ||||||||||||||||||||||||||
| (Millions of Dollars) | Electric | Natural Gas | All Other | Total | ||||||||||||||||||||||
| Major revenue types | ||||||||||||||||||||||||||
| Revenue from contracts with customers: | ||||||||||||||||||||||||||
| Residential | $ | 3,194 | $ | 1,222 | $ | 45 | $ | 4,461 | ||||||||||||||||||
| C&I | 5,050 | 640 | 30 | 5,720 | ||||||||||||||||||||||
| Other | 127 | — | 7 | 134 | ||||||||||||||||||||||
| Total retail | 8,371 | 1,862 | 82 | 10,315 | ||||||||||||||||||||||
| Wholesale | 1,540 | — | — | 1,540 | ||||||||||||||||||||||
| Transmission | 604 | — | — | 604 | ||||||||||||||||||||||
| Other | 61 | 148 | — | 209 | ||||||||||||||||||||||
| Total revenue from contracts with customers | 10,576 | 2,010 | 82 | 12,668 | ||||||||||||||||||||||
| Alternative revenue and other | 629 | 122 | 12 | 763 | ||||||||||||||||||||||
| Total revenues | $ | 11,205 | $ | 2,132 | $ | 94 | $ | 13,431 | ||||||||||||||||||
| Year Ended Dec. 31, 2020 | ||||||||||||||||||||||||||
| (Millions of Dollars) | Electric | Natural Gas | All Other | Total | ||||||||||||||||||||||
| Major revenue types | ||||||||||||||||||||||||||
| Revenue from contracts with customers: | ||||||||||||||||||||||||||
| Residential | $ | 3,066 | $ | 975 | $ | 42 | $ | 4,083 | ||||||||||||||||||
| C&I | 4,596 | 462 | 27 | 5,085 | ||||||||||||||||||||||
| Other | 125 | — | 6 | 131 | ||||||||||||||||||||||
| Total retail | 7,787 | 1,437 | 75 | 9,299 | ||||||||||||||||||||||
| Wholesale | 759 | — | — | 759 | ||||||||||||||||||||||
| Transmission | 579 | — | — | 579 | ||||||||||||||||||||||
| Other | 73 | 137 | — | 210 | ||||||||||||||||||||||
| Total revenue from contracts with customers | 9,198 | 1,574 | 75 | 10,847 | ||||||||||||||||||||||
| Alternative revenue and other | 604 | 62 | 13 | 679 | ||||||||||||||||||||||
| Total revenues | $ | 9,802 | $ | 1,636 | $ | 88 | $ | 11,526 | ||||||||||||||||||
61
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 (a) | 2020 (a) | ||||||||||||||||||
| Federal statutory rate | 21.0 | % | 21.0 | % | 21.0 | % | ||||||||||||||
| State income tax on pretax income, net of federal tax effect | 4.9 | 5.0 | 4.9 | |||||||||||||||||
| (Decreases) increases in tax from: | ||||||||||||||||||||
Wind PTCs (b) | (27.4) | (23.4) | (15.7) | |||||||||||||||||
Plant regulatory differences (c) | (5.5) | (6.2) | (7.6) | |||||||||||||||||
| Other tax credits, net NOL & tax credit allowances | (1.3) | (1.1) | (1.2) | |||||||||||||||||
| NOL Carryback | — | — | (0.9) | |||||||||||||||||
| Other, net | (0.1) | 0.1 | (0.9) | |||||||||||||||||
| Effective income tax rate | (8.4) | % | (4.6) | % | (0.4) | % | ||||||||||||||
(a)Prior period amounts have been restated to conform with current year presentation.
(b)Wind PTCs are credited to customers (reduction to revenue) and do not materially impact net income.
(c)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 and additional prepaid pension asset amortization.
Components of income tax expense for years ended Dec. 31:
| (Millions of Dollars) | 2022 | 2021 | 2020 | |||||||||||||||||
| Current federal tax expense (benefit) | $ | 1 | $ | 15 | $ | (13) | ||||||||||||||
| Current state tax expense (benefit) | 3 | (2) | 2 | |||||||||||||||||
| Current change in unrecognized tax expense | 5 | 1 | 18 | |||||||||||||||||
| Deferred federal tax benefit | (239) | (183) | (89) | |||||||||||||||||
| Deferred state tax expense | 96 | 99 | 91 | |||||||||||||||||
| Deferred change in unrecognized tax expense (benefit) | 3 | 5 | (10) | |||||||||||||||||
| Deferred ITCs | (4) | (5) | (5) | |||||||||||||||||
| Total income tax benefit | $ | (135) | $ | (70) | $ | (6) | ||||||||||||||
Components of deferred income tax expense as of Dec. 31:
| (Millions of Dollars) | 2022 | 2021 | 2020 | |||||||||||||||||
| Deferred tax (benefit) expense excluding items below | $ | (138) | $ | 148 | $ | 237 | ||||||||||||||
| Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities | 8 | (221) | (247) | |||||||||||||||||
| Tax (benefit) expense allocated to other comprehensive income and other | (10) | (6) | 2 | |||||||||||||||||
| Deferred tax benefit | $ | (140) | $ | (79) | $ | (8) | ||||||||||||||
Components of 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 | $ | 6,442 | $ | 6,231 | ||||||||||
| Regulatory assets | 508 | 560 | ||||||||||||
| Operating lease assets | 325 | 351 | ||||||||||||
| Deferred fuel costs | 222 | 262 | ||||||||||||
| Pension expense | 159 | 175 | ||||||||||||
| Other | 92 | 88 | ||||||||||||
| Total deferred tax liabilities | $ | 7,748 | $ | 7,667 | ||||||||||
| Deferred tax assets: | ||||||||||||||
| Tax credit carryforward | $ | 1,679 | $ | 1,261 | ||||||||||
| Regulatory liabilities | 742 | 742 | ||||||||||||
| Operating lease liabilities | 325 | 351 | ||||||||||||
| Other employee benefits | 102 | 119 | ||||||||||||
| NOL carryforward | 57 | 247 | ||||||||||||
| NOL and tax credit valuation allowances | (62) | (64) | ||||||||||||
| Deferred ITCs | 14 | 15 | ||||||||||||
| Other | 135 | 102 | ||||||||||||
| Total deferred tax assets | $ | 2,992 | $ | 2,773 | ||||||||||
| Net deferred tax liability | $ | 4,756 | $ | 4,894 | ||||||||||
(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:
| (Millions of Dollars) | 2022 | 2021 | ||||||||||||
| Federal NOL carryforward | $ | 20 | $ | 765 | ||||||||||
| Federal tax credit carryforwards | 1,593 | 1,172 | ||||||||||||
| State NOL carryforwards | 1,022 | 1,648 | ||||||||||||
| Valuation allowances for state NOL carryforwards | (3) | (3) | ||||||||||||
State tax credit carryforwards, net of federal detriment (a) | 85 | 89 | ||||||||||||
Valuation allowances for state credit carryforwards, net of federal benefit (b) | (62) | (64) | ||||||||||||
(a)State tax credit carryforwards are net of federal detriment of $23 million and $24 million as of Dec. 31, 2022 and 2021.
(b)Valuation allowances for state tax credit carryforwards were net of federal benefit of $16 million and $17 million as of Dec. 31, 2022 and 2021.
Federal carryforward periods expire starting 2032 and state carryforward periods expire starting 2022.
Federal Loss Carryback Claims - In 2020, Xcel Energy identified certain expense related to tax years 2009 - 2011 that qualify for an extended carryback claim. As a result, a tax benefit of approximately $13 million was recognized in 2020.
Unrecognized Tax Benefits
Federal Audit — Statute of limitations applicable to Xcel Energy’s consolidated federal income tax returns expire as follows:
| Tax Year(s) | Expiration | |||||||
| 2014 - 2016 | March 2024 | |||||||
| 2019 | October 2023 | |||||||
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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 — Xcel Energy files consolidated state tax returns based on income in its major operating jurisdictions and various other state income-based tax returns.
As of Dec. 31, 2022, Xcel Energy’s earliest open tax years (subject to examination by state taxing authorities in its major operating jurisdictions) were as follows:
| State | Tax Year(s) | Expiration | ||||||||||||
| Colorado | 2014 - 2016 | March 2025 | ||||||||||||
| Colorado | 2018 | September 2023 | ||||||||||||
| Minnesota | 2014 - 2016 | September 2024 | ||||||||||||
| Minnesota | 2018 | June 2023 | ||||||||||||
| Texas | 2016 | May 2023 | ||||||||||||
| Texas | 2017 | July 2025 | ||||||||||||
| Texas | 2018 | November 2023 | ||||||||||||
| Wisconsin | 2016 - 2017 | April 2023 | ||||||||||||
| Wisconsin | 2018 | October 2023 | ||||||||||||
•In 2020, Minnesota began an audit of tax years 2015-2018. In 2022, the state of Minnesota issued its audit report without any material adjustments.
•In 2021, Texas began an audit of tax years 2016-2019. As of Dec. 31, 2022, no material adjustments have been proposed.
•In 2021, Wisconsin began an audit of tax years 2016-2019. As of Dec. 31, 2022, no material adjustments have been proposed.
•No other state income tax audits are in progress for its major operating jurisdictions as of Dec. 31, 2022.
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 period 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 | $ | 55 | $ | 47 | ||||||||||
| Unrecognized tax benefit — Temporary tax positions | 12 | 11 | ||||||||||||
| Total unrecognized tax benefit | $ | 67 | $ | 58 | ||||||||||
Changes in unrecognized tax benefits:
| (Millions of Dollars) | 2022 | 2021 | 2020 | |||||||||||||||||
| Balance at Jan. 1 | $ | 58 | $ | 52 | $ | 44 | ||||||||||||||
| Additions based on tax positions related to the current year | 7 | 5 | 9 | |||||||||||||||||
| Reductions based on tax positions related to the current year | — | — | (2) | |||||||||||||||||
| Additions for tax positions of prior years | 6 | 2 | 35 | |||||||||||||||||
| Reductions for tax positions of prior years | (1) | (1) | (34) | |||||||||||||||||
| Reductions for tax positions related to settlements with taxing authorities | (1) | — | — | |||||||||||||||||
| Reductions for tax positions related to statute of limitations | (2) | — | — | |||||||||||||||||
| Balance at Dec. 31 | $ | 67 | $ | 58 | $ | 52 | ||||||||||||||
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 | $ | (40) | $ | (36) | ||||||||||
As the IRS progresses its review of the tax loss carryback claims and as state audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $40 million in the next 12 months.
Payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards.
Interest payable related to unrecognized tax benefits:
| (Millions of Dollars) | 2022 | 2021 | 2020 | |||||||||||||||||
| Payable for interest related to unrecognized tax benefits at Jan. 1 | $ | (3) | $ | (3) | $ | — | ||||||||||||||
| Interest expense related to unrecognized tax benefits | (1) | — | (3) | |||||||||||||||||
| Payable for interest related to unrecognized tax benefits at Dec. 31 | $ | (4) | $ | (3) | $ | (3) | ||||||||||||||
No penalties were accrued related to unrecognized tax benefits as of Dec. 31, 2022, 2021 or 2020.
8. Share-Based Compensation | ||
Incentive Plan Including Share-Based Compensation — Xcel Energy has authorized 7.0 million equity shares under an incentive plan (the Amended and Restated 2015 Omnibus Incentive Plan).
Equity Awards — Xcel Energy‘s Board of Directors has granted equity awards under the 2015 Omnibus Incentive Plan, which includes various vesting conditions and performance goals. At the end of the restricted period, such grants will be awarded if vesting conditions and/or performance goals are met.
Certain employees are granted equity awards with a portion subject only to service conditions, and the other portion subject to performance conditions. A total of 0.2 million time-based equity shares subject only to service conditions were granted annually in 2022, 2021 and 2020.
The performance conditions for a portion of the awards granted from 2020 to 2022 are based on relative TSR and environmental goals. Equity awards with performance conditions will be settled or forfeited after three years, with payouts ranging from zero to 200% depending on achievement.
Equity award units granted to employees:
| (Units in Thousands) | 2022 | 2021 | 2020 | |||||||||||||||||
| Granted units | 395 | 421 | 411 | |||||||||||||||||
| Weighted average grant date fair value | $ | 68.43 | $ | 66.03 | $ | 62.92 | ||||||||||||||
Equity awards vested:
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Changes in the nonvested portion of equity award units:
| (Units in Thousands) | Units | Weighted Average Grant Date Fair Value | ||||||||||||
| Nonvested Units at Jan. 1, 2022 | 695 | $ | 64.59 | |||||||||||
| Granted | 395 | 68.43 | ||||||||||||
| Forfeited | (96) | 65.53 | ||||||||||||
| Vested | (319) | 63.03 | ||||||||||||
| Dividend equivalents | 33 | 65.40 | ||||||||||||
| Nonvested Units at Dec. 31, 2022 | 708 | 67.35 | ||||||||||||
Stock Equivalent Units — Non-employee members of Xcel Energy‘s Board of Directors may elect to receive their annual equity grant as stock equivalent units in lieu of common stock. Each unit’s value is equal to one share of common stock. The annual equity grant is vested as of the date of each member’s election to the Board of Directors; there is no further service or other condition. Directors may also elect to receive their cash fees as stock equivalent units in lieu of cash. Stock equivalent units are payable as a distribution of common stock upon a director’s termination of service.
Stock equivalent units granted:
| (Units in Thousands) | 2022 | 2021 | 2020 | |||||||||||||||||
| Granted units | 29 | 31 | 33 | |||||||||||||||||
| Weighted average grant date fair value | $ | 71.97 | $ | 68.15 | $ | 61.61 | ||||||||||||||
Changes in stock equivalent units:
| (Units in Thousands) | Units | Weighted Average Grant Date Fair Value | ||||||||||||
| Stock equivalent units at Jan. 1, 2022 | 604 | $ | 39.27 | |||||||||||
| Granted | 29 | 71.97 | ||||||||||||
| Units distributed | (52) | 38.16 | ||||||||||||
| Dividend equivalents | 16 | 67.79 | ||||||||||||
| Stock equivalent units at Dec. 31, 2022 | 597 | 41.75 | ||||||||||||
Liability Awards — Xcel Energy’s Board of Directors has granted TSR liability awards under the 2015 Omnibus Incentive Plan. This plan allows Xcel Energy to attach various performance goals to the awards granted. The liability awards have been historically dependent on relative TSR measured over a -year period. Xcel Energy Inc.’s TSR is compared to a peer group of other utility companies. Potential payouts of the awards range from zero to 200%.
Liability awards granted:
| (In Thousands) | 2022 | 2021 | 2020 | |||||||||||||||||
| Awards granted | 165 | 221 | 212 | |||||||||||||||||
Liability awards settled:
| (Units In Thousands, Settlement Amount in Millions) | 2022 | 2021 | 2020 | |||||||||||||||||
| Awards settled | 411 | 446 | 476 | |||||||||||||||||
| Settlement amount (cash, common stock and deferred amounts) | $ | 27 | $ | 27 | $ | 33 | ||||||||||||||
TSR liability awards of $21 million were settled in cash in 2022.
Share-Based Compensation Expense — Award settlement determination (permitting cash or share settlement) is made by Xcel Energy, not the participants. Equity awards have not been previously settled in cash and Xcel Energy plans to continue electing share settlement. Grant date fair value of equity awards is expensed over the service period.
TSR liability awards are accounted for as liabilities, as historically they are partially settled in cash. As liability awards, the fair value on which ratable expense is based, as employees vest in their rights to those awards, is remeasured each period based on the current stock price and performance achievement, and final expense is based on the market value of the shares on the date the award is settled.
Compensation costs related to share-based awards:
| (Millions of Dollars) | 2022 | 2021 | 2020 | |||||||||||||||||
Cost for share-based awards (a) | $ | 36 | $ | 31 | $ | 73 | ||||||||||||||
| Tax benefit recognized in income | 9 | 8 | 19 | |||||||||||||||||
(a)Compensation costs for share-based payments are included in O&M expense. Amount for equity awards (non-cash) amounted to $20 million in 2022.
There was approximately $37 million and $28 million as of Dec. 31, 2022 and 2021, respectively, of total unrecognized compensation cost related to nonvested share-based compensation awards. Xcel Energy expects to recognize the unrecognized amount over a weighted average period of 1.8 years.
9. Earnings Per Share | ||
Basic EPS was computed by dividing the earnings available to common shareholders by the weighted average number of common shares outstanding. Diluted EPS was computed by dividing the earnings available to common shareholders by the diluted weighted average number of common shares outstanding.
Diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate diluted EPS is calculated using the treasury stock method.
Common Stock Equivalents — Common stock equivalents include commitments to issue common stock related to time-based equity compensation awards.
Stock equivalent units granted to Xcel Energy’s Board of Directors are included in common shares outstanding upon grant date as there is no further service, performance or market condition associated with these. Restricted stock issued to employees under the Executive Annual Incentive Award Plan is included in common shares outstanding when granted.
Share-based compensation arrangements for which there is currently no dilutive impact to EPS include the following:
•Equity awards subject to a performance condition; included in common shares outstanding when all necessary conditions for settlement have been satisfied by the end of the reporting period.
•Liability awards subject to a performance condition; any portions settled in shares are included in common shares outstanding upon settlement.
Common shares outstanding used in the basic and diluted EPS computation:
| (Shares in Millions) | 2022 | 2021 | 2020 | |||||||||||||||||
| Basic | 547 | 539 | 527 | |||||||||||||||||
Diluted (a) | 547 | 540 | 528 | |||||||||||||||||
(a)Diluted common shares outstanding included common stock equivalents of 0.3 million, 0.3 million and 1.1 million shares for 2022, 2021 and 2020, respectively.
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10. Fair Value of Financial Assets and Liabilities | ||
Fair Value Measurements
Accounting guidance for fair value measurements and disclosures provides a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value.
•Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are actively traded instruments with observable actual trading prices.
•Level 2 — Pricing inputs are other than actual trading prices in active markets but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts or priced with models using highly observable inputs.
•Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 include those valued with models requiring significant judgment or estimation.
Specific valuation methods include:
Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds are measured using NAVs. The investments in commingled funds may be redeemed for NAV with proper notice. Private equity commingled funds require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate commingled funds may be redeemed with proper notice, however, withdrawals may be delayed or discounted as a result of fund illiquidity.
Investments in debt securities — Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities.
Interest rate derivatives — Fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.
Commodity derivatives — Methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When contracts relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges, the significance of the use of less observable inputs on a valuation is evaluated and may result in Level 3 classification.
Electric commodity derivatives held by NSP-Minnesota and 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.
Non-Derivative Fair Value Measurements
Nuclear Decommissioning Fund
The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning these facilities. The fund contains cash equivalents, debt securities, equity securities and other investments. NSP-Minnesota uses the MPUC approved asset allocation for the investment targets by asset class for the qualified trust.
NSP-Minnesota recognizes the costs of funding the decommissioning over the lives of the nuclear plants, assuming rate recovery of all costs. Realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund are deferred as a component of the regulatory asset.
Unrealized gains for the nuclear decommissioning fund were $1 billion and $1.3 billion as of Dec. 31, 2022 and 2021, respectively, and unrealized losses were $90 million and $7 million as of Dec. 31, 2022 and 2021, respectively.
Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund:
(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $219 million of equity method investments and $133 million of rabbi trust assets and other miscellaneous investments.
| Dec. 31, 2021 | ||||||||||||||||||||||||||||||||||||||
| Fair Value | ||||||||||||||||||||||||||||||||||||||
| (Millions of Dollars) | Cost | Level 1 | Level 2 | Level 3 | NAV | Total | ||||||||||||||||||||||||||||||||
Nuclear decommissioning fund (a) | ||||||||||||||||||||||||||||||||||||||
| Cash equivalents | $ | 64 | $ | 64 | $ | — | $ | — | $ | — | $ | 64 | ||||||||||||||||||||||||||
| Commingled funds | 856 | — | — | — | 1,294 | 1,294 | ||||||||||||||||||||||||||||||||
| Debt securities | 631 | — | 666 | 9 | — | 675 | ||||||||||||||||||||||||||||||||
| Equity securities | 411 | 1,222 | 1 | — | — | 1,223 | ||||||||||||||||||||||||||||||||
| Total | $ | 1,962 | $ | 1,286 | $ | 667 | $ | 9 | $ | 1,294 | $ | 3,256 | ||||||||||||||||||||||||||
(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $208 million of equity investments in unconsolidated subsidiaries and $164 million of rabbi trust assets and other miscellaneous investments.
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For the years ended Dec. 31, 2022 and 2021, there were immaterial Level 3 nuclear decommissioning fund investments or transfer of amounts between levels.
Contractual maturity dates of debt securities in the nuclear decommissioning fund as of Dec. 31, 2022:
| Final Contractual Maturity | ||||||||||||||||||||||||||||||||
| (Millions of Dollars) | Due in 1 Year or Less | Due in 1 to 5 Years | Due in 5 to 10 Years | Due after 10 Years | Total | |||||||||||||||||||||||||||
| Debt securities | $ | 6 | $ | 204 | $ | 250 | $ | 215 | $ | 675 | ||||||||||||||||||||||
Rabbi Trusts
Xcel Energy has established rabbi trusts to provide partial funding for future distributions of deferred compensation plan. The fair value of assets held in the rabbi trusts were $80 million and $109 million at Dec. 31, 2022 and 2021, respectively, comprised of cash equivalents and mutual funds (level 1 valuation methods). Amounts are reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.
Derivative Activities and Fair Value Measurements
Xcel Energy enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates, and utility commodity prices.
Interest Rate Derivatives — Xcel Energy enters into contracts that effectively fix the interest rate on a specified principal amount of a hypothetical future debt issuance. These financial swaps net settle based on changes in a specified benchmark interest rate, acting as a hedge of changes in market interest rates that will impact specified anticipated debt issuances. These derivative instruments are designated as cash flow hedges for accounting purposes, with changes in fair value prior to occurrence of the hedged transactions recorded as other comprehensive income.
As of Dec. 31, 2022, accumulated other comprehensive loss related to interest rate derivatives included $2 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings. As of Dec. 31, 2022, Xcel Energy had unsettled interest swaps outstanding with a notional amount of $40 million. These interest rate derivatives were designated as cash flow hedges, with changes in fair value recorded to other comprehensive income.
See Note 13 for the financial impact of qualifying interest rate cash flow hedges on Xcel Energy’s accumulated other comprehensive loss included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income.
Wholesale and Commodity Trading — Xcel Energy Inc.’s utility subsidiaries conduct various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Xcel Energy is allowed to conduct these activities within guidelines and limitations as approved by its risk management committee, comprised of management personnel not directly involved in the activities governed by this policy.
Derivative instruments entered into for trading purposes are presented in the consolidated statements of income as electric revenues, net of any sharing with customers. These activities are not intended to mitigate commodity price risk associated with regulated electric and natural gas operations. Sharing of these margins is determined through state regulatory proceedings as well as the operation of the FERC-approved joint operating agreement.
Commodity Derivatives — Xcel Energy enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale and FTRs.
The most significant derivative positions outstanding at December 31, 2022 and 2021 for this purpose relate to FTR instruments administered by MISO and 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 Xcel Energy enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, the instruments are not typically designated as qualifying hedging transactions. The classification of unrealized losses or gains on these instruments as a regulatory asset or liability, if applicable, is based on approved regulatory recovery mechanisms.
As of Dec. 31, 2022, Xcel Energy had no commodity contracts designated as cash flow hedges.
Gross notional amounts of commodity forwards, options and FTRs:
(Amounts in Millions) (a)(b) | Dec. 31, 2022 | Dec. 31, 2021 | ||||||||||||
| MWh of electricity | 61 | 80 | ||||||||||||
| MMBtu of natural gas | 131 | 156 | ||||||||||||
(a)Not reflective of net positions in the underlying commodities.
(b)Notional amounts for options included on a gross basis but weighted for the probability of exercise.
Consideration of Credit Risk and Concentrations — Xcel Energy continuously monitors the creditworthiness of counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented on the consolidated balance sheets.
Xcel Energy’s utility subsidiaries’ most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to their wholesale, trading and non-trading commodity activities.
As of Dec. 31, 2022, four of Xcel Energy’s ten most significant counterparties for these activities, comprising $75 million or 37% of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services or Fitch Ratings.
Four of the ten most significant counterparties, comprising $63 million or 32% of this credit exposure, were not rated by these external ratings agencies, but based on Xcel Energy’s internal analysis, had credit quality consistent with investment grade.
Two of these significant counterparties, comprising $62 million or 31% of this credit exposure, had credit quality less than investment grade, based on internal analysis. Six of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities.
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Credit Related Contingent Features — Contract provisions for derivative instruments that the utility subsidiaries enter, including those accounted for as normal purchase and normal sale contracts and therefore not reflected on the consolidated balance sheets, may require the posting of collateral or settlement of the contracts for various reasons, including if the applicable utility subsidiary’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies.
As of Dec. 31, 2022 and 2021, there were $4 million and $3 million, respectively, of derivative liabilities with such underlying contract provisions, respectively.
Certain contracts also contain cross default provisions that may require the posting of collateral or settlement of the contracts if there was a failure under other financing arrangements related to payment terms or other covenants.
As of Dec. 31, 2022 and 2021, there were approximately $76 million and $64 million of derivative liabilities with such underlying contract provisions, respectively.
Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that a given utility subsidiary’s ability to fulfill its contractual obligations is reasonably expected to be impaired.
Xcel Energy had no collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 2022 and 2021.
Recurring Derivative Fair Value Measurements
Impact of derivative activity:
| Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: | ||||||||||||||
| (Millions of Dollars) | Accumulated Other Comprehensive Loss | Regulatory (Assets) and Liabilities | ||||||||||||
| Year Ended Dec. 31, 2022 | ||||||||||||||
| Derivatives designated as cash flow hedges | ||||||||||||||
| Interest rate | $ | 22 | $ | — | ||||||||||
| Total | $ | 22 | $ | — | ||||||||||
| Other derivative instruments | ||||||||||||||
| Electric commodity | $ | — | $ | (10) | ||||||||||
| Natural gas commodity | — | (16) | ||||||||||||
| Total | $ | — | $ | (26) | ||||||||||
| Year Ended Dec. 31, 2021 | ||||||||||||||
| Interest rate | $ | 5 | $ | — | ||||||||||
| Total | $ | 5 | $ | — | ||||||||||
| Other derivative instruments | ||||||||||||||
| Electric commodity | $ | — | $ | 32 | ||||||||||
| Natural gas commodity | — | (4) | ||||||||||||
| Total | $ | — | $ | 28 | ||||||||||
| Year Ended Dec. 31, 2020 | ||||||||||||||
| Interest rate | $ | (13) | $ | — | ||||||||||
| Total | $ | (13) | $ | — | ||||||||||
| Other derivative instruments | ||||||||||||||
| Electric commodity | $ | — | $ | (5) | ||||||||||
| Natural gas commodity | — | (13) | ||||||||||||
| Total | $ | — | $ | (18) | ||||||||||
| Pre-Tax (Gains) Losses Reclassified into Income During the Period from: | Pre-Tax Gains (Losses) Recognized During the Period in Income | ||||||||||||||||||||||
| (Millions of Dollars) | Accumulated Other Comprehensive Loss | Regulatory Assets and (Liabilities) | |||||||||||||||||||||
| Year Ended Dec. 31, 2022 | |||||||||||||||||||||||
| Derivatives designated as cash flow hedges | |||||||||||||||||||||||
| Interest rate | $ | 7 | (a) | $ | — | $ | — | ||||||||||||||||
| Total | $ | 7 | $ | — | $ | — | |||||||||||||||||
| Other derivative instruments | |||||||||||||||||||||||
| Commodity trading | $ | — | $ | — | $ | 25 | (b) | ||||||||||||||||
| Electric commodity | — | 3 | (c) | — | |||||||||||||||||||
| Natural gas commodity | — | 10 | (d) | (27) | (d)(e) | ||||||||||||||||||
| Total | $ | — | $ | 13 | $ | (2) | |||||||||||||||||
| Year Ended Dec. 31, 2021 | |||||||||||||||||||||||
| Derivatives designated as cash flow hedges | |||||||||||||||||||||||
| Interest rate | $ | 8 | (a) | $ | — | $ | — | ||||||||||||||||
| Total | $ | 8 | $ | — | $ | — | |||||||||||||||||
| Other derivative instruments | |||||||||||||||||||||||
| Commodity trading | $ | — | $ | — | $ | 63 | (b) | ||||||||||||||||
| Electric commodity | — | (23) | (c) | — | |||||||||||||||||||
| Natural gas commodity | — | 5 | (d) | (22) | (d)(e) | ||||||||||||||||||
| Total | $ | — | $ | (18) | $ | 41 | |||||||||||||||||
| Year Ended Dec. 31, 2020 | |||||||||||||||||||||||
| Derivatives designated as cash flow hedges | |||||||||||||||||||||||
| Interest rate | $ | 7 | (a) | $ | — | $ | — | ||||||||||||||||
| Total | $ | 7 | $ | — | $ | — | |||||||||||||||||
| Other derivative instruments | |||||||||||||||||||||||
| Commodity trading | $ | — | $ | — | $ | (1) | (b) | ||||||||||||||||
| Electric commodity | — | (3) | (c) | — | |||||||||||||||||||
| Natural gas commodity | — | 10 | (d) | (13) | (d)(e) | ||||||||||||||||||
| Total | $ | — | $ | 7 | $ | (14) | |||||||||||||||||
(a)Recorded to interest charges.
(b)Recorded to electric revenues. Presented amounts do not reflect non-derivative transactions or margin sharing with customers.
(c)Recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms and reclassified out of income as regulatory assets or liabilities, as appropriate. FTR settlements are shared with customers and do not have a material impact on net income. Presented amounts reflect changes in fair value between auction and settlement dates, but exclude the original auction fair value.
(d)Recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate.
(e)Relates primarily to option premium amortization.
Xcel Energy had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2022, 2021 and 2020.
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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) | Fair Value | Fair Value Total | Netting (a) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (Millions of Dollars) | Level 1 | Level 2 | Level 3 | Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Current derivative assets | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other derivative instruments: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Commodity trading | $ | 32 | $ | 259 | $ | 33 | $ | 324 | $ | (242) | $ | 82 | $ | 22 | $ | 137 | $ | 21 | $ | 180 | $ | (134) | $ | 46 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Electric commodity | — | — | 177 | 177 | (2) | 175 | — | — | 57 | 57 | (1) | 56 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Natural gas commodity | — | 19 | — | 19 | — | 19 | — | 18 | — | 18 | — | 18 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total current derivative assets | $ | 32 | $ | 278 | $ | 210 | $ | 520 | $ | (244) | 276 | $ | 22 | $ | 155 | $ | 78 | $ | 255 | $ | (135) | 120 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
PPAs (b) | 3 | 3 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| $ | 279 | $ | 123 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Noncurrent derivative assets | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other derivative instruments: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Commodity trading | $ | 34 | $ | 71 | $ | 74 | $ | 179 | $ | (89) | $ | 90 | $ | 16 | $ | 63 | $ | 89 | $ | 168 | $ | (107) | $ | 61 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Total noncurrent derivative assets | $ | 34 | $ | 71 | $ | 74 | $ | 179 | $ | (89) | 90 | $ | 16 | $ | 63 | $ | 89 | $ | 168 | $ | (107) | 61 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
PPAs (b) | 3 | 6 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Noncurrent derivative instruments | $ | 93 | $ | 67 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Dec. 31, 2022 | Dec. 31, 2021 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Fair Value | Fair Value Total | Netting (a) | Fair Value | Fair Value Total | Netting (a) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (Millions of Dollars) | Level 1 | Level 2 | Level 3 | Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Current derivative liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Derivatives designated as cash flow hedges: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Interest rate | $ | — | $ | 1 | $ | — | $ | 1 | $ | — | $ | 1 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Other derivative instruments: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Commodity trading | $ | 29 | $ | 297 | $ | 6 | $ | 332 | $ | (287) | $ | 45 | $ | 19 | $ | 148 | $ | 20 | $ | 187 | $ | (143) | $ | 44 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Electric commodity | — | — | 2 | 2 | (2) | — | — | — | 1 | 1 | (1) | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Natural gas commodity | — | 13 | — | 13 | — | 13 | — | 8 | — | 8 | — | 8 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total current derivative liabilities | $ | 29 | $ | 311 | $ | 8 | $ | 348 | $ | (289) | 59 | $ | 19 | $ | 156 | $ | 21 | $ | 196 | $ | (144) | 52 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
PPAs (b) | 17 | 17 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Current derivative instruments | $ | 76 | $ | 69 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Noncurrent derivative liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other derivative instruments: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Commodity trading | $ | 43 | $ | 97 | $ | 41 | $ | 181 | $ | (98) | $ | 83 | $ | 18 | $ | 48 | $ | 127 | $ | 193 | $ | (128) | $ | 65 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Total noncurrent derivative liabilities | $ | 43 | $ | 97 | $ | 41 | $ | 181 | $ | (98) | 83 | $ | 18 | $ | 48 | $ | 127 | $ | 193 | $ | (128) | 65 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
PPAs (b) | 30 | 40 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Noncurrent derivative instruments | $ | 113 | $ | 105 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
(a)Xcel Energy nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement. At Dec. 31, 2022 and 2021, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2022 and 2021, derivative assets and liabilities include rights to reclaim cash collateral of $53 million and $30 million, respectively. Counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
(b)Xcel Energy 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.
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Changes in Level 3 commodity derivatives:
| Year Ended Dec. 31 | ||||||||||||||||||||
| (Millions of Dollars) | 2022 | 2021 | 2020 | |||||||||||||||||
| Balance at Jan. 1 | $ | 19 | $ | (49) | $ | 4 | ||||||||||||||
Purchases (a) | 406 | 65 | 51 | |||||||||||||||||
Settlements (a) | (350) | (158) | (73) | |||||||||||||||||
| Net transactions recorded during the period: | ||||||||||||||||||||
Gains (losses) recognized in earnings (b) | 151 | 49 | (39) | |||||||||||||||||
Net gains recognized as regulatory assets and liabilities (a) | 10 | 112 | 8 | |||||||||||||||||
| Balance at Dec. 31 | $ | 236 | $ | 19 | $ | (49) | ||||||||||||||
(a)Relates primarily to NSP-Minnesota and SPS FTR instruments administered by MISO and SPP.
(b)Relates to commodity trading and is subject to substantial offsetting losses and gains on derivative instruments categorized as levels 1 and 2 in the income statement. See above tables for the income statement impact of derivative activity, including commodity trading gains and losses.
Fair Value of Long-Term Debt
As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value:
| 2022 | 2021 | |||||||||||||||||||||||||
| (Millions of Dollars) | Carrying Amount | Fair Value | Carrying Amount | Fair Value | ||||||||||||||||||||||
| Long-term debt, including current portion | $ | 23,964 | $ | 20,897 | $ | 22,380 | $ | 25,232 | ||||||||||||||||||
Fair value of Xcel Energy’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. Fair value estimates are based on information available to management as of Dec. 31, 2022 and 2021, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.
11. Benefit Plans and Other Postretirement Benefits | ||
Pension and Postretirement Health Care Benefits
Xcel Energy 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 4.89, 2.03 and 1.89% 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. Xcel Energy recognized net benefit cost for the SERP and nonqualified plans of $17 million in 2022 and $4 million in 2021.
Xcel Energy’s investment-return assumption considers the expected long-term performance for each of the asset classes in its pension and postretirement health care portfolio. Xcel Energy considers the historical returns achieved by its asset portfolios over long time periods, as well as the long-term projected return levels from investment experts.
Pension cost determination assumes a forecasted mix of investment types over the long-term.
•Investment returns in 2022 were below the assumed level of 6.49%.
•Investment returns in 2021 were above the assumed level of 6.49%.
•Investment returns in 2020 were above the assumed level of 6.87%.
•In 2023, expected investment-return assumption is 6.93%.
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. PSCo is required to fund postretirement benefit costs in irrevocable external trusts that are dedicated to the payment of these postretirement benefits. 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.
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Plan Assets
For each of the fair value hierarchy levels, Xcel Energy’s pension plan assets measured at fair value:
Dec. 31, 2022 (a) | Dec. 31, 2021 (a) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (Millions of Dollars) | Level 1 | Level 2 | Level 3 | Measured at NAV | Total | Level 1 | Level 2 | Level 3 | Measured at NAV | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Cash equivalents | $ | 129 | $ | — | $ | — | $ | — | $ | 129 | $ | 133 | $ | — | $ | — | $ | — | $ | 133 | ||||||||||||||||||||||||||||||||||||||||||
| Commingled funds | 935 | — | — | 882 | 1,817 | 1,324 | — | — | 1,143 | 2,467 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Debt securities | — | 682 | 3 | — | 685 | — | 959 | 5 | — | 964 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Equity securities | 47 | — | — | — | 47 | 67 | — | — | — | 67 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other | — | 7 | — | — | 7 | — | 7 | — | 32 | 39 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total | $ | 1,111 | $ | 689 | $ | 3 | $ | 882 | $ | 2,685 | $ | 1,524 | $ | 966 | $ | 5 | $ | 1,175 | $ | 3,670 | ||||||||||||||||||||||||||||||||||||||||||
(a)See Note 10 for further information regarding fair value measurement inputs and methods.
For each of the fair value hierarchy levels, Xcel Energy’s postretirement benefit plan assets that were measured at fair value:
Dec. 31, 2022 (a) | Dec. 31, 2021 (a) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (Millions of Dollars) | Level 1 | Level 2 | Level 3 | Measured at NAV | Total | Level 1 | Level 2 | Level 3 | Measured at NAV | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Cash equivalents | $ | 31 | $ | — | $ | — | $ | — | $ | 31 | $ | 28 | $ | — | $ | — | $ | — | $ | 28 | ||||||||||||||||||||||||||||||||||||||||||
| Insurance contracts | — | 41 | — | — | 41 | — | 52 | — | — | 52 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Commingled funds | 54 | — | — | 63 | 117 | 64 | — | — | 77 | 141 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Debt securities | — | 175 | 1 | — | 176 | — | 218 | 1 | — | 219 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other | — | (1) | — | — | (1) | — | 2 | — | — | 2 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total | $ | 85 | $ | 215 | $ | 1 | $ | 63 | $ | 364 | $ | 92 | $ | 272 | $ | 1 | $ | 77 | $ | 442 | ||||||||||||||||||||||||||||||||||||||||||
(a)See Note 10 for further information on fair value measurement inputs and methods.
Immaterial assets were transferred in or out of Level 3 for 2022. No assets were transferred in or out of Level 3 for 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 Xcel Energy are as follows:
| Pension Benefits | Postretirement Benefits | |||||||||||||||||||||||||
| (Millions of Dollars) | 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||||
| Change in Benefit Obligation: | ||||||||||||||||||||||||||
| Obligation at Jan. 1 | $ | 3,718 | $ | 3,964 | $ | 511 | $ | 574 | ||||||||||||||||||
| Service cost | 97 | 104 | 2 | 2 | ||||||||||||||||||||||
| Interest cost | 110 | 104 | 15 | 15 | ||||||||||||||||||||||
| Plan amendments | 1 | 5 | — | — | ||||||||||||||||||||||
| Actuarial gain | (703) | (94) | (85) | (41) | ||||||||||||||||||||||
| Plan participants’ contributions | — | — | 8 | 8 | ||||||||||||||||||||||
| Medicare subsidy reimbursements | — | — | 2 | 2 | ||||||||||||||||||||||
Benefit payments (a) | (352) | (365) | (48) | (49) | ||||||||||||||||||||||
| Obligation at Dec. 31 | $ | 2,871 | $ | 3,718 | $ | 405 | $ | 511 | ||||||||||||||||||
| Change in Fair Value of Plan Assets: | ||||||||||||||||||||||||||
| Fair value of plan assets at Jan. 1 | $ | 3,670 | $ | 3,599 | $ | 442 | $ | 452 | ||||||||||||||||||
| Actual return on plan assets | (683) | 305 | (51) | 16 | ||||||||||||||||||||||
| Employer contributions | 50 | 131 | 13 | 15 | ||||||||||||||||||||||
| Plan participants’ contributions | — | — | 8 | 8 | ||||||||||||||||||||||
| Benefit payments | (352) | (365) | (48) | (49) | ||||||||||||||||||||||
| Fair value of plan assets at Dec. 31 | $ | 2,685 | $ | 3,670 | $ | 364 | $ | 442 | ||||||||||||||||||
| Funded status of plans at Dec. 31 | $ | (186) | $ | (48) | $ | (41) | $ | (69) | ||||||||||||||||||
| Amounts recognized in the Consolidated Balance Sheet at Dec. 31: | ||||||||||||||||||||||||||
| Noncurrent assets | $ | 15 | $ | 19 | $ | 33 | $ | 33 | ||||||||||||||||||
| Current liabilities | — | — | (2) | (4) | ||||||||||||||||||||||
| Noncurrent liabilities | (201) | (67) | (72) | (98) | ||||||||||||||||||||||
| Net amounts recognized | $ | (186) | $ | (48) | $ | (41) | $ | (69) | ||||||||||||||||||
(a)Includes approximately $195 million in 2022 and $197 million in 2021 of lump-sum benefit payments used in the determination of a settlement charge.
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| 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 $2,672 million and $3,469 million as of Dec. 31, 2022 and 2021, respectively.
Net Periodic Benefit Cost (Credit) — Net periodic benefit cost (credit), other than the service cost component, is included in other income (expense) in the consolidated statements of income.
Components of net periodic benefit cost (credit) and amounts recognized in other comprehensive income and regulatory assets and liabilities:
| Pension Benefits | Postretirement Benefits | |||||||||||||||||||||||||||||||||||||
| (Millions of Dollars) | 2022 | 2021 | 2020 | 2022 | 2021 | 2020 | ||||||||||||||||||||||||||||||||
| Service cost | $ | 97 | $ | 104 | $ | 95 | $ | 2 | $ | 2 | $ | 1 | ||||||||||||||||||||||||||
| Interest cost | 110 | 104 | 125 | 15 | 15 | 18 | ||||||||||||||||||||||||||||||||
| Expected return on plan assets | (208) | (206) | (208) | (18) | (18) | (19) | ||||||||||||||||||||||||||||||||
| Amortization of prior service credit | (1) | (1) | (4) | (6) | (8) | (8) | ||||||||||||||||||||||||||||||||
| Amortization of net loss | 75 | 107 | 100 | 2 | 5 | 4 | ||||||||||||||||||||||||||||||||
Settlement charge (a) | 71 | 59 | — | — | — | — | ||||||||||||||||||||||||||||||||
| Net periodic pension cost (credit) | 144 | 167 | 108 | (5) | (4) | (4) | ||||||||||||||||||||||||||||||||
| Effects of regulation | (30) | (46) | 9 | 3 | 2 | 3 | ||||||||||||||||||||||||||||||||
| Net benefit cost (credit) recognized for financial reporting | $ | 114 | $ | 121 | $ | 117 | $ | (2) | $ | (2) | $ | (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 | 6.49 | 6.49 | 6.87 | 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 and 2021, as a result of lump-sum distributions during each plan year, Xcel Energy recorded a total pension settlement charge of $71 million and $59 million, respectively, the majority of which was not recognized due to the effects of regulation. A total of $9 million and $7 million was recorded in the consolidated statements of income in 2022 and 2021, respectively. There were no settlement charges recorded for the qualified pension plans in 2020.
| Pension Benefits | Postretirement Benefits | |||||||||||||||||||||||||
| (Millions of Dollars) | 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||||
| Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: | ||||||||||||||||||||||||||
| Net loss | $ | 1,021 | $ | 978 | $ | 63 | $ | 81 | ||||||||||||||||||
| Prior service credit | (7) | (9) | (1) | (7) | ||||||||||||||||||||||
| Total | $ | 1,014 | $ | 969 | $ | 62 | $ | 74 | ||||||||||||||||||
| 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 | $ | 21 | $ | 74 | $ | — | $ | — | ||||||||||||||||||
| Noncurrent regulatory assets | 943 | 846 | 78 | 90 | ||||||||||||||||||||||
| Current regulatory liabilities | — | — | (1) | (1) | ||||||||||||||||||||||
| Noncurrent regulatory liabilities | — | — | (20) | (19) | ||||||||||||||||||||||
| Deferred income taxes | 14 | 13 | 1 | 1 | ||||||||||||||||||||||
| Net-of-tax accumulated other comprehensive income | 36 | 36 | 4 | 3 | ||||||||||||||||||||||
| Total | $ | 1,014 | $ | 969 | $ | 62 | $ | 74 | ||||||||||||||||||
| Measurement date | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2022 | Dec. 31, 2021 | ||||||||||||||||||||||
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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.
Voluntary and required pension funding contributions:
•$50 million in January 2023.
•$50 million in 2022.
•$131 million in 2021.
•$150 million in 2020.
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.
Voluntary postretirement funding contributions:
•$12 million expected during 2023.
•$13 million during 2022.
•$15 million during 2021.
•$11 million during 2020.
Targeted 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
Xcel Energy’s projected benefit payments:
| (Millions of Dollars) | Projected Pension Benefit Payments | Gross Projected Postretirement Health Care Benefit Payments | Expected Medicare Part D Subsidies | Net Projected Postretirement Health Care Benefit Payments | ||||||||||||||||||||||
| 2023 | $ | 283 | $ | 42 | $ | 2 | $ | 40 | ||||||||||||||||||
| 2024 | 249 | 41 | 2 | 39 | ||||||||||||||||||||||
| 2025 | 249 | 40 | 2 | 38 | ||||||||||||||||||||||
| 2026 | 246 | 39 | 2 | 37 | ||||||||||||||||||||||
| 2027 | 243 | 37 | 2 | 35 | ||||||||||||||||||||||
| 2028 - 2032 | 1,162 | 167 | 12 | 155 | ||||||||||||||||||||||
Defined Contribution Plans
Xcel Energy maintains 401(k) and other defined contribution plans that cover most employees. Total expense to these plans was approximately $46 million in 2022, $43 million in 2021 and $42 million in 2020.
Multiemployer Plans
NSP-Minnesota and NSP-Wisconsin each contribute to several union multiemployer pension and other postretirement benefit plans, none of which are individually significant. These plans provide pension and postretirement health care benefits to certain union employees who may perform services for multiple employers and do not participate in the NSP-Minnesota and NSP-Wisconsin sponsored pension and postretirement health care plans.
Contributing to these types of plans creates risk that differs from providing benefits under NSP-Minnesota and NSP-Wisconsin sponsored plans, in that if another participating employer ceases to contribute to a multiemployer plan, additional unfunded obligations may need to be funded over time by remaining participating employers.
12. Commitments and Contingencies | ||
Legal
Xcel Energy 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 Xcel Energy’s consolidated financial statements. Legal fees are generally expensed as incurred.
Gas Trading Litigation — e prime is a wholly owned subsidiary of Xcel Energy. e prime was in the business of natural gas trading and marketing but has not engaged in natural gas trading or marketing activities since 2003. Multiple lawsuits involving multiple plaintiffs seeking monetary damages were commenced against e prime and its affiliates, including Xcel Energy, between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. Cases were all consolidated in the U.S. District Court in Nevada.
One case remains active which includes a multi-district litigation matter consisting of a Wisconsin purported class (Arandell Corp.). The Court issued a ruling on June 30, 2022 granting plaintiffs’ class certification. Defendants will work together to prepare and file a petition appealing the class certification ruling to the Seventh Circuit. Xcel Energy has concluded that a loss is remote for the remaining lawsuit.
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Comanche Unit 3 Litigation — In 2021, CORE filed a lawsuit in Denver County District Court, alleging PSCo breached ownership agreement terms by failing to operate Comanche Unit 3 in accordance with prudent utility practices. In January 2022, the Court granted PSCo’s motion to dismiss CORE’s claims for unjust enrichment, declaratory judgment and damages for replacement power costs. In April 2022, CORE filed a supplement to include the January 2022 outage and damages related to this event. Also in 2022, CORE sent notice of withdrawal from the ownership agreement based on the same alleged breaches. In February 2023, CORE disclosed its expert witness, who estimated damages incurred of $270 million. Also in February 2023, the court granted PSCo’s motion precluding CORE from seeking damages related to its withdrawal as part of the lawsuit. PSCo continues to believe CORE's claims are without merit and disputes CORE’s right to withdraw.
Rate Matters and Other
Xcel Energy’s operating subsidiaries are involved in various regulatory proceedings arising in the ordinary course of business. Until resolution, typically in the form of a rate order, uncertainties may exist regarding the ultimate rate treatment for certain activities and transactions. Amounts have been recognized for probable and reasonably estimable losses that may result. Unless otherwise disclosed, any reasonably possible range of loss in excess of any recognized amount is not expected to have a material effect on the consolidated financial statements.
Sherco — In 2018, NSP-Minnesota and Southern Minnesota Municipal Power Agency (Co-owner of Sherco Unit 3) reached a settlement with GE related to a 2011 incident, which damaged the turbine at Sherco Unit 3 and resulted in an extended outage for repair. NSP-Minnesota notified the MPUC of its proposal to refund settlement proceeds to customers through the fuel clause adjustment.
In March 2019, the MPUC approved NSP-Minnesota’s settlement refund proposal. Additionally, the MPUC decided to withhold any decision as to NSP-Minnesota’s prudence in connection with the incident at Sherco Unit 3 until after conclusion of an appeal pending between GE and NSP-Minnesota’s insurers.
In February 2020, the Minnesota Court of Appeals affirmed the district court’s judgment in favor of GE. In March 2020, NSP-Minnesota’s insurers filed a petition seeking additional review by the Minnesota Supreme Court. In April 2020, the Minnesota Supreme Court denied the insurers’ petition for further review, ending the litigation.
In January 2021, the Minnesota Office of the Attorney General and DOC recommended that NSP-Minnesota refund approximately $17 million of replacement power costs previously recovered through the fuel clause adjustment. NSP-Minnesota subsequently filed its response, asserting that it acted prudently in connection with the Sherco Unit 3 outage, the MPUC has previously disallowed $22 million of related costs and no additional refund or disallowance is appropriate.
A final decision by the MPUC is expected in mid-2024. A loss related to this matter is deemed remote.
MISO ROE Complaints — In November 2013 and February 2015, customer groups filed two ROE complaints against MISO TOs, which includes NSP-Minnesota and NSP-Wisconsin. The first complaint requested a reduction in base ROE transmission formula rates from 12.38% to 9.15% for the time period of Nov. 12, 2013 to Feb. 11, 2015, and removal of ROE adders (including those for RTO membership). The second complaint requested, for a subsequent time period, a base ROE reduction from 12.38% to 8.67%.
The FERC subsequently issued various related orders (including Opinion Nos. 569, 569A and 569B) related to ROE methodology/calculations and timing. NSP-Minnesota has processed refunds to customers for applicable complaint periods based on the ROE in the most recent applicable opinions.
The MISO TOs and various other parties have filed petitions for review of the FERC’s most recent applicable opinions at the D.C. Circuit. In August 2022, the D.C. Circuit ruled that FERC had not adequately supported its conclusions, vacated FERC’s related orders and remanded the issue back to FERC for further proceedings, which remain pending. Additional exposure, if any related to this matter is expected to be immaterial.
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 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 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 2020, SPP and Oklahoma Gas & Electric separately filed petitions for review of the FERC’s orders at the D.C. Circuit. In 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 2017, SPS filed a separate related complaint asserting SPP assessed upgrade charges to SPS in violation of the SPP OATT. In 2018, the FERC issued an order denying the SPS complaint. SPS filed a request for rehearing in 2018. The FERC subsequently issued a tolling order granting a rehearing for further consideration. If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the amount through future SPS customer rates. In 2020, SPS filed a petition for review of the FERC’s 2018 orders 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 Xcel Energy, which are normally recovered through the regulated rate process.
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Site Remediation
Various federal and state environmental laws impose liability where hazardous substances or other regulated materials have been released to the environment. Xcel Energy Inc.’s subsidiaries may sometimes pay all or a portion of the cost to remediate sites where past activities of their 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 one or more of Xcel Energy Inc.’s subsidiaries are alleged to have sent wastes to that site.
Historical MGP, Landfill and Disposal Sites
Xcel Energy is currently investigating, remediating or performing post-closure actions at 9 historical MGP, landfill or other disposal sites across its service territories, excluding sites that are being addressed under current coal ash regulations (see below).
Xcel Energy has recognized its best estimate of costs/liabilities from final resolution of these issues; however, the outcome and timing are unknown. In addition, there may be insurance recovery and/or recovery from other potentially responsible parties, offsetting a portion of costs incurred.
Environmental Requirements — Water and Waste
Coal Ash Regulation — Xcel Energy’s operations are subject to federal and state regulations that impose requirements for handling, storage, treatment and disposal of solid waste. Under the CCR Rule, utilities are required to complete groundwater sampling around their applicable landfills and surface impoundments as well as perform corrective actions where offsite groundwater has been impacted.
As of Dec. 31, 2022, Xcel Energy had eight regulated ash units in operation.
PSCo is currently exploring an agreement with a third party that would excavate and process ash for beneficial use (at two sites) and perform restoration at one site at a cost of approximately $45 million. An estimated liability has been recorded and amounts are expected to be fully recoverable through regulatory mechanisms.
Investigation and feasibility studies for additional corrective action related to offsite groundwater are ongoing (three sites). While the results are uncertain, additional costs are estimated to be up to $35 million. A liability has been recorded for the portion estimable/probable and are expected to be fully recoverable through regulatory mechanisms.
Federal Clean Water Act Section 316(b) — The Federal Clean Water Act requires the EPA to regulate cooling water intake structures to assure they reflect the best technology available for minimizing impingement and entrainment of aquatic species.
Estimated capital expenditures of approximately $45 million may be required for NSP-Minnesota to comply with the requirements pending approval of mitigation plans from the MPCA. Xcel Energy anticipates these costs will be recoverable through regulatory mechanisms.
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.
AROs — AROs have been recorded for Xcel Energy’s assets. For nuclear assets, the ARO is associated with the decommissioning of NSP-Minnesota nuclear generating plants.
Aggregate fair value of NSP-Minnesota’s legally restricted assets, for funding future nuclear decommissioning was $2.9 billion and $3.3 billion for 2022 and 2021, respectively.
Xcel Energy’s AROs were as follows:
| (Millions of Dollars) | Jan. 1, 2022 | Amounts Incurred (a) | Accretion | Cash Flow Revisions (b) | Dec. 31, 2022 | |||||||||||||||||||||||||||
| Electric | ||||||||||||||||||||||||||||||||
| Nuclear | $ | 2,056 | $ | — | $ | 104 | $ | — | $ | 2,160 | ||||||||||||||||||||||
| Wind | 478 | 25 | 19 | (8) | 514 | |||||||||||||||||||||||||||
| Steam, hydro and other production | 288 | 34 | 12 | 14 | 348 | |||||||||||||||||||||||||||
| Distribution | 47 | — | 1 | — | 48 | |||||||||||||||||||||||||||
| Natural gas | ||||||||||||||||||||||||||||||||
| Transmission and distribution | 271 | — | 12 | 23 | 306 | |||||||||||||||||||||||||||
| Miscellaneous | 8 | — | — | (7) | 1 | |||||||||||||||||||||||||||
| Common | ||||||||||||||||||||||||||||||||
| Miscellaneous | 1 | — | — | — | 1 | |||||||||||||||||||||||||||
| Non-utility | ||||||||||||||||||||||||||||||||
| Miscellaneous | 2 | — | — | — | 2 | |||||||||||||||||||||||||||
| Total liability | $ | 3,151 | $ | 59 | $ | 148 | $ | 22 | $ | 3,380 | ||||||||||||||||||||||
(a)Amounts incurred related to the wind farms placed in service in 2022 for NSP-Minnesota (Dakota Range and Rock Aetna) and steam production pond remediation costs for PSCo.
(b)In 2022, AROs were revised for changes in timing and estimates of cash flows. Revisions in steam, hydro and other production AROs were primarily related to changes in cost estimates for remediation of ash containment facilities. Changes in gas transmission and distribution AROs were primarily related to changes in labor rates coupled with increased gas line mileage and number of services.
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| (Millions of Dollars) | Jan. 1, 2021 | Amounts Incurred (a) | Accretion | Cash Flow Revisions (b) | Dec. 31, 2021 | |||||||||||||||||||||||||||
| Electric | ||||||||||||||||||||||||||||||||
| Nuclear | $ | 1,957 | $ | — | $ | 99 | $ | — | $ | 2,056 | ||||||||||||||||||||||
| Wind | 360 | 101 | 17 | — | 478 | |||||||||||||||||||||||||||
| Steam, hydro and other production | 264 | 6 | 10 | 8 | 288 | |||||||||||||||||||||||||||
| Distribution | 46 | — | 1 | — | 47 | |||||||||||||||||||||||||||
| Natural gas | ||||||||||||||||||||||||||||||||
| Transmission and distribution | 252 | — | 10 | 9 | 271 | |||||||||||||||||||||||||||
| Miscellaneous | 3 | — | — | 5 | 8 | |||||||||||||||||||||||||||
| Common | ||||||||||||||||||||||||||||||||
| Miscellaneous | 1 | — | — | — | 1 | |||||||||||||||||||||||||||
| Non-utility | ||||||||||||||||||||||||||||||||
| Miscellaneous | 1 | — | 1 | — | 2 | |||||||||||||||||||||||||||
| Total liability | $ | 2,884 | $ | 107 | $ | 138 | $ | 22 | $ | 3,151 | ||||||||||||||||||||||
(a)Amounts incurred related to the wind farms placed in service in 2021 for NSP-Minnesota (Blazing Star 2, Mower and Freeborn) and removal of a utility scale battery asset in NSP-Minnesota.
(b)In 2021, AROs were revised for changes in timing and estimates of cash flows. Revisions in steam, hydro and other production AROs were primarily related to changes in cost estimates for remediation of ash containment facilities. Changes in gas transmission and distribution AROs were primarily related to changes in labor rates coupled with increased gas line mileage and number of services.
Indeterminate AROs — Outside of the recorded asbestos AROs, other plants or buildings may contain asbestos due to the age of many of Xcel Energy’s facilities, but no confirmation or measurement of the cost of removal could be determined as of Dec. 31, 2022. Therefore, an ARO was not recorded for these facilities.
Nuclear
Nuclear Insurance — NSP-Minnesota’s public liability for claims from any nuclear incident is limited to $13.7 billion under the Price-Anderson amendment to the Atomic Energy Act. NSP-Minnesota has $450 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $13.2 billion of exposure is funded by the Secondary Financial Protection Program available from assessments by the federal government.
NSP-Minnesota is subject to assessments of up to $138 million per reactor-incident for each of its three reactors, for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $20 million per reactor-incident during any one year. Maximum assessments are subject to inflation adjustments.
NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from NEIL and EMANI. The coverage limits are $2.8 billion for each of NSP-Minnesota’s two nuclear plant sites. NEIL also provides business interruption insurance coverage up to $350 million, including the cost of replacement power during prolonged accidental outages of nuclear generating units. Premiums are expensed over the policy term.
All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NEIL and EMANI to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage.
NSP-Minnesota could be subject to annual maximum assessments of $12 million for business interruption insurance and $32 million for property damage insurance if losses exceed accumulated reserve funds.
Nuclear Fuel Disposal — NSP-Minnesota is responsible for temporarily storing spent nuclear fuel from its nuclear plants. The DOE is responsible for permanently storing spent fuel from U.S. nuclear plants, but no such facility is yet available.
NSP-Minnesota owns temporary on-site storage facilities for spent fuel at its Monticello and PI nuclear plants, which consist of storage pools and dry cask facilities. The Monticello dry-cask storage facility currently stores all 30 of the authorized canisters. The PI dry-cask storage facility currently stores 50 of the 64 authorized casks. Monticello’s future spent fuel will continue to be placed in its spent fuel pool. The decommissioning plan addresses the disposition of spent fuel at the end of the licensed life. A CON for additional storage at the Monticello site has been filed with the MPUC, to support possible life extension to 2040. NSP-Minnesota expects a decision by year-end 2023.
Regulatory Plant Decommissioning Recovery — Decommissioning activities for NSP-Minnesota’s nuclear facilities are planned to begin at the end of each unit’s authorized retirement dates, which can be different than the currently approved NRC operating licenses. These decommissioning activities are planned to be completed at both facilities by 2101.
NSP-Minnesota’s current operating licenses allow continued use of its Monticello nuclear plant until 2030 and its PI nuclear plant until 2033 for Unit 1 and 2034 for Unit 2. The MPUC reaffirmed a 60-year DECON scenario, where Monticello continues operations under a 10-year license extension (approved in August 2022). NRC approval of the extension is pending.
Future decommissioning costs of nuclear facilities are estimated through triennial periodic studies that assess the costs and timing of planned nuclear decommissioning activities for each unit. The 2020 nuclear decommissioning filing was approved by the MPUC and became effective in 2022.
Obligations for decommissioning are expected to be funded 100% by the external decommissioning trust fund. NSP-Minnesota had $2.9 billion and $3.3 billion of assets held in external decommissioning trusts at Dec. 31, 2022, and 2021, respectively.
See Note 10 to the consolidated financial statements for additional discussion.
Leases
Xcel Energy 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 Xcel Energy's rights to use leased assets. The present value of future operating lease payments is recognized in other current liabilities and noncurrent operating lease liabilities. These amounts, adjusted for any prepayments or incentives, are recognized as operating lease ROU assets.
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Most of Xcel Energy’s leases do not contain a readily determinable discount rate. Therefore, the present value of future lease payments is generally calculated using the applicable Xcel Energy subsidiary’s estimated incremental borrowing rate (weighted average of 4.1%). Xcel Energy has elected the practical expedient under which non-lease components, such as asset maintenance costs included in payments, are not deducted from minimum lease payments for the purposes of lease accounting and disclosure.
Leases with an initial term of 12 months or less are classified as short-term leases and are not recognized on the consolidated balance sheet.
Operating lease ROU assets:
| (Millions of Dollars) | Dec. 31, 2022 | Dec. 31, 2021 | ||||||||||||
| PPAs | $ | 1,669 | $ | 1,656 | ||||||||||
| Other | 244 | 225 | ||||||||||||
| Gross operating lease ROU assets | 1,913 | 1,881 | ||||||||||||
| Accumulated amortization | (709) | (590) | ||||||||||||
| Net operating lease ROU assets | $ | 1,204 | $ | 1,291 | ||||||||||
ROU assets for finance leases are included in other noncurrent assets, and the present value of future finance lease payments is included in other current liabilities and other noncurrent liabilities.
Xcel Energy’s most significant finance lease activities are related to WYCO, a joint venture with CIG, to develop and lease natural gas pipeline, storage and compression facilities. Xcel Energy Inc. has a 50% ownership interest in WYCO. WYCO leases its facilities to CIG, and CIG operates the facilities, providing natural gas storage and transportation services to PSCo under separate service agreements.
PSCo accounts for its Totem natural gas storage service and Front Range pipeline arrangements with CIG and WYCO, respectively, as finance leases. Xcel Energy Inc. eliminates 50% of the finance lease obligation related to WYCO in the consolidated balance sheet along with an equal amount of Xcel Energy Inc.’s equity investment in WYCO.
Finance lease ROU assets:
| (Millions of Dollars) | Dec. 31, 2022 | Dec. 31, 2021 | ||||||||||||
| Gas storage facilities | $ | 160 | $ | 201 | ||||||||||
| Gas pipeline | 21 | 21 | ||||||||||||
| Gross finance lease ROU assets | 181 | 222 | ||||||||||||
| Accumulated amortization | (64) | (97) | ||||||||||||
| $ | 117 | $ | 125 | |||||||||||
Components of lease expense:
| (Millions of Dollars) | 2022 | 2021 | 2020 | |||||||||||||||||
| Operating leases | ||||||||||||||||||||
| PPA capacity payments | $ | 241 | $ | 251 | $ | 238 | ||||||||||||||
Other operating leases (a) | 39 | 36 | 26 | |||||||||||||||||
Total operating lease expense (b) | $ | 280 | $ | 287 | $ | 264 | ||||||||||||||
| Finance leases | ||||||||||||||||||||
| Amortization of ROU assets | $ | 4 | $ | 7 | $ | 7 | ||||||||||||||
| Interest expense on lease liability | 16 | 17 | 18 | |||||||||||||||||
| Total finance lease expense | $ | 20 | $ | 24 | $ | 25 | ||||||||||||||
(a)Includes short-term lease expense of $6 million for 2022 and $5 million for 2021 and 2020.
(b)PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income. Expense for other operating leases is included in O&M expense and electric fuel and purchased power.
Commitments under operating and finance leases as of Dec. 31, 2022:
| (Millions of Dollars) | PPA (a) (b) Operating Leases | Other Operating Leases | Total Operating Leases | Finance Leases (c) | ||||||||||||||||||||||
| 2023 | $ | 231 | $ | 33 | $ | 264 | $ | 10 | ||||||||||||||||||
| 2024 | 238 | 28 | 266 | 10 | ||||||||||||||||||||||
| 2025 | 217 | 23 | 240 | 10 | ||||||||||||||||||||||
| 2026 | 161 | 18 | 179 | 9 | ||||||||||||||||||||||
| 2027 | 90 | 18 | 108 | 8 | ||||||||||||||||||||||
| Thereafter | 326 | 74 | 400 | 181 | ||||||||||||||||||||||
| Total minimum obligation | 1,263 | 194 | 1,457 | 228 | ||||||||||||||||||||||
| Interest component of obligation | (170) | (32) | (202) | (162) | ||||||||||||||||||||||
| Present value of minimum obligation | $ | 1,093 | 162 | 1,255 | 66 | |||||||||||||||||||||
| Less current portion | (217) | (2) | ||||||||||||||||||||||||
| $ | 1,038 | $ | 64 | |||||||||||||||||||||||
| Weighted-average remaining lease term in years | 7.9 | 37.8 | ||||||||||||||||||||||||
(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.
(c)Excludes certain amounts related to Xcel Energy’s 50% ownership interest in WYCO.
PPAs and Fuel Contracts
Non-Lease PPAs — NSP-Minnesota, PSCo and SPS have entered into PPAs with other utilities and energy suppliers for purchased power to meet system load and energy requirements, operating reserve obligations and as part of wholesale and commodity trading activities. In general, these agreements provide for energy payments, based on actual energy delivered and capacity payments. Certain PPAs, accounted for as executory contracts with various expiration dates through 2033, contain minimum energy purchase commitments. Total energy payments on those contracts were $182 million, $149 million and $112 million in 2022, 2021 and 2020, respectively.
Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $75 million, $69 million and $75 million in 2022, 2021 and 2020, respectively.
Capacity and energy payments are contingent on the IPPs meeting contract obligations, including plant availability requirements. Certain contractual payments are adjusted based on market indices. The effects of price adjustments on financial results are mitigated through purchased energy cost recovery mechanisms.
At Dec. 31, 2022, the estimated future payments for capacity and energy that the utility subsidiaries of Xcel Energy are obligated to purchase pursuant to these executory contracts, subject to availability, were as follows:
| (Millions of Dollars) | Capacity | Energy (a) | ||||||||||||
| 2023 | $ | 77 | $ | 50 | ||||||||||
| 2024 | 72 | 45 | ||||||||||||
| 2025 | 29 | 51 | ||||||||||||
| 2026 | 10 | 48 | ||||||||||||
| 2027 | 7 | 55 | ||||||||||||
| Thereafter | 3 | 28 | ||||||||||||
| Total | $ | 198 | $ | 277 | ||||||||||
(a)Excludes contingent energy payments for renewable energy PPAs.
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Fuel Contracts — Xcel Energy has entered into various long-term commitments for the purchase and delivery of a significant portion of its coal, nuclear fuel and natural gas requirements. These contracts expire between 2023 and 2060. Xcel Energy 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 | Nuclear fuel | Natural gas supply | Natural gas supply and transportation | ||||||||||||||||||||||
| 2023 | $ | 628 | $ | 144 | $ | 684 | $ | 316 | ||||||||||||||||||
| 2024 | 343 | 112 | 8 | 290 | ||||||||||||||||||||||
| 2025 | 90 | 158 | 1 | 276 | ||||||||||||||||||||||
| 2026 | 53 | 37 | — | 276 | ||||||||||||||||||||||
| 2027 | 55 | 155 | — | 225 | ||||||||||||||||||||||
| Thereafter | 2 | 194 | — | 607 | ||||||||||||||||||||||
| Total | $ | 1,171 | $ | 800 | $ | 693 | $ | 1,990 | ||||||||||||||||||
VIEs
PPAs — Under certain PPAs, NSP-Minnesota, PSCo and SPS purchase power from IPPs for which the utility subsidiaries are required to reimburse fuel costs, or to participate in tolling arrangements under which the utility subsidiaries procure the natural gas required to produce the energy that they purchase. Xcel Energy has determined that certain IPPs are VIEs, however it 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.
Xcel Energy 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. Xcel Energy concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance.
The utility subsidiaries had approximately 3,961 MW and 4,062 MW of capacity under these long-term PPAs at Dec. 31, 2022 and 2021, respectively, with entities that have been determined to be VIEs. These agreements have expiration dates through 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.
Low-Income Housing Limited Partnerships — Eloigne and NSP-Wisconsin have entered into limited partnerships with affordable rental housing activities that qualify for low-income housing tax credits.
Eloigne and NSP-Wisconsin, as primary beneficiaries of these activities, consolidate these limited partnerships in their consolidated financial statements.
Amounts reflected in Xcel Energy’s consolidated balance sheets for these investments include $44 million of assets and $35 million of liabilities at Dec. 31, 2022, and $45 million of assets and $35 million of liabilities at Dec. 31, 2021.
Other
Technology Agreements — Xcel Energy has several contracts for information technology services that extend through 2027. The contracts are cancelable, although there are financial penalties for early termination. Xcel Energy capitalized or expensed $181 million, $103 million and $110 million associated with these vendors in 2022, 2021 and 2020, respectively.
Committed minimum payments under these obligations as follows:
| (Millions of Dollars) | Minimum Payments | |||||||
| 2023 | $ | 24 | ||||||
| 2024 | 13 | |||||||
| 2025 | 12 | |||||||
| 2026 | 11 | |||||||
| 2027 | 10 | |||||||
| Thereafter | — | |||||||
Guarantees and Bond Indemnifications — Xcel Energy Inc. and its subsidiaries provide guarantees and bond indemnities, which guarantee payment or performance. Xcel Energy Inc.’s exposure is based upon the net liability under the specified agreements or transactions. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries have a stated maximum amount.
As of Dec. 31, 2022 and 2021, Xcel Energy Inc. and its subsidiaries had no assets held as collateral related to their guarantees, bond indemnities and indemnification agreements. Guarantees and bond indemnities issued and outstanding for Xcel Energy were $62 million and $60 million at Dec. 31, 2022 and 2021 respectively.
Other Indemnification Agreements — Xcel Energy Inc. and its subsidiaries provide indemnifications through various contracts. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, as well as breaches of representations and warranties, including corporate existence, transaction authorization and income tax matters with respect to assets sold.
Xcel Energy Inc.’s and its subsidiaries’ obligations under these agreements may be limited in terms of duration and amount. Maximum future payments under these indemnifications cannot be reasonably estimated as the dollar amounts are often not explicitly stated.
77
13. Other Comprehensive Income | ||
Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31:
| 2022 | ||||||||||||||||||||
| (Millions of Dollars) | Gains and Losses on Interest Rate Cash Flow Hedges | Defined Benefit Pension and Postretirement Items | Total | |||||||||||||||||
| Accumulated other comprehensive loss at Jan. 1 | $ | (75) | $ | (48) | $ | (123) | ||||||||||||||
| Other comprehensive gain before reclassifications | 16 | 5 | 21 | |||||||||||||||||
| Losses reclassified from net accumulated other comprehensive loss: | ||||||||||||||||||||
| Amortization of interest rate hedges | 5 | (a) | — | 5 | ||||||||||||||||
| Amortization of net actuarial loss | — | 4 | (b) | 4 | ||||||||||||||||
| Net current period other comprehensive income | 21 | 9 | 30 | |||||||||||||||||
| Accumulated other comprehensive loss at Dec. 31 | $ | (54) | $ | (39) | $ | (93) | ||||||||||||||
(a)Included in interest charges.
(b)Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information.
| 2021 | ||||||||||||||||||||
| (Millions of Dollars) | Gains and Losses on Interest Rate Cash Flow Hedges | Defined Benefit Pension and Postretirement Items | Total | |||||||||||||||||
| Accumulated other comprehensive loss at Jan. 1 | $ | (85) | $ | (56) | $ | (141) | ||||||||||||||
| Other comprehensive gain before reclassifications | 4 | — | 4 | |||||||||||||||||
| Losses reclassified from net accumulated other comprehensive loss: | ||||||||||||||||||||
| Amortization of interest rate hedges | 6 | (a) | — | 6 | ||||||||||||||||
| Amortization of net actuarial loss | — | 8 | (b) | 8 | ||||||||||||||||
| Net current period other comprehensive income | 10 | 8 | 18 | |||||||||||||||||
| Accumulated other comprehensive loss at Dec. 31 | $ | (75) | $ | (48) | $ | (123) | ||||||||||||||
(a)Included in interest charges.
(b)Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information.
14. Segment Information | ||
Xcel Energy evaluates performance by each utility subsidiary based on profit or loss generated from the product or service provided, including the regulated electric utility operating results of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS, as well as the regulated natural gas utility operating results of NSP-Minnesota, NSP-Wisconsin and PSCo. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment.
Xcel Energy has the following reportable segments:
•Regulated Electric — The regulated electric utility segment generates, transmits and distributes electricity in Minnesota, Wisconsin, Michigan, North Dakota, South Dakota, Colorado, Texas and New Mexico. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. The regulated electric utility segment also includes wholesale commodity and trading operations.
•Regulated Natural Gas — The regulated natural gas utility segment transports, stores and distributes natural gas primarily in portions of Minnesota, Wisconsin, North Dakota, Michigan and Colorado.
Xcel Energy also presents All Other, which includes operating segments with revenues below the necessary quantitative thresholds. Those operating segments primarily include steam revenue, appliance repair services, non-utility real estate activities, revenues associated with processing solid waste into refuse-derived fuel, investments in rental housing projects that qualify for low-income housing tax credits and the operations of MEC until July 2020.
Xcel Energy had equity method investments of $219 million and $208 million as of Dec. 31, 2022 and 2021, respectively, included in the natural gas utility and all other segments.
Asset and capital expenditure information is not provided for Xcel Energy’s reportable segments. As an integrated electric and natural gas utility, Xcel Energy operates significant assets that are not dedicated to a specific business segment.
Reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations, which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.
Certain costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators across each segment. In addition, a general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.
78
Xcel Energy’s segment information:
| (Millions of Dollars) | 2022 | 2021 | 2020 | |||||||||||||||||
| Regulated Electric | ||||||||||||||||||||
| Operating revenues — external | $ | 12,123 | $ | 11,205 | $ | 9,802 | ||||||||||||||
| Intersegment revenue | 2 | 2 | 2 | |||||||||||||||||
| Total revenues | $ | 12,125 | $ | 11,207 | $ | 9,804 | ||||||||||||||
| Depreciation and amortization | 2,122 | 1,855 | 1,673 | |||||||||||||||||
| Interest charges and financing costs | 636 | 568 | 534 | |||||||||||||||||
| Income tax (benefit) expense | (162) | (96) | 1 | |||||||||||||||||
| Net income | 1,631 | 1,478 | 1,407 | |||||||||||||||||
| Regulated Natural Gas | ||||||||||||||||||||
| Operating revenues — external | $ | 3,080 | $ | 2,132 | $ | 1,636 | ||||||||||||||
| Intersegment revenue | 2 | 2 | 1 | |||||||||||||||||
| Total revenues | $ | 3,082 | $ | 2,134 | $ | 1,637 | ||||||||||||||
| Depreciation and amortization | 276 | 254 | 252 | |||||||||||||||||
| Interest charges and financing costs | 86 | 75 | 71 | |||||||||||||||||
| Income tax expense | 68 | 54 | 17 | |||||||||||||||||
| Net income | 264 | 231 | 190 | |||||||||||||||||
| All Other | ||||||||||||||||||||
| Total revenues | $ | 107 | $ | 94 | $ | 88 | ||||||||||||||
| Depreciation and amortization | 15 | 12 | 23 | |||||||||||||||||
| Interest charges and financing costs | 203 | 173 | 193 | |||||||||||||||||
| Income tax benefit | (41) | (28) | (24) | |||||||||||||||||
| Net loss | (159) | (112) | (124) | |||||||||||||||||
| Consolidated Total | ||||||||||||||||||||
| Total revenues | $ | 15,314 | $ | 13,435 | $ | 11,529 | ||||||||||||||
| Reconciling eliminations | (4) | (4) | (3) | |||||||||||||||||
| Total operating revenues | $ | 15,310 | $ | 13,431 | $ | 11,526 | ||||||||||||||
| Depreciation and amortization | 2,413 | 2,121 | 1,948 | |||||||||||||||||
| Interest charges and financing costs | 925 | 816 | 798 | |||||||||||||||||
| Income tax (benefit) expense | (135) | (70) | (6) | |||||||||||||||||
| Net income | 1,736 | 1,597 | 1,473 | |||||||||||||||||
ITEM 9 — CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE | ||
None.
ITEM 9A — CONTROLS AND PROCEDURES | ||
Disclosure Controls and Procedures
Xcel Energy 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 Xcel Energy’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and procedures, the CEO and CFO have concluded that Xcel Energy’s disclosure controls and procedures were effective.
Internal Control Over Financial Reporting
No changes in Xcel Energy’s internal control over financial reporting occurred during the most recent fiscal quarter ended Dec. 31, 2022 that materially affected, or are reasonably likely to materially affect, Xcel Energy’s internal control over financial reporting. Xcel Energy maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting. Xcel Energy 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, Xcel Energy conducted testing and monitoring of its internal control over financial reporting. Based on the control evaluation, testing and remediation performed, Xcel Energy 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 Xcel Energy’s Management Report on Internal Controls over Financial Reporting, which is contained in Item 8 herein.
ITEM 9B — OTHER INFORMATION | ||
None.
ITEM 9C — DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS | ||
Not applicable.
PART III
ITEM 10 — DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE | ||
Information required under this Item with respect to Directors and Corporate Governance is set forth in Xcel Energy Inc.’s Proxy Statement for its 2023 Annual Meeting of Shareholders, which is expected to occur on April 11, 2023, incorporated by reference. Information with respect to Executive Officers is included in Item 1 to this report.
ITEM 11 — EXECUTIVE COMPENSATION | ||
Information required under this Item is set forth in Xcel Energy Inc.’s Proxy Statement for its 2023 Annual Meeting of Shareholders, which is incorporated by reference.
ITEM 12 — SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS | ||
Information required under this Item is contained in Xcel Energy Inc.’s Proxy Statement for its 2023 Annual Meeting of Shareholders, which is incorporated by reference.
ITEM 13 — CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE | ||
Information required under this Item is contained in Xcel Energy Inc.’s Proxy Statement for its 2023 Annual Meeting of Shareholders, which is incorporated by reference.
79
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
| ITEM 15 — EXHIBIT AND FINANCIAL STATEMENT SCHEDULES | ||
| 1 | Consolidated Financial Statements | ||||||||||
| Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, 2022. | |||||||||||
| Report of Independent Registered Public Accounting Firm — Financial Statements and Internal Controls Over Financial Reporting | |||||||||||
| Consolidated Statements of Income — For each of the three years ended Dec. 31, 2022, 2021, and 2020. | |||||||||||
| Consolidated Statements of Comprehensive Income — For each of the three years ended Dec. 31, 2022, 2021, and 2020. | |||||||||||
| Consolidated Statements of Cash Flows — For each of the three years ended Dec. 31, 2022, 2021, and 2020. | |||||||||||
| Consolidated Balance Sheets — As of Dec. 31, 2022 and 2021. | |||||||||||
| Consolidated Statements of Common Stockholders’ Equity — For each of the three years ended Dec. 31, 2022, 2021, and 2020. | |||||||||||
| 2 | Schedule I — Condensed Financial Information of Registrant. | ||||||||||
| Schedule II — Valuation and Qualifying Accounts and Reserves for 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 | ||||||||||
| Xcel Energy Inc. | |||||||||||
| Exhibit Number | Description | Report or Registration Statement | Exhibit Reference | ||||||||
3.01* | Xcel Energy Inc. Form 8-K dated May 16, 2012 | 3.01 | |||||||||
3.02* | Xcel Energy Inc. Form 8-K dated April 3, 2020 | 3.01 | |||||||||
4.01* | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2019 | 4.01 | |||||||||
4.02* | Xcel Energy Inc. Form 8-K dated Dec. 14, 2000 | 4.01 | |||||||||
4.03* | Xcel Energy Inc. Form 8-K dated June 6, 2006 | 4.01 | |||||||||
4.04* | Xcel Energy Inc. Form 8-K dated Jan. 16, 2008 | 4.01 | |||||||||
4.05* | Xcel Energy Inc. Form 8-K dated Jan. 16, 2008 | 4.03 | |||||||||
4.06* | Xcel Energy Inc. Form 8-K dated Sept. 12, 2011 | 4.01 | |||||||||
4.07* | Xcel Energy Inc. Form 8-K dated June 1, 2015 | 4.01 | |||||||||
4.08* | Xcel Energy Inc. Form 8-K dated Dec. 1, 2016 | 4.01 | |||||||||
4.09* | Xcel Energy Inc. Form 8-K dated June 25, 2018 | 4.01 | |||||||||
4.10* | Supplemental Indenture No. 12, dated as of Nov. 7, 2019 by and between Xcel Energy Inc. and Computershare Trust Company, N.A. (as successor to Wells Fargo Bank, National Association), as Trustee, creating $500 million aggregate principal amount of 2.60% Senior Notes, Series due Dec 1. 2029 and $500 million aggregate principal amount of 3.50% Senior Notes, Series due Dec. 1, 2049 | Xcel Energy Inc. Form 8-K dated Nov. 7, 2019 | 4.01 | ||||||||
4.11* | Xcel Energy Inc. Form 8-K dated April 1, 2020 | 4.01 | |||||||||
4.12* | Xcel Energy Inc. Form 8-K dated Sept. 25, 2020 | 4.01 | |||||||||
4.13* | Xcel Energy Inc. Form 8-K dated Nov. 3, 2021 | 4.01 | |||||||||
80
4.14* | Xcel Energy Form 8-K dated May 6, 2022 | 4.01 | |||||||||
| Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 | 10.02 | ||||||||||
10.02*+ | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 | 10.05 | |||||||||
10.03*+ | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011 | 10.18 | |||||||||
10.04*+ | Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2016 | 10.01 | |||||||||
10.05*+ | Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2018 | 10.01 | |||||||||
10.06*+ | Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2020 | 10.02 | |||||||||
10.07*+ | Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2020 | 10.01 | |||||||||
10.08*+ | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 | 10.17 | |||||||||
10.09*+ | Xcel Energy Inc. Definitive Proxy Statement dated April 6, 2010 | Appendix A | |||||||||
10.10*+ | Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2013 | 10.01 | |||||||||
10.11*+ | Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2009 | 10.08 | |||||||||
10.12*+ | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 | 10.07 | |||||||||
10.13*+ | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011 | 10.17 | |||||||||
10.14*+ | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2013 | 10.22 | |||||||||
10.15*+ | Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2016 | 10.01 | |||||||||
10.16*+ | Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2017 | 10.1 | |||||||||
10.17*+ | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018 | 10.34 | |||||||||
10.18*+ | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018 | 10.35 | |||||||||
10.19*+ | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2019 | 10.32 | |||||||||
10.20*+ | Xcel Energy Inc. Definitive Proxy Statement dated April 5, 2011 | Appendix A | |||||||||
10.21*+ | Xcel Energy Inc. Form 8-K dated May 20, 2015 | 10.02 | |||||||||
10.22*+ | Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2021 | 10.01 | |||||||||
10.23*+ | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018 | 10.36 | |||||||||
10.24*+ | Xcel Energy Inc. Form U5B dated Nov. 16, 2000 | H-1 | |||||||||
| Xcel Energy Inc. Form 8-K dated Sept. 19, 2022 | 99.01 | ||||||||||
Xcel Energy Inc. Form 8-K dated Dec. 10, 2021 | 10.01 | ||||||||||
| NSP-Minnesota | |||||||||||
| Xcel Energy Inc. Form S-3 dated April 18, 2018 | 4(b)(3) | ||||||||||
| Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2017 | 4.11 | ||||||||||
| Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2017 | 4.12 | ||||||||||
| NSP-Minnesota Form 10-12G dated Oct. 5, 2000 | 4.51 | ||||||||||
| Xcel Energy Inc. Form S-3 dated April 18, 2018 | 4(b)(7) | ||||||||||
81
| NSP-Minnesota Form 10-12G dated Oct. 5, 2000 | 4.63 | ||||||||||
| NSP-Minnesota Form 8-K dated July 14, 2005 | 4.01 | ||||||||||
| NSP-Minnesota Form 8-K dated May 18, 2006 | 4.01 | ||||||||||
| NSP-Minnesota Form 8-K dated June 19, 2007 | 4.01 | ||||||||||
| NSP-Minnesota Form 8-K dated Nov. 16, 2009 | 4.01 | ||||||||||
| NSP-Minnesota Form 8-K dated Aug. 4, 2010 | 4.01 | ||||||||||
| NSP-Minnesota Form 8-K dated Aug. 13, 2012 | 4.01 | ||||||||||
| NSP-Minnesota Form 8-K dated May 20, 2013 | 4.01 | ||||||||||
| NSP-Minnesota Form 8-K dated May 13, 2014 | 4.01 | ||||||||||
| NSP-Minnesota Form 8-K dated Aug. 11, 2015 | 4.01 | ||||||||||
| NSP-Minnesota Form 8-K dated May 31, 2016 | 4.01 | ||||||||||
| NSP-Minnesota Form 8-K dated Sept. 13, 2017 | 4.01 | ||||||||||
| NSP-Minnesota Form 8-K dated Sept. 10, 2019 | 4.01 | ||||||||||
| NSP-Minnesota 8-K dated June 15, 2020 | 4.01 | ||||||||||
Supplemental Indenture, dated as of March 1, 2021, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating $425 million principal amount of 2.25% First Mortgage Bonds, Series due April 1, 2031 and $425 million principal amount of 3.20% First Mortgage Bonds, Series due April 1, 2052 | NSP-Minnesota 8-K dated March 30, 2021 | 4.01 | |||||||||
4.35* | NSP-Minnesota 8-K dated May 9, 2022 | 4.01 | |||||||||
| NSP-Wisconsin Form S-4 dated Jan. 21, 2004 | 10.01 | ||||||||||
| Xcel Energy Inc. Form 8-K dated Sept. 19, 2022 | 99.02 | ||||||||||
| NSP-Wisconsin | |||||||||||
| Xcel Energy Inc. Form S-3 dated April 18, 2018 | 4(c)(3) | ||||||||||
| NSP-Wisconsin Form 8-K dated Sept. 25, 2000 | 4.01 | ||||||||||
Supplemental Trust Indenture, dated as of Sept. 1, 2008, by and between NSP-Wisconsin 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 6.375% First Mortgage Bonds, Series due Sept. 1, 2038 | NSP-Wisconsin Form 8-K dated Sept. 3, 2008 | 4.01 | |||||||||
Supplemental Trust Indenture, dated as of Oct. 1, 2012, by and between NSP-Wisconsin and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $100 million aggregate principal amount of 3.70% First Mortgage Bonds, Series due Oct. 1, 2042 | NSP-Wisconsin Form 8-K dated Oct. 10, 2012 | 4.01 | |||||||||
| NSP-Wisconsin Form 8-K dated June 23, 2014 | 4.01 | ||||||||||
| NSP-Wisconsin Form 8-K dated Dec. 4, 2017 | 4.01 | ||||||||||
| NSP-Wisconsin Form 8-K dated Sept. 12, 2018 | 4.01 | ||||||||||
82
83
| SPS Form 8-K dated Feb. 25, 1999 | 99.2 | ||||||||||
| Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2003 | 4.04 | ||||||||||
| SPS Form 8-K dated Oct. 3, 2006 | 4.01 | ||||||||||
| SPS Form 8-K dated Aug. 10, 2011 | 4.01 | ||||||||||
| SPS Form 8-K dated Aug. 10, 2011 | 4.02 | ||||||||||
| SPS Form 8-K dated June 9, 2014 | 4.02 | ||||||||||
| SPS Form 8-K dated Aug. 12, 2016 | 4.02 | ||||||||||
| SPS Form 8-K dated Aug 9. 2017 | 4.02 | ||||||||||
| SPS Form 8-K dated Nov. 5, 2018 | 4.02 | ||||||||||
| SPS Form 8-K dated June 18, 2019 | 4.02 | ||||||||||
| SPS Form 8-K dated May 18, 2020 | 4.02 | ||||||||||
4.73* | SPS Form 8-K dated May 31, 2022 | 4.02 | |||||||||
| Xcel Energy Inc. Form 8-K dated Sept. 19, 2022 | 99.04 | ||||||||||
| Xcel Energy Inc. | |||||||||||
| 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) | ||||||||||
84
SCHEDULE I
XCEL ENERGY INC.
CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(amounts in millions, except per share data)
| Year Ended Dec. 31 | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| Income | |||||||||||||||||
| Equity earnings of subsidiaries | $ | 1,905 | $ | 1,744 | $ | 1,646 | |||||||||||
| Total income | 1,905 | 1,744 | 1,646 | ||||||||||||||
| Expenses and other deductions | |||||||||||||||||
| Operating expenses | 19 | 21 | 43 | ||||||||||||||
| Other (income) expenses | (2) | 3 | (4) | ||||||||||||||
| Interest charges and financing costs | 206 | 173 | 198 | ||||||||||||||
| Total expenses and other deductions | 223 | 197 | 237 | ||||||||||||||
| Income before income taxes | 1,682 | 1,547 | 1,409 | ||||||||||||||
| Income tax benefit | (54) | (50) | (64) | ||||||||||||||
| Net income | $ | 1,736 | $ | 1,597 | $ | 1,473 | |||||||||||
| Other Comprehensive Income | |||||||||||||||||
Pension and retiree medical benefits, net of tax of $ 1, $1 and $1, respectively | $ | 9 | $ | 8 | $ | 5 | |||||||||||
Derivative instruments, net of tax of $3, $(1) and $(7), respectively | 21 | 10 | (5) | ||||||||||||||
| Other comprehensive income | 30 | 18 | — | ||||||||||||||
| Comprehensive income | $ | 1,766 | $ | 1,615 | $ | 1,473 | |||||||||||
| Weighted average common shares outstanding: | |||||||||||||||||
| Basic | 547 | 539 | 527 | ||||||||||||||
| Diluted | 547 | 540 | 528 | ||||||||||||||
| Earnings per average common share: | |||||||||||||||||
| Basic | $ | 3.18 | $ | 2.96 | $ | 2.79 | |||||||||||
| Diluted | 3.17 | 2.96 | 2.79 | ||||||||||||||
| See Notes to Condensed Financial Statements | |||||||||||||||||
XCEL ENERGY INC.
CONDENSED STATEMENTS OF CASH FLOWS
(amounts in millions)
| Year Ended Dec. 31 | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| Operating activities | |||||||||||||||||
| Net cash provided by operating activities | $ | 1,340 | $ | 1,147 | $ | 2,377 | |||||||||||
| Investing activities | |||||||||||||||||
| Capital contributions to subsidiaries | (921) | (1,661) | (2,553) | ||||||||||||||
| Net return (investments) in the utility money pool | — | 57 | (18) | ||||||||||||||
| Other, net | — | — | (1) | ||||||||||||||
| Net cash used in investing activities | (921) | (1,604) | (2,572) | ||||||||||||||
| Financing activities | |||||||||||||||||
| Proceeds (repayment of) from short-term borrowings, net | (407) | 638 | (500) | ||||||||||||||
| Proceeds from issuance of long-term debt | 694 | 791 | 1,089 | ||||||||||||||
| Repayment of long-term debt | — | (400) | (300) | ||||||||||||||
| Proceeds from issuance of common stock | 322 | 366 | 727 | ||||||||||||||
| Repurchase of common stock | — | — | (4) | ||||||||||||||
| Dividends paid | (1,012) | (935) | (856) | ||||||||||||||
| Other | (16) | (16) | (17) | ||||||||||||||
| Net cash provided by financing activities | (419) | 444 | 139 | ||||||||||||||
| Net change in cash, cash equivalents, and restricted cash | — | (13) | (56) | ||||||||||||||
| Cash, cash equivalents and restricted cash at beginning of period | 1 | 14 | 70 | ||||||||||||||
| Cash, cash equivalents and restricted cash at end of period | $ | 1 | $ | 1 | $ | 14 | |||||||||||
| See Notes to Condensed Financial Statements | |||||||||||||||||
XCEL ENERGY INC.
CONDENSED BALANCE SHEETS
(amounts in millions)
| Dec. 31 | ||||||||||||||
| 2022 | 2021 | |||||||||||||
| Assets | ||||||||||||||
| Cash and cash equivalents | $ | 1 | $ | 1 | ||||||||||
| Accounts receivable from subsidiaries | 443 | 430 | ||||||||||||
| Derivative instruments | 1 | — | ||||||||||||
| Other current assets | 7 | 6 | ||||||||||||
| Total current assets | 452 | 437 | ||||||||||||
| Investment in subsidiaries | 22,597 | 21,167 | ||||||||||||
| Other assets | (7) | 71 | ||||||||||||
| Total other assets | 22,590 | 21,238 | ||||||||||||
| Total assets | $ | 23,042 | $ | 21,675 | ||||||||||
| Liabilities and Equity | ||||||||||||||
| Current portion of long-term debt | 500 | — | ||||||||||||
| Dividends payable | 268 | 249 | ||||||||||||
| Short-term debt | 231 | 638 | ||||||||||||
| Other current liabilities | 17 | 29 | ||||||||||||
| Total current liabilities | 1,016 | 916 | ||||||||||||
| Other liabilities | 13 | 10 | ||||||||||||
| Total other liabilities | 13 | 10 | ||||||||||||
| Commitments and contingencies | ||||||||||||||
| Capitalization | ||||||||||||||
| Long-term debt | 5,338 | 5,137 | ||||||||||||
| Common stockholders' equity | 16,675 | 15,612 | ||||||||||||
| Total capitalization | 22,013 | 20,749 | ||||||||||||
| Total liabilities and equity | $ | 23,042 | $ | 21,675 | ||||||||||
| See Notes to Condensed Financial Statements | ||||||||||||||
Notes to Condensed Financial Statements
Incorporated by reference are Xcel Energy’s consolidated statements of common stockholders’ equity and other comprehensive income in Part II, Item 8.
Basis of Presentation — The condensed financial information of Xcel Energy Inc. is presented to comply with Rule 12-04 of Regulation S-X. Xcel Energy Inc.’s investments in subsidiaries are presented under the equity method of accounting. Under this method, the assets and liabilities of subsidiaries are not consolidated. The investments in net assets of the subsidiaries are recorded in the balance sheets. The income from operations of the subsidiaries is reported on a net basis as equity in income of subsidiaries.
As a holding company with no business operations, Xcel Energy Inc.’s assets consist primarily of investments in its utility subsidiaries. Xcel Energy Inc.’s material cash inflows are only from dividends and other payments received from its utility subsidiaries and the proceeds raised from the sale of debt and equity securities. The ability of its utility subsidiaries to make dividend and other payments is subject to the availability of funds after taking into account their respective funding requirements, the terms of their respective indebtedness, the regulations of the FERC under the Federal Power Act, and applicable state laws. Management does not expect maintaining these requirements to have an impact on Xcel Energy Inc.’s ability to pay dividends at the current level in the foreseeable future. Each of its utility subsidiaries, however, is legally distinct and has no obligation, contingent or otherwise, to make funds available to Xcel Energy Inc.
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Guarantees and Indemnifications
Xcel Energy Inc. provides guarantees and bond indemnities under specified agreements or transactions, which guarantee payment or performance. Xcel Energy Inc.’s exposure is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. limit the exposure to a maximum stated amount. As of Dec. 31, 2022 and 2021, Xcel Energy Inc. had no assets held as collateral related to guarantees, bond indemnities and indemnification agreements.
Guarantees and bond indemnities issued and outstanding as of Dec. 31, 2022:
| (Millions of Dollars) | Guarantor | Guarantee Amount | Current Exposure | Triggering Event | ||||||||||||||||||||||
Guarantee of loan for Hiawatha Collegiate High School (a) | Xcel Energy Inc. | $ | 1 | — | (b) | |||||||||||||||||||||
Guarantee of Capital Services purchase contract for solar generating equipment. (c) | Xcel Energy Inc. | 98 | (d) | (b) | ||||||||||||||||||||||
Guarantee performance and payment of surety bonds for Xcel Energy Inc.’s utility subsidiaries (e) | Xcel Energy Inc. | 61 | (f) | (g) | ||||||||||||||||||||||
(a)The guarantee expires the earlier of 2024 or full repayment of the loan.
(b)Nonperformance and/or nonpayment.
(c)The guarantee expires the earlier of termination or payment of all obligations under the purchase contract.
(d)Given that the manufacturing of solar generating equipment has not yet commenced, related exposure to the payment obligations of Capital Services at Dec. 31, 2022 is immaterial.
(e)The surety bonds primarily relate to workers compensation benefits and utility projects. The workers compensation bonds are renewed annually and the project based bonds expire in conjunction with the completion of the related projects.
(f)Due to the magnitude of projects associated with the surety bonds, the total current exposure of this indemnification cannot be determined. Xcel Energy Inc. believes the exposure to be significantly less than the total amount of the outstanding bonds.
(g)Per the indemnity agreement between Xcel Energy Inc. and the various surety companies, surety companies have the discretion to demand that collateral be posted.
Indemnification Agreements
Xcel Energy Inc. provides indemnifications through contracts entered into in the normal course of business. Indemnifications are primarily against adverse litigation outcomes in connection with underwriting agreements, breaches of representations and warranties, including corporate existence, transaction authorization and certain income tax matters. Obligations under these agreements may be limited in terms of duration or amount. Maximum future payments under these indemnifications cannot be reasonably estimated as the dollar amounts are often not explicitly stated.
Related Party Transactions — Xcel Energy Inc. presents related party receivables net of payables. Accounts receivable net of payables with affiliates at Dec. 31:
| (Millions of Dollars) | 2022 | 2021 | ||||||||||||
| NSP-Minnesota | $ | 82 | $ | 104 | ||||||||||
| NSP-Wisconsin | 17 | 25 | ||||||||||||
| PSCo | 111 | 91 | ||||||||||||
| SPS | 61 | 58 | ||||||||||||
| Xcel Energy Services Inc. | 145 | 125 | ||||||||||||
| Other subsidiaries of Xcel Energy Inc. | 27 | 27 | ||||||||||||
| $ | 443 | $ | 430 | |||||||||||
Dividends — Cash dividends paid to Xcel Energy Inc. by its subsidiaries were $1,503 million, $1,344 million and $2,527 million for the years ended Dec. 31, 2022, 2021 and 2020, respectively. These cash receipts are included in operating cash flows of the condensed statements of cash flows.
Money Pool — FERC approval was received to establish a utility money pool arrangement with the utility subsidiaries, subject to receipt of required state regulatory approvals. The utility money pool 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 lending for Xcel Energy Inc.:
| (Amounts in Millions, Except Interest Rates) | Three Months Ended Dec. 31, 2022 | |||||||
| Loan outstanding at period end | $ | — | ||||||
| Average loan outstanding | 1 | |||||||
| Maximum loan outstanding | 50 | |||||||
| Weighted average interest rate, computed on a daily basis | 0.01 | % | ||||||
| Weighted average interest rate at end of period | N/A | |||||||
| Money pool interest income | $ | — | ||||||
| (Amounts in Millions, Except Interest Rates) | Year Ended Dec. 31, 2022 | Year Ended Dec. 31, 2021 | Year Ended Dec. 31, 2020 | |||||||||||||||||
| Loan outstanding at period end | $ | — | $ | — | $ | 57 | ||||||||||||||
| Average loan outstanding | 10 | 16 | 104 | |||||||||||||||||
| Maximum loan outstanding | 204 | 439 | 350 | |||||||||||||||||
| Weighted average interest rate, computed on a daily basis | 0.73 | % | 0.08 | % | 0.60 | % | ||||||||||||||
| Weighted average interest rate at end of period | N/A | N/A | 0.07 | |||||||||||||||||
| Money pool interest income | $ | — | $ | — | $ | 1 | ||||||||||||||
See notes to the consolidated financial statements in Part II, Item 8.
SCHEDULE II
Xcel Energy Inc. and Subsidiaries Valuation and Qualifying Accounts Years Ended Dec. 31
| Allowance for bad debts | NOL and tax credit valuation allowances | ||||||||||||||||||||||||||||||||||||||||
| (Millions of Dollars) | 2022 | 2021 | 2020 | 2022 | 2021 | 2020 | |||||||||||||||||||||||||||||||||||
| Balance at Jan. 1 | $ | 106 | $ | 79 | $ | 55 | $ | 64 | $ | 64 | $ | 67 | |||||||||||||||||||||||||||||
| Additions charged to costs and expenses | 73 | 60 | 60 | 6 | 5 | 6 | |||||||||||||||||||||||||||||||||||
| Additions charged to other accounts | 26 | (a) | 14 | (a) | 12 | (a) | — | — | — | ||||||||||||||||||||||||||||||||
| Deductions from reserves | (83) | (b) | (47) | (b) | (48) | (b) | (8) | (c) | (5) | (c) | (9) | (d) | |||||||||||||||||||||||||||||
| Balance at Dec. 31 | $ | 122 | $ | 106 | $ | 79 | $ | 62 | $ | 64 | $ | 64 | |||||||||||||||||||||||||||||
(a)Recovery of amounts previously written-off.
(b)Deductions related primarily to bad debt write-offs.
(c)Primarily reductions to valuation allowances due to additional NOLs and tax credits forecasted to be used prior to expiration.
(d)Primarily the reduction of valuation allowances for North Dakota ITC, net of federal income tax benefit, that is offset to a regulatory liability forecasted to be used prior to expiration along with valuation allowances that expired.
ITEM 16 — FORM 10-K SUMMARY | ||
None.
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Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned thereunto duly authorized.
| XCEL ENERGY INC. | ||||||||
| Feb. 23, 2023 | By: | /s/ BRIAN J. VAN ABEL | ||||||
| Brian J. Van Abel | ||||||||
| Executive Vice President, Chief Financial Officer | ||||||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities on the date indicated above.
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