10-K

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, 2023 or

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____ to _____

001-03280

(Commission File Number)

Public Service Company of Colorado

(Exact name of registrant as specified in its charter)

Colorado			84-0296600
(State or Other Jurisdiction of Incorporation or Organization)			(IRS Employer Identification No.)
1800 Larimer, Suite 1100	Denver	Colorado	80202
(Address of Principal Executive Offices)			(Zip Code)

303	571-7511
(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
N/A	N/A	N/A

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 Feb. 21, 2024, 100 shares of common stock, par value $0.01 per share, were outstanding, all of which were held by Xcel Energy Inc., a Minnesota corporation.

DOCUMENTS INCORPORATED BY REFERENCE

The information required by Item 14 of Form 10-K is set forth under the heading “Independent Registered Public Accounting Firm – Audit and Non-Audit Fees” in Xcel Energy Inc.’s definitive Proxy Statement for the 2024 Annual Meeting of Shareholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 9, 2024. Such information set forth under such heading is incorporated herein by this reference hereto.

Public Service Company of Colorado meets the conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format permitted by General Instruction I(2).

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TABLE OF CONTENTS

PART I
Item 1 —	Business	3
Item 1A —	Risk Factors	8
Item 1B —	Unresolved Staff Comments	14
Item 1C —	Cybersecurity	14
Item 2 —	Properties	15
Item 3 —	Legal Proceedings	16
Item 4 —	Mine Safety Disclosures	16
PART II
Item 5 —	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	16
Item 6 —	[Reserved]	16
Item 7 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16
Item 7A —	Quantitative and Qualitative Disclosures About Market Risk	20
Item 8 —	Financial Statements and Supplementary Data	21
Item 9 —	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	48
Item 9A —	Controls and Procedures	48
Item 9B —	Other Information	49
Item 9C —	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	49
PART III
Item 10 —	Directors, Executive Officers and Corporate Governance	49
Item 11 —	Executive Compensation	49
Item 12 —	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	49
Item 13 —	Certain Relationships and Related Transactions, and Director Independence	49
Item 14 —	Principal Accountant Fees and Services	49
PART IV
Item 15 —	Exhibit and Financial Statement Schedules	49
Item 16 —	Form 10-K Summary	51
Signatures		52

This Form 10-K is filed by PSCo. PSCo is a wholly owned subsidiary of Xcel Energy Inc. Additional information on Xcel Energy is available in various filings with the SEC. This report should be read in its entirety.

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PART I

ITEM 1 — BUSINESS

Definitions of Abbreviations

Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
NSP-Minnesota	Northern States Power Company, a Minnesota corporation
NSP-Wisconsin	Northern States Power Company, a Wisconsin corporation
PSCo	Public Service Company of Colorado
SPS	Southwestern Public Service Company
Utility subsidiaries	NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
WYCO	WYCO Development, LLC
Xcel Energy	Xcel Energy Inc. and its subsidiaries

Federal and State Regulatory Agencies
CPUC	Colorado Public Utilities Commission
DOT	United States Department of Transportation
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
IRS	Internal Revenue Service
NERC	North American Electric Reliability Corporation
PHMSA	Pipeline and Hazardous Materials Safety Administration
SEC	Securities and Exchange Commission

Electric, Purchased Gas and Resource Adjustment Clauses
DSM	Demand side management
ECA	Retail electric commodity adjustment
GCA	Gas cost adjustment
PSIA	Pipeline system integrity adjustment
RES	Renewable energy standard

Other
AFUDC	Allowance for funds used during construction
ALJ	Administrative Law Judge
ARO	Asset retirement obligation
ARRR	Application for Rehearing, Reargument, or Reconsideration
ASC	Financial Accounting Standards Board Accounting Standards Codification
C&I	Commercial and Industrial
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
CEO	Chief executive officer
CFO	Chief financial officer
CIG	Colorado Interstate Gas Company, LLC
CWIP	Construction work in progress

ETR	Effective tax rate
GAAP	Generally accepted accounting principles
GHG	Greenhouse gas
IPP	Independent power producing entity
ISO	Independent System Operator
ITC	Investment tax credit
MGP	Manufactured gas plant
Native load	Customer demand of retail and wholesale customers whereby a utility has an obligation to serve under statute or long-term contract
NAV	Net asset value
NOL	Net operating loss
O&M	Operating and maintenance
PIM	Performance Incentive Mechanism
PFAS	Per- and PolyFluoroAlkyl Substances
Post-65	Post-Medicare
PPA	Purchased power agreement
Pre-65	Pre-Medicare
PTC	Production tax credit
REC	Renewable energy credit
ROE	Return on equity
ROU	Right-of-use
RTO	Regional Transmission Organization
S&P	Standard & Poor’s Global Ratings
SERP	Supplemental executive retirement plan
SPP	Southwest Power Pool, Inc.
TCJA	2017 federal tax reform enacted as Public Law No: 115-97, commonly referred to as the Tax Cuts and Jobs Act
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

PSCo is a wholly owned subsidiary of Xcel Energy Inc., and Xcel Energy’s website address is www.xcelenergy.com. Xcel Energy makes available, free of charge through its website, 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.

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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 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, 2023 (including risk factors listed from time to time by PSCo 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; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices and fuel costs; qualified employee workforce and third-party contractor factors; violations of our Codes of Conduct; our ability to recover costs; 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 PSCo 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; 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; cybersecurity 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 and wildfire damages in excess of liability insurance coverage; 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.

Company Overview

Electric customers	1.6 million		PSCo was incorporated in 1924 under the laws of Colorado. PSCo conducts business in Colorado and generates, purchases, transmits, distributes and sells electricity in addition to purchasing, transporting, distributing and selling natural gas to retail customers and transporting customer-owned natural gas.
Natural gas customers	1.5 million
Total assets	$24.6 billion
Rate Base (estimated)	$16.9 billion
GAAP ROE	7.32%
Electric generating capacity	6,203 MW
Gas storage capacity	32.1 Bcf
Electric transmission lines (conductor miles)	25,000 miles
Electric distribution lines (conductor miles)	80,000 miles
Natural gas transmission lines	2,000 miles
Natural gas distribution lines	23,000 miles

Electric Operations

Electric operations consist of energy supply, generation, transmission and distribution activities. PSCo had electric sales volume of 33,811 (millions of KWh), 1.6 million customers and electric revenues of $3,731 million for 2023.

Electric Operations (percentage of total)	Sales Volume		Number of Customers		Revenues
Residential	28	%	86	%	35	%
C&I	54		11		49
Other	18		3		17

Retail Sales/Revenue Statistics (a)

	2023			2022
KWH sales per retail customer	17,781			18,456
Revenue per retail customer	$	2,006		$	2,074
Residential revenue per KWh	13.69		¢	13.62		¢
C&I revenue per KWh	9.90		¢	9.86		¢
Total retail revenue per KWh	11.28		¢	11.24		¢

(a)See Note 6 to the consolidated financial statements for further information.

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Owned and Purchased Energy Generation — 2023

Electric Energy Sources

Total electric energy generation by source for the year ended Dec. 31:

Carbon–Free

PSCo’s carbon–free energy portfolio includes wind, hydroelectric and solar power from both owned generating 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

Wind capacity is shown as net maximum capacity. Net maximum capacity is attainable only when wind conditions are sufficiently available

Owned — Owned and operated wind farms with corresponding capacity:

2023		2022
Wind Farms	Capacity (MW)	Wind Farms	Capacity (MW)
2	1,059	2	1,059

PPAs — Number of PPAs with capacity range:

2023		2022
PPAs	Range (MW)	PPAs	Range (MW)
17	23 — 301	17	23 — 301

Current contracted wind capacity for PPAs was 3,026 MW and 3,023 MW in 2023 and 2022, respectively.

In 2023, the average cost of wind energy was $7 per MWh for owned generation and $42 per MWh under existing PPAs. In 2022, the average cost of wind energy was $11 per MWh for owned generation and $38 per MWh under existing PPAs.

PSCo anticipates development of approximately 1,850 MW of wind generation resources (1,550 MW Company Owned, 300 MW as PPAs), as part of the Colorado Resource Plan.

Solar

PPAs — Solar PPAs capacity by type:

Type	Capacity (MW)
Distributed Generation	887
Utility-Scale	1,530	(a)
Total	2,417

(a)Includes battery storage capacity of 225 MW.

The average cost of solar energy under existing PPAs was $34 per MWh and $69 per MWh in 2023 and 2022, respectively.

PSCo anticipates development of approximately 1,700 MW of solar generation resources (650 MW Company Owned, 1,050 MW as PPAs) as part of the Colorado Resource Plan.

Other

PSCo’s other carbon-free energy portfolio includes hydro from owned generating facilities.

PSCo anticipates development of approximately 1,850 MW of storage capacity (400 MW Company Owned, 1,450 MW as PPAs) as part of the Colorado Resource Plan.

See Item 2 — Properties for further information.

Fossil Fuel

PSCo’s fossil fuel energy portfolio includes coal and natural gas power from both owned generating facilities and PPAs.

See Item 2 — Properties for further information.

Coal

PSCo owns and operates coal units with approximately 1,650 MW of total 2023 net summer dependable capacity, which provided 26% of the PSCo energy mix in 2023.

Approved early coal plant retirements:

Year	Plant Unit	Capacity (MW)
2025	Comanche 2	330
2025	Craig 1	42	(a)
2025	Pawnee (b)	505
2027	Hayden 2	98	(a)
2028	Hayden 1	135	(a)
2028	Craig 2	40	(a)
2030	Comanche 3	500	(a)

(a)Based on PSCo’s ownership interest.

(b)Reflects conversion from coal to natural gas.

Coal Fuel Cost — Delivered cost per MMBtu of coal consumed for owned electric generation and the percentage of total fuel requirements (coal and natural gas):

	Coal
	Cost		Percent
2023	$	1.57	54	%
2022	1.48		55

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Natural Gas

PSCo has seven natural gas plants with approximately 3,300 MW of total 2023 net summer dependable capacity, which provided 32% of the PSCo energy mix in 2023.

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 (coal and natural gas):

	Natural Gas
	Cost		Percent
2023	$	3.06	46	%
2022	7.09		45

PSCo anticipates development of approximately 650 MW of Company Owned natural gas generation, as part of the Colorado Resource Plan to help ensure resiliency and reliability.

Capacity and Demand

Uninterrupted system peak demand and occurrence date:

System Peak Demand (MW)
2023		2022
6,909	July 24	6,821	Sept. 6

Transmission

Transmission lines deliver electricity over long distances from power sources to 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. PSCo owns more than 24,000 conductor miles of transmission lines across its service territory.

PSCo plans to build approximately 550 additional conductor miles of transmission lines related to the Colorado Power Pathway project estimated to be complete in 2027.

See Item 2 - Properties for further information.

Distribution

Distribution lines allow electricity to travel at lower voltages from substations directly to customers. PSCo has a vast distribution network, owning and operating approximately 80,000 conductor miles of distribution lines across our service territory.

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. PSCo had natural gas deliveries of 289,163 (thousands of MMBtu), 1.5 million customers and natural gas revenues of $1,734 million for 2023.

Natural Gas (percentage of total)	Deliveries		Number of Customers		Revenues
Residential	35	%	92	%	64	%
C&I	16		7		26
Transportation and other	49		1		10

Sales/Revenue Statistics (a)

	2023		2022
MMBtu sales per retail customer	101		103
Revenue per retail customer	$	1,061	$	1,147
Residential revenue per MMBtu	10.97		11.14
C&I revenue per MMBtu	9.66		10.40
Transportation and other revenue per MMBtu	0.95		1.07

(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:

2023		2022
MMBtu	Date	MMBtu	Date
2,190,155	Jan. 30	2,243,552	Dec. 22

Natural Gas Supply and Cost

PSCo seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio, which increases flexibility, decreases interruption, financial risks and economical rates. In addition, PSCo conducts natural gas price hedging activities approved by its state’s commissions.

Average delivered cost per MMBtu of natural gas for regulated retail distribution:

2023		2022
$	4.91	$	6.33

PSCo has 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

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, PSCo’s operations have historically generated less revenues and income when weather conditions are warmer in the winter and cooler in the summer. Decoupling mechanisms mitigate the impacts of weather in certain jurisdictions. PSCo’s electric decoupling mechanism expired in September.

Competition

PSCo is subject to public policies that promote competition and development of energy markets. PSCo’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.

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Customers have the opportunity to supply their own power with distributed generation including solar generation and can currently avoid paying for most of the fixed production, transmission and distribution costs incurred to serve them.

Colorado has incentives for the development of rooftop solar, community solar gardens and other distributed energy resources. Distributed generating resources are potential competitors to PSCo’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. PSCo’s wholesale customers can purchase energy from competing generation resources and transmission services from other service providers 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.

PSCo has 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.

While facing these challenges, PSCo believes its 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 PSCo activities require registrations, permits, licenses, inspections and approvals from these agencies.

PSCo 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. PSCo has 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

Power Plant Greenhouse Gas Regulations — In May 2023, the EPA published proposed rules addressing control of CO2 emissions from the power sector. The rule proposed regulations for new natural gas generating units and emission guidelines for existing coal and certain natural gas generation. The proposed rules create subcategories of coal units based on planned retirement date and subcategories of natural gas combustion turbines and combined cycle units based on utilization. The CO2 control requirements vary by subcategory. Until final rules are issued, it is not certain what the impact will be on PSCo. PSCo 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 May 2023, the EPA published proposed rules to regulate legacy CCR surface impoundments at inactive facilities and previously exempt areas where CCR was placed directly on land at regulated CCR facilities under the CCR Rule for the first time. The proposed rule would subject these areas to the CCR Rule requirements, including groundwater monitoring, corrective action, closure, and post-closure care requirements, among other requirements, with several of the deadlines accelerated.

The EPA has committed to a May 2024 publication date for those new rules. It is also anticipated that the EPA may issue other CCR proposed rules in 2024 and 2025 that further expand the scope of the CCR Rule. Until final rules are issued, it is not certain what the impact will be on PSCo. PSCo. believes that the cost of these initiatives would be recoverable through rates based on prior state commission practices.

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. PSCo 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 CERCLA. In March 2023, the EPA published a proposed rule that would establish enforceable drinking water standards for certain PFAS chemicals.

Final rules are expected in 2024. Costs are uncertain until a final rule is published.

The proposed rules could result in new obligations for investigation and cleanup. PSCo is monitoring changes to state laws addressing PFAS. The impact of these proposed regulations is uncertain.

Effluent Limitation Guidelines

In March 2023, the EPA released a proposed rule under the Clean Water Act, setting forth proposed Effluent Limitations Guidelines and Standards for steam generating coal plants. This proposed rule establishes more stringent wastewater discharge standards for bottom ash transport water, flue-gas desulfurization wastewater, and combustion residuals leachate from steam electric power plants, particularly coal-fired power plants. The impact of these proposed regulations is uncertain until a final rule is published.

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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.

Employees

As of Dec. 31, 2023, PSCo had 2,352 full-time employees and ten part-time employees, of which 1,878 were covered under collective-bargaining agreements.

ITEM 1A — RISK FACTORS

Xcel Energy, which includes PSCo, is subject to a variety of risks, many of which are beyond our control. Risks that may adversely affect the business, financial condition, results of operations or cash flows are described below. Although the risks are organized by heading, and each risk is described separately, many of the risks are interrelated. These risks should be carefully considered together with the other information set forth in this report and future reports that Xcel Energy files with the SEC.

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

PSCo’s Board of Directors is responsible for the oversight of material risk and maintaining an effective risk monitoring process. Management and the Board of Directors have responsibility for overseeing the identification and mitigation of key risks.

PSCo 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. PSCo further mitigates inherent risks through formal risk committees and corporate functions such as internal audit, and internal controls over financial reporting and legal.

Management identifies and analyzes risks to determine materiality and other attributes such as timing, probability and controllability. Identification and risk analysis occurs formally through risk assessment conducted by senior management, the financial disclosure process, hazard risk procedures, internal audit and compliance with financial and operational controls. Management also identifies and analyzes risk through the business planning process, development of goals and establishment of key performance indicators, including identification of barriers to implementing our strategy. The business planning process also identifies likelihood and mitigating factors to prevent the assumption of inappropriate risk to meet goals.

Management communicates regularly with the Board of Directors and its sole stockholder regarding risk. Senior management presents and communicates a periodic risk assessment to the Board of Directors, providing information on the risks that management believes are material, including financial impact, timing, likelihood and mitigating factors. The Board of Directors regularly reviews management’s key risk assessments, which includes areas of existing and future macroeconomic, financial, operational, policy, environmental, safety and security risks.

The oversight, management and mitigation of risk is an integral and continuous part of the Board of Directors’ governance of PSCo. Processes are in place to confirm appropriate risk oversight, as well as identification and consideration of new risks.

Risks Associated with Our Business

Operational Risks

Our natural gas and electric generation/transmission and distribution operations involve numerous risks that may result in accidents and other operating risks and costs.

Our natural gas transmission and distribution activities include inherent hazards and operating risks, such as leaks, explosions, outages and mechanical problems. Our electric generation, transmission and distribution activities include inherent hazards and operating risks such as contact, fire and outages. These risks could result in loss of life, significant property damage, environmental pollution, impairment of our operations and substantial financial losses to employees, third-party contractors, customers or the public. We maintain insurance against most, but not all, of these risks and losses.

The occurrence of these events, if not fully covered by insurance, could have a material effect on our financial condition, results of operations and cash flows as well as potential loss of reputation.

Other uncertainties and risks inherent in operating and maintaining PSCo'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, avalanches, icing events, floods, high winds 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 utility investments are planned to be used for decades. Transmission and generation investments typically have long lead times and are planned well in advance of in-service dates and typically subject to long-term resource plans. These plans are based on numerous assumptions such as: sales growth, customer usage, commodity prices, economic activity, costs, regulatory mechanisms, customer behavior, available technology and public policy. Our long-term resource plan is dependent on our ability to obtain required approvals, develop necessary technical expertise, allocate and coordinate sufficient resources and adhere to budgets and timelines.

In addition, the long-term nature of both our planning processes and our asset lives are subject to risk. The 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. New data centers and crypto mining facilities could generate significant increase in demand. Higher electric demand may require us to adopt new technologies and make significant transmission and distribution investments including advanced grid infrastructure, which increases exposure to overall grid instability and technology obsolescence. Evolving stakeholder preference for lower emissions from generation sources and end-uses, like heating, may impact our resource mix and put pressure on our ability to recover capital investments in natural gas generation and delivery. Multiple states may not agree as to the appropriate resource mix, which may lead to costs to comply with one jurisdiction that are not recoverable across all jurisdictions served by the same assets.

We require inputs such as coal, natural gas and water. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate.

Our utility operations are highly dependent on suppliers to deliver components in accordance with short and long-term project schedules.

Our products contain components that are globally sourced from suppliers. A shortage of key components in which an alternative supplier is not identified could significantly impact operations and project plans for PSCo and our customers. Such impacts could include timing of projects and the potential for project cancellation. Failure to adhere to project budgets and timelines could adversely impact our results of operations, financial condition or cash flows.

We are subject to commodity risks and other risks associated with energy markets and energy production.

A significant increase in fuel costs could cause a decline in customer demand, adverse regulatory outcomes and an increase in bad debt expense which may have a material impact on our results of operations. Despite existing fuel cost recovery mechanisms, higher fuel costs could significantly impact our results of operations if costs are not recovered. Delays in the timing of the collection of fuel cost recoveries could impact our cash flows and liquidity.

A significant disruption in supply could cause us to seek alternatives 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 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, PSCo 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, PSCo cannot fully assure that its controls will be effective against all potential risks. If such programs and procedures are not effective, PSCo’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 and decisions related to strategic workforce planning. 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, adequately train replacement employees, transfer knowledge/expertise 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 could adversely impact our results of operations, financial condition or cash flows.

Our businesses have collective bargaining agreements with labor unions. Failure to renew or renegotiate these contracts could lead to labor disruptions, including strikes or boycotts. Such disruptions or any negotiated wage or benefit increases could have a material adverse impact to our results of operations, financial condition or cash flows.

National unionization efforts could affect our business, as an increase in unionized workers could challenge our operational efficiency and increase costs.

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 compliance with our Code of Conduct and are required to participate in annual training. Additionally, suppliers are subject to compliance with our Supplier Code of Conduct. PSCo does not tolerate discrimination, violations of our Code of Conduct or other unacceptable behaviors. However, it is not always possible to identify and deter misconduct by employees and other third-parties, which may result in governmental investigations, other actions or lawsuits. If such actions are taken against us we may suffer loss of reputation and such actions could have a material effect on our financial condition, results of operations and cash flows.

We are a wholly owned subsidiary of Xcel Energy Inc. Xcel Energy Inc. can exercise substantial control over our dividend policy and business and operations and may exercise that control in a manner that may be perceived to be adverse to our interests.

All of the members of our Board of Directors, as well as many of our executive officers, are officers of Xcel Energy Inc. Our Board of Directors makes determinations with respect to a number of significant corporate events, including the payment of our dividends.

We have historically paid quarterly dividends to Xcel Energy Inc. If Xcel Energy Inc.’s cash requirements increase, our Board of Directors could decide to increase the dividends we pay to Xcel Energy Inc. to help support Xcel Energy Inc.’s cash needs. This could adversely affect our liquidity. The most restrictive dividend limitation for PSCo is imposed by its credit facility, which limits the debt-to-total capitalization ratio.

See Note 5 to the consolidated financial statements for further information.

Financial Risks

Our profitability depends on our ability to recover costs and changes in regulation may impair our ability to recover costs from our customers.

We are subject to comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and the rates that we can charge customers.

The profitability of our operations is dependent on our ability to recover the costs of providing energy and utility services and earn a return on capital investment. Our rates are generally regulated and are based on an analysis of our costs incurred in a test year. We are subject to both future and historical test years depending upon the regulatory jurisdiction. Thus, the rates we are allowed to charge may or may not match our costs at any given time. Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital.

There can also be no assurance that our regulatory commissions will judge all our costs to be prudent, which could result in disallowances, or that the regulatory process will always result in rates that will produce full recovery.

Overall, management believes prudently incurred costs are recoverable given the existing regulatory framework. However, there may be changes in the regulatory environment that could impair our ability to recover costs historically collected from customers, or we could exceed caps on capital costs required by commissions and result in less than full recovery.

Changes in the long-term cost-effectiveness or to the operating conditions of our assets may result in early retirements of utility facilities. While regulation typically provides cost recovery for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs.

Higher than expected inflation or tariffs may increase costs of construction and operations. Also, rising fuel costs could increase the risk that we will not be able to fully recover our fuel costs from our customers.

Adverse regulatory rulings (including changes in recovery mechanisms) or the imposition of additional regulations could have an adverse impact on our results of operations and materially affect our ability to meet our financial obligations, including debt payments and the payment of dividends on common stock.

Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.

Our credit ratings are subject to change and our credit ratings may 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.

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Any credit ratings downgrade could lead to higher borrowing costs or lower proceeds from equity issuances. It could also impact our ability to access capital markets. Also, we may enter into contracts that require posting of collateral or settlement if credit ratings fall below investment grade.

We are subject to capital market and interest rate risks.

Utility operations require significant capital investment. As a result, we frequently need to access capital markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital market disruption and financial market distress could prevent us from issuing commercial paper, issuing new securities or cause us to issue securities with unfavorable terms and conditions, such as higher interest rates or lower proceeds from equity issuances. Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results. 

We are subject to credit risks.

Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in our cash flow and liquidity and an increase in bad debt expense. Credit risk is comprised of numerous factors including the price of products and services provided, the economy and unemployment rates.

Credit risk also includes the risk that counterparties that owe us money or product will become insolvent and may breach their obligations. Should the counterparties fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and incur losses.

We may have direct credit exposure in our short-term wholesale and commodity trading activity to financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties. We may also have some indirect credit exposure due to participation in organized markets, (e.g., SPP, Midcontinent Independent System Operator, Inc. and California ISO), in which any credit losses are socialized to all market participants.

We have additional indirect credit exposure to financial institutions from letters of credit provided as security by power suppliers under various purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below investment grade, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party could be in default under the contract.

As we are a subsidiary of Xcel Energy Inc., we may be negatively affected by events impacting the credit or liquidity of Xcel Energy Inc. and its affiliates.

If either S&P or Moody’s Investor Services were to downgrade Xcel Energy Inc.’s debt securities below investment grade, it would increase Xcel Energy Inc.’s cost of capital and restrict its access to the capital markets. This could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

As of Dec. 31, 2023, Xcel Energy Inc. and its utility subsidiaries had approximately $24.9 billion of long-term debt and $1.3 billion of short-term debt and current maturities. Xcel Energy Inc. provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries for specified agreements or transactions.

Xcel Energy also has other contingent liabilities resulting from various tax disputes and other matters. Xcel Energy Inc.’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. The majority of Xcel Energy Inc.’s guarantees limit its exposure to a maximum amount that is stated in the guarantees. 

As of Dec. 31, 2023, Xcel Energy had the following guarantees outstanding:

•$951 million for performance and payment of Capital Services, LLC contracts for wind and solar generating equipment, with immaterial exposure.

•$100 million for performance on tax credit sale agreements of its subsidiaries, with immaterial exposure.

•$75 million for performance and payment of surety bonds for the benefit of itself and its subsidiaries, with total exposure that cannot be estimated at this time.

If Xcel Energy Inc. were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund other contingent liabilities, it could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us, or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

Increasing costs of our defined benefit retirement plans and employee benefits may adversely affect our results of operations, financial condition or cash flows.

We have defined benefit pension and postretirement plans that cover most of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements of these plans. Estimates and assumptions may change. In addition, the Pension Protection Act sets the minimum funding requirements for defined benefit pension plans. Therefore, our funding requirements and contributions may change in the future. Also, the payout of a significant percentage of pension plan liabilities in a single year due to high numbers of retirements or employees leaving PSCo would trigger settlement accounting and could require PSCo to recognize incremental pension expense related to unrecognized plan losses in the year liabilities are paid. Changes in industry standards utilized in key assumptions (e.g., mortality tables) could have a significant impact on future obligations and benefit costs.

Increasing costs associated with health care plans may adversely affect our results of operations.

Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our results of operations, financial condition or cash flows. Health care legislation could also significantly impact our benefit programs and costs.

Federal tax law may significantly impact our business.

PSCo collects estimated federal, state and local tax payments through their regulated rates. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Tax depreciable lives and the value/availability of various tax credits or the timeliness of their utilization may impact the economics or selection of resources. If tax rates are increased, there could be timing delays before regulated rates provide for recovery of such tax increases in revenues. In addition, certain IRS tax policies such as tax normalization may impact our ability to economically deliver certain types of resources relative to market prices.

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Macroeconomic Risks

Economic conditions impact our business.

Our operations are affected by economic conditions, which correlates to customers/sales growth (decline). Economic conditions may be impacted by recessionary factors, rising interest rates and insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay their bills which could lead to additional bad debt expense.

PSCo faces competitive factors, which could have an adverse impact on our financial condition, results of operations and cash flows. Further, worldwide economic activity impacts the demand for basic commodities necessary for utility infrastructure, which may inhibit our ability to acquire sufficient supplies. We operate in a capital intensive industry and federal trade policy could significantly impact the cost of materials we use. There may be delays before these additional material costs can be recovered in rates.

The oil and gas industry represents our largest commercial and industrial customer base. Oil and natural gas prices are sensitive to market risk factors which may impact demand.

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 impact countries, communities, supply chains and markets. Uncertainty continues to exist regarding epidemics; the duration and magnitude of business restrictions including shutdowns (domestically and globally); the potential impact on the workforce including shortages of employees and third-party contractors due to quarantine policies, vaccination requirements or government restrictions; impacts on the transportation of goods, and the generalized impact on the economy.

We cannot ultimately predict whether an epidemic will have a material impact on our future liquidity, financial condition or results of operations. Nor can we predict the impact on the health of our employees, our supply chain or our ability to recover higher costs associated with managing an outbreak.

Operations could be impacted by war, terrorism or other events.

Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any disruption could impact operations or result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition, results of operations or cash flows. The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have incurred increased costs for security and capital expenditures in response to these risks. The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, insurance may have higher deductibles, higher premiums and more restrictive policy terms.

A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business, brand and reputation. Because our facilities are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility.

We also face the risks of possible loss of business due to significant events such as severe storms, temperature extremes, wildfires, widespread pandemic, generator or transmission facility outage, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or a workforce disruption.

In addition, major catastrophic events throughout the world may disrupt our business. While we have business continuity plans in place, our ability to recover may be prolonged due to the type and extent of the event. PSCo 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 cybersecurity incident or security breach could have a material effect on our business.

We operate in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including Company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors and other individuals.

Our generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets, as well as information processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cybersecurity 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 cybersecurity 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.

Cybersecurity incidents could harm our businesses by limiting our generation, transmission and distribution capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which would likely receive state and federal regulatory scrutiny and could expose us to liability.

Our generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cybersecurity 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.

Generative Artificial Intelligence, such as large language models like ChatGPT, present a range of challenges and potential risks as we consider impacts to the business. These challenges involve navigating the complexities of creating and deploying AI models that generate content autonomously. Data privacy, legal concerns, and security issues are all risks as this technology continues to be adopted.

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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 cybersecurity threats or subsequent related actions. Cybersecurity 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 cybersecurity 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 cybersecurity 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, cybersecurity 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 PSCo's electric and natural gas infrastructure.

Other potential risks associated with wildfires and other climate events 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 PSCo 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.

ITEM 1C — CYBERSECURITY

PSCo is a wholly owned subsidiary of Xcel Energy. As such, its cybersecurity processes are maintained by Xcel Energy management and governed by its Board of Directors.

As described in Item 1A – Risk Factors, Xcel Energy operates in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure, as such, our business is subject to the risk of interruption by cybersecurity incidents that range from attacks common to most industries, such as phishing and denial-of-service, to attacks from more sophisticated adversaries, including nation state actors, that target the critical infrastructure used in the operation of our business.

Xcel Energy has a security risk program in place to identify, assess, manage and report material risks from cybersecurity incidents. As a utility provider, Xcel Energy complies with reliability standards imposed by NERC, including critical infrastructure protection standards related to both cybersecurity and physical security. These standards imposed by NERC, in alignment with the NIST Cybersecurity Framework, are the basis for which Xcel Energy has designed the cybersecurity control framework within its security risk program.

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Annually, as part of Xcel Energy’s enterprise risk program, an integrated cybersecurity risk identification and assessment is completed across Xcel Energy’s business, including generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (including systems hosted by third parties) that could be affected by cybersecurity incidents. This analysis includes the impact, likelihood, timeframe and controllability of cybersecurity risks and is presented to the Board of Directors. Management monitors and reviews the results of this analysis, integrating them into the enterprise risk assessment processes and implements appropriate mitigating actions as needed.

Xcel Energy’s cybersecurity policies, standards, practices and readiness are regularly assessed by third-party consultants. These partners are engaged to perform independent penetration testing and other security related services to assist in the prevention, detection, monitoring, mitigation and remediation of cybersecurity incidents and risks. The results of these assessments are communicated to management and the Board of Directors by the Chief Security Officer.

Xcel Energy employs a comprehensive risk based approach to assess the magnitude and significance of a vendor’s risk to Xcel Energy. Certain third-party service providers are subject to vendor security risk assessments at the time of integration, contract execution/renewal, and upon detection of any increase in risk profile. Xcel Energy uses a variety of inputs in such risk assessments, including information supplied by providers and third parties (including information analysis centers that share daily threat intelligence and improve organizational agility associated with management of cybersecurity risks). In addition, Xcel Energy requires certain third-party service providers to meet appropriate security requirements, controls and responsibilities. Xcel Energy deploys periodic monitoring activities to assess compliance with our cybersecurity control framework and investigates security incidents that have impacted our third-party service providers as appropriate.

Management has assigned responsibility for the security risk program to the Chief Security Officer who has extensive experience in critical infrastructure protection, including multiple years of experience with the Department of Defense. The Chief Security Officer is informed about and monitors prevention, detection, mitigation and remediation efforts through a team of security professionals, many of whom are Certified Information Systems Security Professionals, Certified Information Security Managers or have received other cybersecurity certifications. The team has extensive experience selecting, deploying and operating cybersecurity technologies, initiatives and processes that aid in preventing, remediating and mitigating known and unknown cybersecurity threats.

The Chief Security Officer or members of management brief the Board on routine and regular cybersecurity risk and threat updates, typically on a quarterly basis. In the event of a significant threat or incident, management and the Chief Security Officer leverage Xcel Energy’s incident response processes to assess impacts and resolve incidents. When a significant cybersecurity incident occurs, management communicates with the Board of Directors and relevant committees.

The Board of Directors oversees the risks associated with cybersecurity and the physical security of our assets, with information security matters being discussed at each regular board meeting as well as at the ONES and Audit Committee meetings throughout the year.

While the ONES Committee has primary committee responsibility for cybersecurity due to the operational issues involved, the Board of Directors has determined that the topic is of sufficient importance to warrant this comprehensive oversight approach. Augmenting such oversight efforts, the Board conducts drills to practice its response in a possible emergency situation to ensure it is well prepared and positioned to perform in a possible crisis.

Cybersecurity risks are a part of Xcel Energy’s normal course of business. To date, no cybersecurity incident or attack has had a material impact on our business or results of operations. As of Feb. 21, 2024 there have been no material cybersecurity incidents to report.

ITEM 2 — PROPERTIES

Virtually all of the utility plant property of PSCo is subject to the lien of its first mortgage bond indenture.

Station, Location and Unit at Dec. 31, 2023	Fuel	Installed	MW (a)
Steam:
Comanche-Pueblo, CO
Unit 2	Coal	1975	330
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	1,022
Manchief, CO, 2 Units .	Natural Gas	2000	250
Rocky Mountain-Keenesburg, CO, 3 Units	Natural Gas	2004	592
Various locations, 8 Units	Natural Gas	Various	247
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	(e)
Cheyenne Ridge, CO, 229 units	Wind	2020	477	(e)
		Total	6,203

(a)Summer 2023 net dependable capacity. Wind is presented as net maximum 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)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2023 the Company’s wind facilities had a weighted-average capacity factors of 43%.

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Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2023:

Conductor Miles
Transmission
345 KV	5,421
230 KV	12,244
138 KV	92
115 KV	4,994
Less than 115 KV	1,782
Total Transmission	24,533
Distribution
Less than 115 KV	80,176
Total	104,709

PSCo had 235 electric utility transmission and distribution substations at Dec. 31, 2023.

Natural gas utility mains at Dec. 31, 2023:

Miles
Transmission	2,024
Distribution	23,494

ITEM 3 — LEGAL PROCEEDINGS

PSCo 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 PSCo’s consolidated financial statements. Legal fees are generally expensed as incurred.

See Note 10 to the consolidated financial statements, Item 1 and Item 7 for further information. 

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

PSCo is a wholly owned subsidiary of Xcel Energy Inc. and there is no market for its common equity securities.

See Note 5 to the consolidated financial statements for further information.

The dividends declared during 2023 and 2022 were as follows:

(Millions of Dollars)	2023		2022
First quarter	$	183	$	129
Second quarter	189		132
Third quarter	161		127
Fourth quarter	72		119

ITEM 6 — [RESERVED]

ITEM 7 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Discussion of financial condition and liquidity for PSCo is omitted per conditions set forth in general instructions I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries. It is replaced with management’s narrative analysis and the results of operations for the current year as set forth in general instructions I(2)(a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

Non-GAAP Financial Measures

The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as ongoing earnings. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that is adjusted from measures calculated and presented in accordance with GAAP.

PSCo’s management uses non-GAAP measures for financial planning and analysis, for reporting of results to the Board of Directors, in determining performance-based compensation and communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.

Earnings Adjusted for Certain Items (Ongoing Earnings)

Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items.

We use this non-GAAP financial measure to evaluate and provide details of PSCo’s core earnings and underlying performance. For instance, to present ongoing earnings, we may adjust the related GAAP amounts for certain items that are non-recurring in nature. We believe this measurement is useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries. This non-GAAP financial measure should not be considered as an alternative to measures calculated and reported in accordance with GAAP.

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The following table provides a reconciliation of GAAP earnings (net income) to ongoing earnings:

(Millions of Dollars)	2023		2022
GAAP net income	$	695	$	727
Loss on Comanche Unit 3 litigation	35		—
Workforce reduction expenses	20		—
Less: tax effect of adjustment	(13)		—
Ongoing earnings	$	737	$	727

Comanche Unit 3 Litigation — In the third quarter of 2023, PSCo recognized a $34 million loss due to a jury verdict in Denver County District Court awarding CORE lost power damages and other costs. PSCo intends to file an appeal of this decision. Given the non-recurring nature of this specific item, it has been excluded from ongoing earnings.

Workforce Reduction — In 2023, Xcel Energy implemented workforce actions to align resources and investments with our evolving business and customer needs, and streamline the organization for long-term success. Xcel Energy initiated a voluntary retirement program, under which approximately 400 eligible non-bargaining employees retired. Xcel Energy also eliminated approximately 150 non-bargaining employees through an involuntary severance program.

Total Xcel Energy workforce reduction expenses of $72 million were recorded in the fourth quarter of 2023, of which $20 million was attributable to PSCo. Given the non-recurring nature of this item, it has been excluded from ongoing earnings.

Results of Operations

2023 Comparison to 2022

PSCo’s GAAP net income was $695 million for 2023, compared to $727 million for 2022. Ongoing net income was $737 million for 2023, compared to $727 million for 2022. Ongoing earnings primarily reflects higher recovery of infrastructure investment and lower O&M expenses, which were partially offset by increased depreciation, interest charges and unfavorable weather.

Electric Margin

Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Expenses incurred for electric fuel and purchased power are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues.

Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas and coal. However, these fluctuations have minimal impact on margin due to fuel recovery mechanisms. In addition, electric customers receive a credit for PTCs generated, which reduce electric revenue and margin (offset by lower tax expense).

Electric Revenues, Fuel and Purchased Power and Electric Margin

(Millions of Dollars)	2023		2022
Electric revenues	$	3,731	$	3,795
Electric fuel and purchased power	(1,364)		(1,485)
Electric margin	$	2,367	$	2,310

Changes in Electric Margin

(Millions of Dollars)	2023 vs. 2022
Regulatory rate outcome	$	56
Non-fuel riders	26
Wholesale transmission revenue (net)	6
Estimated impact of weather (net of decoupling)	(23)
Sales and demand (a)	(5)
Other (net)	(3)
Total increase	$	57

(a)Sales excludes weather impact, net of partial decoupling (mechanism expired in September).

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)	2023		2022
Natural gas revenues	$	1,734	$	1,860
Cost of natural gas sold and transported	(910)		(1,053)
Natural gas margin	$	824	$	807

Changes in Natural Gas Margin

(Millions of Dollars)	2023 vs. 2022
Regulatory rate outcomes	47
Estimated impact of weather	$	(12)
Other (net)	(18)
Total increase	$	17

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses decreased $40 million in 2023. The decrease was primarily due to impact of management cost containment efforts, the timing of regulatory deferrals and the exit of our appliance repair services business, offset by the impact of inflationary pressures, including labor.

Depreciation and Amortization — Depreciation and amortization increased $76 million in 2023. The increase was primarily due to system expansion and new electric and natural gas depreciation rates.

Interest Charges — Interest expenses increased $41 million in 2023. The increase was largely due to increased long-term debt levels to fund capital investments and higher interest rates.

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Public Utility Regulation

The FERC and state and local regulatory commissions regulate PSCo. PSCo 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 Colorado.

Rates are designed to recover plant investment, operating costs and an allowed return on investment. PSCo requests changes in utility rates through commission filings. Changes in operating costs can affect PSCo’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 PSCo’s results of operations and credit quality.

See Rate Matters within Note 10 to the consolidated financial statements for further information.

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 the SPP Western Energy Imbalance Service market, an energy imbalance market.
DOT	Pipeline safety compliance.

Recovery Mechanisms

Mechanism	Additional Information
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.
Decoupling	Mechanism to true-up revenue to a baseline amount for residential (excluding lighting and demand) and metered non-demand small C&I classes (pilot program ended Sept. 2023, with amortization of previously deferred amounts expected through 2026).
DSM Cost Adjustment	Recovers electric and gas DSM, interruptible service costs and performance incentives for achieving energy savings goals.
ECA	Recovers fuel and purchased energy costs. Short-term sales margins are shared with customers. The ECA is revised quarterly.
Fuel Clause Adjustment	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.
Purchased Capacity Cost Adjustment	Recovers purchased capacity payments.
RES Adjustment	Recovers the incremental costs of compliance with the RES with a maximum of 1% of the customer’s bill.
Steam Cost Adjustment	Recovers fuel costs to operate the steam system. The Steam Cost Adjustment rate is revised quarterly.
Transmission Cost Adjustment	Recovers costs between rate cases for transmission projects that result in a net increase in capacity or are part of an approved wildfire mitigation plan.
Transportation Electrification Plan	Recovers costs associated with the investment in and adoption of transportation electrification infrastructure.

Pending and Recently Concluded Regulatory Proceedings

Colorado Electric Rate Case — In 2022, PSCo filed a Colorado electric rate case seeking a revised net increase of $253 million. The total request reflected a $303 million increase, which includes $50 million of authorized costs previously recovered through various rider mechanisms. The request was based on a 10.25% ROE, an equity ratio of 55.7% and a 2023 forecast test year with a 2023 average rate base of $11.3 billion.

In September 2023, the CPUC approved a settlement between PSCo and various parties, which included the following terms:

•Retail revenue increase (excluding rider roll-ins) of $95 million (2.96%), based on a 2022 historic test year using year-end rate base with forward looking known and measurable adjustments.

•Weighted-average cost of capital of 6.95% (based on 55.69% equity ratio and 9.3% ROE).

•Termination of the revenue decoupling pilot.

•Continuation of previously authorized trackers and deferrals.

Rates became effective in September 2023.

Colorado Resource Plan — In August 2022, the CPUC approved a settlement for the Colorado Resource Plan, which provides for an expected carbon reduction and the retirement of PSCo’s remaining coal plant by the end of 2030.

In September 2023 (updated in October 2023), PSCo filed its recommended Preferred Portfolio of resources, which proposed a total of 7,521 MW of generation resources, including 4,716 owned MW and 2,805 purchased power MW. The filing also included several other alternative portfolios.

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In December 2023, the CPUC approved an alternative portfolio of 5,835 MW. The decision provides an opportunity to assess timing and levels of incremental renewable resources in the Just Transition Plan filing expected to be submitted by June 1, 2024.

Approved portfolio includes the following resources:

Generation Resource (in MW)	Company Owned	PPAs	Total
Wind Resources	1,325	375	1,700
Solar	858	760	1,618
Storage	500	1,348	1,848
Natural Gas	450	219	669
Total	3,133	2,702	5,835

PSCo expects to invest approximately $4.8 billion in generation resources under the alternative portfolio for the benefit of its customers and achieving the state’s clean energy goals. The CPUC did not approve the May Valley to Longhorn Transmission Line, which was estimated at $250 million.

In December 2023, the CPUC approved two PIMs associated with the generation projects in the portfolio, including a two-way sharing measure related to capital construction costs and another related to ongoing levelized energy costs. These PIMs will be further defined in the written order and related proceedings throughout 2024.

In February 2024, PSCo filed an ARRR to seek approval for an updated portfolio, reflecting inclusion of certain back-up bids and clarifications of the application of PIMs.

Colorado Natural Gas Rate Case — In January 2024, PSCo filed a request with the CPUC seeking an increase to retail natural gas rates of $171 million, or an approximately 9.5% increase in the average residential customer bill. The request is based on a 2023 test year, a 10.25% ROE, an equity ratio of 55% and a $4.2 billion retail rate base which includes projected capital additions through Dec. 31, 2023. PSCo has requested a proposed effective date of Nov. 1, 2024.

PSCo has proposed to defer collection of the increased rates until Feb. 15, 2025 (following the expiration of the rider to recover Winter Storm Uri costs) to mitigate customer bill impacts, with revenues for the deferred period collected over a 12-month period beginning on that date.

The request supports fundamental infrastructure investments to serve customers, consistent with PSCo’s obligation to provide safe, reliable service while enabling PSCo to continue to be a leader of the clean energy transition in partnership with the CPUC to achieve clean heat goals.

Revenue Request (millions of dollars)
Changes since 2022 rate case:
Plant related investments (a)	$	145
Operations and maintenance, amortization and other expenses	23
Property tax expense	10
Sales growth	(7)
Total base revenue request	$	171

(a)Includes approximately $32 million as a result of the increase in ROE from 9.2% to 10.25%.

ECA Fuel Recovery — In December 2022, PSCo filed to recover $123 million of under-recovered 2022 fuel costs over two quarters. 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 costs.

In 2023, PSCo submitted interim ECA filings to recover $70 million and $25 million, respectively, of the 2022 under-recovered costs.

In the third quarter, PSCo and CPUC Staff filed a settlement allowing for collection of the remaining amount, which after final adjustments was $37 million. In December 2023, the ALJ issued a recommended decision approving the settlement in full. Recovery of costs is expected to begin in the second quarter of 2024.

Colorado Legislation — In May 2023, Colorado Senate Bill 23-291 passed and was signed into law. The bill includes a number of topics including natural gas and electric fuel incentive mechanisms, natural gas planning rules, regulatory filing requirements, and non-recovery of certain expenses (e.g., certain organizational or membership dues, tax penalties or fines).

In November 2023, the CPUC approved PSCo’s natural gas price risk management plan, establishing upper and lower limits for changes in the GCA rate. As a result costs above the upper limit are deferred for future recovery, with interest, and costs below the lower limit are deferred as a reserve against future cost increases.

The legislation also calls for the CPUC to adopt rules to establish fuel cost mechanisms to align the financial incentives of a utility with the interests of the utility’s customers by Jan. 1, 2025. The CPUC issued a request for initial comments on a potential mechanism under which gas utilities would share a percentage, subject to an annual cap, of cost changes in the GCA. A formal rulemaking is expected to commence in the first half of 2024.

Purchased Power and Transmission Service Providers

PSCo meets its system capacity and energy requirements through its fleet of owned and purchased electric generation resources and, when required, the use of demand-side management programs.

Purchased Power — PSCo purchases power from other utilities, energy marketers and independent power producers. Long-term purchased power contracts for dispatchable resources typically require capacity and energy charges. Much of PSCo’s long-term purchased power is for wind, solar and storage resources. PSCo makes short-term purchases to meet system load and energy requirements, replace generation out of service for maintenance, meet operating reserve obligations, or obtain energy at a lower cost.

Energy Markets — PSCo joined the SPP Western Energy Imbalance Service Market in April 2023. This market is an incremental step in the participation in an 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.

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Other

Supply Chain

PSCo’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 the scarcity of certain raw materials and interruptions in production and shipping. Inflationary pressures, labor shortages, and the impact of geopolitical events have further exacerbated these disruptions. PSCo 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.

Additionally, certain products, components, and equipment, particularly in renewables categories, originate in countries that could face tariffs, fines, or restrictions from government or other regulatory bodies and present a cost and supply risk until there is sufficient capacity and supply base with adequate capacity to meet US needs.

Electric Meters and Transformers

Supply chain issues associated with semiconductors delayed the availability of AMI meters, which led to a reduced number of meters deployed in 2022. PSCo saw significant improvement in meter availability in 2023 and we expect normal conditions in 2024 and going forward. PSCo expects to complete AMI meter deployment in 2025.

Additionally, the availability of certain transformers is an industry-wide issue that has significantly impacted and in some cases resulted in delays to projects and new customer connections. Proposed governmental actions related to transformer efficiency standards may compound these delays in the future. PSCo continues to seek alternative suppliers and prioritize work plans to mitigate the impacts of supply constraints.

Solar Resources

In August 2023, the U.S. Department of Commerce completed its anti-circumvention investigation. It concluded that CSPV solar panels and cells imported from Malaysia, Vietnam, Thailand, and Cambodia would be subject to incremental tariffs ranging from 50% to 250%. These countries account for more than 80% of CSPV panel imports.

An interim stay on tariffs remains in effect until June 2024. Many significant solar projects have resumed with modified costs and projected in-service dates, including certain PPAs in PSCo. Further policy action, a change in the interim stay of tariffs, or other restrictions on solar imports (e.g., due to implementation of the Uyghur Forced Labor Protection Act) or disruptions in solar imports from key suppliers could impact project timelines and costs.

ITEM 7A — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Derivatives, Risk Management and Market Risk

PSCo is exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value for a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk.

PSCo 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 PSCo expects that the counterparties will perform on the contracts underlying its derivatives, the contracts expose PSCo to credit and non-performance risk.

Distress in the financial markets may impact counterparty risk and the fair value of the securities in the pension fund.

Commodity Price Risk — We are exposed to commodity price risk in our electric 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 — PSCo 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. PSCo’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee.

Fair value of net commodity trading contracts as of Dec. 31, 2023:

	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
PSCo (a)		$	—	$	1	$	2	$	—	$	3
PSCo (b)		(10)		6		2		—		(2)
		$	(10)	$	7	$	4	$	—	$	1

	Options Maturity
(Millions of Dollars)		Less Than 1 Year		1 to 3 Years		4 to 5 Years		Greater Than 5 Years		Total Fair Value
PSCo (b)		$	4	$	—	$	—	$	—	$	4

(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)	2023		2022
Fair value of commodity trading net contracts outstanding at Jan. 1	$	—	$	(15)
Contracts realized or settled during the period	(12)		(8)
Commodity trading contract additions and changes during the period	17		23
Fair value of commodity trading net contracts outstanding at Dec.31	$	5	$	—

A 10% increase and 10% decrease in forward market prices for PSCo’s commodity trading contracts would have likewise increased and decreased pretax income from continuing operations, by approximately $3 million at Dec. 31, 2023 and $7 million at Dec. 31, 2022. Market price movements can exceed 10% under abnormal circumstances.

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Xcel Energy’s commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations using an industry standard methodology known as VaR. VaR expresses the potential change in fair value of the outstanding contracts and obligations over a particular period of time under normal market conditions. 

The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchases and normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:

(Millions of Dollars)	Year Ended Dec. 31		Average		High		Low
2023	$	—	$	—	$	1	$	—
2022	$	2	$	1	$	5	$	—

Interest Rate Risk — PSCo is subject to interest rate risk. PSCo’s risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives.

A 100 basis point change in the benchmark rate on PSCo’s variable rate debt would impact pretax interest expense annually by approximately $4 million and $3 million in 2023 and 2022, respectively.

The value of pension and postretirement plan assets and benefit costs are impacted by changes in discount rates and expected return on plan assets. PSCo’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 — PSCo is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance on their contractual obligations. PSCo maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.

At Dec. 31, 2023, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $2 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $2 million. At Dec. 31, 2022, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $13 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $6 million.

PSCo 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 PSCo’s credit risk.

Fair Value Measurements

Derivative contracts, with the exception of those designated as normal purchases and normal sales, are reported at fair value. PSCo’s investments held in pension and other postretirement funds are also subject to fair value accounting. See Notes 8 and 9 to the consolidated financial statements for further information.

ITEM 8 — FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

See Item 15-1 for an index of financial statements included herein.

See Note 14 to the consolidated financial statements for further information.

21

Management Report on Internal Control Over Financial Reporting

The management of PSCo is responsible for establishing and maintaining adequate internal control over financial reporting. PSCo’s internal control system was designed to provide reasonable assurance to Xcel Energy Inc.’s and PSCo’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.

PSCo management assessed the effectiveness of PSCo’s internal control over financial reporting as of Dec. 31, 2023. 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, 2023, PSCo’s internal control over financial reporting is effective at the reasonable assurance level based on those criteria.

/s/ ROBERT C. FRENZEL	/s/ BRIAN J. VAN ABEL
Robert C. Frenzel	Brian J. Van Abel
Chairman, Chief Executive Officer and Director	Executive Vice President, Chief Financial Officer and Director
Feb. 21, 2024	Feb. 21, 2024

22

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholder and the Board of Directors of Public Service Company of Colorado

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Public Service Company of Colorado and subsidiaries (the "Company") as of December 31, 2023 and 2022, the related consolidated statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2023, and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Regulatory Assets and Liabilities - Impact of Rate Regulation on the Financial Statements — Refer to Notes 4 and 10 to the consolidated financial statements.

Critical Audit Matter Description

The Company is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Colorado. 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.

23

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 recovery in future rates of incurred costs and refunds 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 filings, legal decisions and recommendations being evaluated by the Commissions, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates. We evaluated historic orders for precedents of the Commissions’ treatment of similar costs under similar circumstances. We compared the regulatory orders, filings and other publicly available information 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 21, 2024

We have served as the Company’s auditor since 2002.

24

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(amounts in millions)

	Year Ended Dec. 31
	2023		2022		2021
Operating revenues
Electric	$	3,731	$	3,795	$	3,413
Natural gas	1,734		1,860		1,355
Other	54		53		47
Total operating revenues	5,519		5,708		4,815
Operating expenses
Electric fuel and purchased power	1,364		1,485		1,336
Cost of natural gas sold and transported	910		1,053		606
Cost of sales — steam and other	17		18		15
Operating and maintenance expenses	865		905		831
Demand side management expenses	135		133		132
Depreciation and amortization	924		848		744
Taxes (other than income taxes)	287		272		256
Loss on Comanche Unit 3 litigation	35		—		—
Workforce reduction expenses	20		—		—
Total operating expenses	4,557		4,714		3,920
Operating income	962		994		895
Other income (expense), net	15		(2)		4
Allowance for funds used during construction — equity	39		32		28
Interest charges and financing costs
Interest charges — includes other financing costs of $8, $8 and $8, respectively	312		271		243
Allowance for funds used during construction — debt	(20)		(11)		(9)
Total interest charges and financing costs	292		260		234
Income before income taxes	724		764		693
Income tax expense	29		37		33
Net income	$	695	$	727	$	660

See Notes to Consolidated Financial Statements

25

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(amounts in millions)

	Year Ended Dec. 31
	2023		2022		2021
Net income	$	695	$	727	$	660
Other comprehensive income
Pension and retiree medical benefits:
Net pension and retiree medical gain (loss) arising during the period, net of tax	—		(1)		—
Reclassification of loss to net income, net of tax	1		—		—
Derivative instruments:
Reclassification of loss to net income, net of tax	1		1		2
Total other comprehensive income	2		—		2
Total comprehensive income	$	697	$	727	$	662

See Notes to Consolidated Financial Statements

26

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(amounts in millions)

	Year Ended Dec. 31
	2023		2022		2021
Operating activities
Net income	$	695	$	727	$	660
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	929		854		754
Deferred income taxes	(138)		(10)		21
Allowance for equity funds used during construction	(39)		(32)		(28)
Provision for bad debts	34		38		26
Changes in operating assets and liabilities:
Accounts receivable	36		(227)		(58)
Accrued unbilled revenues	158		(169)		(52)
Inventories	(14)		(86)		(71)
Other current assets	22		12		(23)
Accounts payable	(107)		183		66
Net regulatory assets and liabilities	270		82		(526)
Other current liabilities	97		8		30
Pension and other employee benefit obligations	11		(13)		(53)
Other, net	—		(112)		(19)
Net cash provided by operating activities	1,954		1,255		727
Investing activities
Utility capital/construction expenditures	(2,360)		(1,880)		(1,604)
Investments in utility money pool arrangement	(367)		(45)		(273)
Repayments from utility money pool arrangement	367		45		273
Net cash used in investing activities	(2,360)		(1,880)		(1,604)
Financing activities
Proceeds from short-term borrowings, net	26		146		11
Borrowings under utility money pool arrangement	781		1,199		743
Repayments under utility money pool arrangement	(730)		(1,199)		(800)
Proceeds from issuance of long-term debt	834		686		737
Repayments of long-term debt	(250)		(300)		—
Capital contributions from parent	400		569		650
Dividends paid to parent	(652)		(491)		(467)
Net cash provided by financing activities	409		610		874
Net change in cash and cash equivalents	3		(15)		(3)
Cash, cash equivalents and restricted cash at beginning of period	10		25		28
Cash, cash equivalents and restricted cash at end of period	$	13	$	10	$	25
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(271)	$	(250)	$	(230)
Cash paid for income taxes, net	(126)		(79)		(14)
Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions	$	248	$	233	$	157
Inventory transfers to property, plant and equipment	75		12		10
Operating lease right-of-use assets	18		140		—
Allowance for equity funds used during construction	39		32		28

See Notes to Consolidated Financial Statements

27

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(amounts in millions, except share and per share)

	Dec. 31
	2023		2022
Assets
Current assets
Cash and cash equivalents	$	13	$	10
Accounts receivable, net	492		562
Accounts receivable from affiliates	28		11
Accrued unbilled revenues	361		519
Inventories	258		319
Regulatory assets	304		411
Derivative instruments	11		65
Prepayments and other	95		103
Total current assets	1,562		2,000
Property, plant and equipment, net	21,035		19,652
Other assets
Regulatory assets	1,267		1,277
Derivative instruments	15		22
Operating lease right-of-use assets	366		437
Other	383		231
Total other assets	2,031		1,967
Total assets	$	24,628	$	23,619
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	—	$	250
Borrowings under utility money pool arrangement	51		—
Short-term debt	320		294
Accounts payable	704		764
Accounts payable to affiliates	83		75
Regulatory liabilities	70		59
Taxes accrued	261		242
Accrued interest	68		59
Dividends payable to parent	72		120
Derivative instruments	17		30
Operating lease liabilities	102		80
Other	177		115
Total current liabilities	1,925		2,088
Deferred credits and other liabilities
Deferred income taxes	1,894		1,983
Regulatory liabilities	2,562		2,489
Asset retirement obligations	383		476
Derivative instruments	—		9
Customer advances	124		144
Pension and employee benefit obligations	40		13
Operating lease liabilities	290		379
Other	218		198
Total deferred credits and other liabilities	5,511		5,691
Commitments and contingencies
Capitalization
Long-term debt	7,450		6,610
Common stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2023 and Dec. 31, 2022, respectively	—		—
Additional paid in capital	7,412		6,992
Retained earnings	2,350		2,260
Accumulated other comprehensive loss	(20)		(22)
Total common stockholder's equity	9,742		9,230
Total liabilities and stockholder's equity	$	24,628	$	23,619
See Notes to Consolidated Financial Statements

28

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

(amounts in millions, except share data)

	Common Stock							Accumulated Other Comprehensive Income (Loss)		Total Common Stockholder’s Equity
	Shares	Par Value		Additional Paid In Capital		Retained Earnings
Balance at Dec. 31, 2020	100	$	—	$	5,770	$	1,846	$	(24)	$	7,592
Net income						660				660
Other comprehensive income								2		2
Common dividends declared to parent						(466)				(466)
Contribution of capital by parent				656						656
Balance at Dec. 31, 2021	100	$	—	$	6,426	$	2,040	$	(22)	$	8,444
Net income						727				727
Common dividends declared to parent						(507)				(507)
Contribution of capital by parent				566						566
Balance at Dec. 31, 2022	100	$	—	$	6,992	$	2,260	$	(22)	$	9,230
Net income						695				695
Other comprehensive income								2		2
Common dividends declared to parent						(605)				(605)
Contribution of capital by parent				420						420
Balance at Dec. 31, 2023	100	$	—	$	7,412	$	2,350	$	(20)	$	9,742
See Notes to Consolidated Financial Statements

29

PUBLIC SERVICE COMPANY of COLORADO

Notes to Consolidated Financial Statements

1. Summary of Significant Accounting Policies

General — PSCo is engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and the regulated purchase, transportation, distribution and sale of natural gas. 

PSCo’s consolidated financial statements include its wholly-owned subsidiaries. In the consolidation process, all intercompany transactions and balances are eliminated. PSCo has investments in several plants and transmission facilities jointly owned with nonaffiliated utilities. 

PSCo’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets, and PSCo’s proportionate share of operating costs associated with these facilities is included in its consolidated statements of income. 

PSCo’s consolidated financial statements are presented in accordance with GAAP. All of PSCo’s underlying accounting records also conform to the FERC uniform system of accounts or to systems required by its state regulatory commission. 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.

PSCo has evaluated events occurring after Dec. 31, 2023 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 — PSCo uses estimates based on the best information available to record 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 — PSCo accounts for income and expense items in accordance with accounting guidance for regulated operations. Under this guidance:

•Certain costs, which would otherwise be charged to expense or other comprehensive income, are deferred as regulatory assets based on the expected ability to recover the costs in future rates.

•Certain credits, which would otherwise be reflected as income or other comprehensive income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred.

Estimates and assumptions for recovery of deferred costs and refund of deferred credits are based on specific ratemaking decisions, precedent or other available information. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process.

If changes in the regulatory environment occur, PSCo 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 PSCo’s results of operations, financial condition and cash flows.

See Note 4 for further information.

Income Taxes — PSCo accounts for income taxes using the asset and liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the consolidated financial statements. Income taxes are deferred for all temporary differences between pretax financial and taxable income and between the book and tax bases of assets and liabilities utilizing rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the period that includes the enactment date.

Utility rate regulation has resulted in the recognition of regulatory assets and liabilities related to income taxes. The effects of PSCo’s tax rate changes are generally subject to a normalization method of accounting. Therefore, the revaluation of most of its 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. PSCo 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.

Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize over the book depreciable lives of related property. The requirement to defer and amortize these credits specifically applies to certain federal ITCs, as determined by tax regulations and PSCo tax elections. For tax credits otherwise eligible to be recognized when earned, PSCo 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. This evaluation includes consideration of whether tax credits are expected to be sold at a discount and impact the realization of amounts presented as deferred tax assets. Transferable tax credits are accounted for under ASC 740 Income Taxes, and valuation allowances and any adjustments for discounts incurred on sales transactions are recorded to deferred tax expense, typically recovered in regulatory mechanisms.

PSCo 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 income (expense), net or interest charges in the consolidated statements of income.

Xcel Energy Inc. and its subsidiaries, including PSCo 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.

30

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 and replacement of items determined to be less than a unit of property are charged to expense 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 3.6% in 2023, 3.4% in 2022 and 3.2% in 2021.

See Note 3 for further information.

AROs — PSCo records AROs as a liability in the period incurred (if fair value can be reasonably estimated), with the offsetting/associated costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion and the capitalized costs are typically depreciated over the useful life of the long-lived asset. Changes resulting from revisions to timing or amounts of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO.

See Note 10 for further information.

Benefit Plans and Other Postretirement Benefits — PSCo maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans requires management to make various assumptions and estimates.

Certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are deferred as regulatory assets and liabilities, rather than recorded as other comprehensive income, based on regulatory recovery mechanisms.

See Note 9 for further information.

Environmental Costs — Environmental costs are recorded when it is probable PSCo is liable for remediation costs and the amount can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. For certain environmental costs related to facilities currently in use, such as for emission-control equipment, the cost is capitalized and depreciated over the life of the plant.

Estimated remediation costs are regularly adjusted as estimates are revised and remediation is performed. If other participating potentially responsible parties exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for PSCo’s expected share of the cost. 

Estimated future expenditures to restore sites are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.

See Note 10 for further information.

Revenue from Contracts with Customers — Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. PSCo 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.

PSCo recognizes physical sales to customers (native load and wholesale) on a gross basis in electric revenues and cost of sales. PSCo participates in SPP WEIS. Revenues for short-term physical wholesale sales of excess energy transacted through the imbalance market are recorded on a gross basis. Other revenues and charges settled/facilitated through SPP WEIS are recorded on a net basis in cost of sales.

See Note 6 for further information.

Cash and Cash Equivalents — PSCo considers investments in instruments with a remaining maturity of 3 months or less at the time of purchase to be cash equivalents.

Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. PSCo 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, 2023 and 2022, the allowance for bad debts was $56 million and $54 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, 2023		Dec. 31, 2022
Inventories
Materials and supplies	$	91	$	80
Fuel	83		68
Natural gas	84		171
Total inventories	$	258	$	319

31

Fair Value Measurements — PSCo presents cash equivalents, interest rate derivatives and commodity derivatives at estimated fair values in its consolidated financial statements. 

For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used to estimate fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price, quoted prices for similar contracts or internally prepared valuation models may be used to determine fair value.

For the pension and postretirement plan assets and nuclear decommissioning fund, published trading data and pricing models, generally using the most observable inputs available, are utilized to determine fair value for each security.

See Notes 8 and 9 for further information.

Derivative Instruments — PSCo 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. Derivatives 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 — PSCo enters into contracts for purchases and sales of commodities for use in its operations. At inception, contracts are evaluated to determine whether they contain a derivative, and if so, whether they may be exempted from derivative accounting if designated as normal purchases or normal sales.

See Note 8 for further information.

Commodity Trading Operations — All applicable gains and losses related to commodity trading activities are shown on a net basis in electric operating revenues in the consolidated statements of income.

Commodity trading activities are not associated with energy produced from PSCo’s generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms. 

See Note 8 for further information

Other Utility Items

AFUDC — AFUDC represents the cost of capital used to finance utility construction activity and is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in PSCo’s rate base.

Alternative Revenue — Certain rate rider mechanisms (including decoupling and 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 — PSCo has implemented programs to assist its retail customers in conserving energy and reducing peak demand on the electric and natural gas systems. These programs include approximately 20 unique DSM products, pilots and services for C&I customers, as well as approximately 23 DSM products, pilots and services for residential and low-income customers. Overall, the DSM portfolio provides rebates and/or incentives for nearly 1,000 unique measures.

The costs incurred for DSM programs are deferred if it is probable future revenue will be provided to permit recovery of the incurred cost. Revenues recognized for incentive programs designed for recovery of DSM program costs and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the year in which they are earned.

PSCo’s DSM program costs are recovered through a combination of base rate revenue and rider mechanisms. 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.

RECs — Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. An inventory accounting model is used to account for RECs.

Sales of RECs are recorded in electric revenues on a gross basis. Cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.

2. Accounting Pronouncements

Recently Issued

Segment Reporting — In November 2023, the FASB issued ASU 2023-07 – Segment Reporting (Topic 280) – Improvements to Reportable Segment Disclosures, which extends the existing requirements for annual disclosures to quarterly periods, and requires that both annual and quarterly disclosures present segment expenses using line items consistent with information regularly provided to the chief operating decision maker. The ASU is effective for annual periods beginning after Dec. 15, 2023 and quarterly periods beginning after Dec. 15, 2024, and PSCo does not expect implementation of the new disclosure guidance to have a material impact to its consolidated financial statements.

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Income Taxes — In December 2023, the FASB issued ASU 2023-09 – Income Taxes (Topic 740) – Improvements to Income Tax Disclosures, with new disclosure requirements including presentation of prescribed line items in the effective tax rate reconciliation and disclosures regarding state and local tax payments. The ASU is effective for annual periods beginning after Dec. 15, 2024, and PSCo does not expect implementation of the new disclosure guidance to have a material impact to its consolidated financial statements.

3. Property, Plant and Equipment

Major classes of property, plant and equipment

(Millions of Dollars)	Dec. 31, 2023		Dec. 31, 2022
Property, plant and equipment, net
Electric plant	$	16,698	$	15,771
Natural gas plant	6,321		5,949
Common and other property	1,472		1,415
Plant to be retired (a)	1,203		1,305
CWIP	1,310		877
Total property, plant and equipment	27,004		25,317
Less accumulated depreciation	(5,969)		(5,665)
Property, plant and equipment, net	$	21,035	$	19,652

(a)Amounts include Comanche Units 2 and 3, Craig Units 1 and 2, Hayden Units 1 and 2 and coal generation assets at Pawnee pending facility gas conversion. Amounts are presented net of accumulated depreciation.

Joint Ownership of Generation, Transmission and Gas Facilities

Jointly owned assets as of Dec. 31, 2023:

(Millions of Dollars, Except Percent Owned)	Plant in Service		Accumulated Depreciation		Percent Owned
Electric generation:
Hayden Unit 1	$	157	$	108	76	%
Hayden Unit 2	151		87		37
Hayden common facilities	44		31		53
Craig Units 1 and 2	82		55		10
Craig common facilities	39		25		7
Comanche Unit 3	916		191		67
Comanche common facilities	29		4		77
Electric transmission:
Transmission and other facilities	189		75		Various
Gas transmission:
Rifle, CO to Avon, CO	28		9		60
Gas transmission compressor	8		2		50
Total (a)	$	1,643	$	587

(a)Projects additionally include $18 million in CWIP.

PSCo’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. PSCo 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, 2023				Dec. 31, 2022
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Pension and retiree medical obligations	9	Various	$	2	$	396	$	3	$	367
Net AROs (a)	1, 10	Various	—		236		—		212
Depreciation differences		One to 10 years	16		184		16		187
Recoverable deferred taxes on AFUDC		Plant lives	—		135		—		119
Excess deferred taxes — TCJA	7	Various	—		55		2		54
Environmental remediation costs		Various	—		44		6		26
Conservation programs (b)	1	One to two years	12		33		8		16
Revenue decoupling		Various	—		31		—		—
Gas pipeline inspection costs		One to two years	3		25		—		13
Deferred natural gas, electric, steam energy/fuel costs		One to three years	221		22		312		200
Purchased power contract costs		Term of related contract	4		20		3		16
Grid modernization costs		Two years	15		14		14		22
Property tax		Various	3		7		8		2
Other		Various	28		65		39		43
Total regulatory assets			$	304	$	1,267	$	411	$	1,277

(a)Includes amounts recorded for future recovery of AROs.

(b)Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

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Components of regulatory liabilities:

(Millions of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2023				Dec. 31, 2022
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Deferred income tax adjustments and TCJA refunds (a)	7	Various	$	2	$	1,260	$	2	$	1,298
Plant removal costs	1, 10	Various	—		769		—		705
Effects of regulation on employee benefit costs (b)		Various	—		234		—		227
Renewable resources and environmental initiatives		Various	—		152		—		141
Revenue decoupling		Various	—		63		—		55
ITC deferrals	1	Various	1		44		1		41
Deferred natural gas, electric, steam energy/fuel costs		Less than one year	34		—		3		—
Conservation programs	1	Less than one year	9		—		19		—
Formula rates		One to two years	8		—		16		—
Other		Various	16		40		18		22
Total regulatory liabilities			$	70	$	2,562	$	59	$	2,489

(a)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.

(b)Includes regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the prepaid pension asset.

PSCo’s regulatory assets not earning a return include past expenditures of $416 million and $538 million at Dec. 31, 2023 and 2022, respectively, which predominately relate to purchased natural gas and electric energy costs (including certain costs related to Winter Storm Uri), sales true-up and revenue decoupling and various renewable resources/environmental initiatives. Additionally, the unfunded portion of pension and retiree medical obligations and net AROs (i.e. deferrals for which cash has not been disbursed) do not earn a return.

5. Borrowings and Other Financing Instruments

Short-Term Borrowings

PSCo meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility and the money pool.

Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc.

Money pool borrowings:

(Millions of Dollars, Except Interest Rates)	Three Months Ended Dec. 31, 2023			Year Ended Dec. 31
				2023			2022			2021
Borrowing limit	$	250		$	250		$	250		$	250
Amount outstanding at period end	51			51			—			—
Average amount outstanding	64			23			29			12
Maximum amount outstanding	250			250			250			243
Weighted average interest rate, computed on a daily basis	5.33		%	5.31		%	1.66		%	0.07		%
Weighted average interest rate at end of period	5.34			5.34			N/A			N/A

Commercial Paper — Commercial paper borrowings:

(Millions of Dollars, Except Interest Rates)	Three Months Ended Dec. 31, 2023			Year Ended Dec. 31
				2023			2022			2021
Borrowing limit	$	700		$	700		$	700		$	700
Amount outstanding at period end	320			320			294			147
Average amount outstanding	189			124			71			26
Maximum amount outstanding	369			454			328			322
Weighted average interest rate, computed on a daily basis	5.53		%	5.17		%	2.56		%	0.19		%
Weighted average interest rate at end of period	5.56			5.56			4.73			0.22

Letters of Credit — PSCo uses letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2023 and 2022, there were $29 million and $27 million of letters of credit outstanding under the credit facility, respectively. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, PSCo must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under this credit facility. The credit facility provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

Features of PSCo’s credit facility:

Debt-to-Total Capitalization Ratio (a)				Amount Facility May Be Increased (millions of dollars)		Additional Periods for Which a One-Year Extension May Be Requested (b)
2023		2022
44.8	%	44.0	%	$	100	2

(a)The credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%.

(b)All extension requests are subject to majority bank group approval.

The credit facility has a cross-default provision that provides PSCo would be in default on its borrowings under the facility if PSCo or any of its subsidiaries whose total assets exceed 15% of PSCo’s consolidated total assets, default on indebtedness in an aggregate principal amount exceeding $75 million.

If PSCo does not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2023, PSCo was in compliance with all financial covenants.

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PSCo had the following committed credit facility available as of Dec. 31, 2023 (in millions of dollars):

Credit Facility (a)		Drawn (b)		Available
$	700	$	349	$	351

(a)This credit facility matures in September 2027.

(b)Includes letters of credit and outstanding commercial paper.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. PSCo had no direct advances on the facility outstanding at Dec. 31, 2023 and 2022.

Long-Term Borrowings and Other Financing Instruments

Generally, the property of PSCo is subject to the lien of its first mortgage indenture for the benefit of bondholders. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses for refinanced debt are deferred and amortized over the life of the new issuance.

Long-term debt obligations for PSCo as of Dec. 31 (in millions of dollars):

Financing Instrument	Interest Rate		Maturity Date	2023		2022
First mortgage bonds	2.50	%	March 15, 2023	$	—	$	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	1.875		June 15, 2031	750		750
First mortgage bonds (a)	4.10		June 1, 2032	300		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 (a)	4.50		June 1, 2052	400		400
First mortgage bonds (b)	5.25		April 1, 2053	850		—
Unamortized discount				(41)		(37)
Unamortized debt issuance cost				(59)		(53)
Current maturities				—		(250)
Total long-term debt				$	7,450	$	6,610

(a)2022 financing.

(b)2023 financing.

Maturities of long-term debt:

(Millions of Dollars)
2024	$	—
2025	250
2026	—
2027	—
2028	350

Deferred Financing Costs — Deferred financing costs of approximately $59 million and $53 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt as of Dec. 31, 2023 and 2022, respectively. 

Capital Stock — PSCo has authorized the issuance of preferred stock.

Preferred Stock Authorized (Shares)	Par Value of Preferred Stock		Preferred Stock Outstanding (Shares) 2023 and 2022
10,000,000	$	0.01	—

Dividend Restrictions — PSCo’s 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.

6. Revenues

Revenue is classified by the type of goods/services rendered and market/customer type. PSCo’s operating revenues consisted of the following:

	Year Ended Dec. 31, 2023
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	1,295	$	1,109	$	19	$	2,423
C&I	1,816		459		30		2,305
Other	52		—		5		57
Total retail	3,163		1,568		54		4,785
Wholesale	237		—		—		237
Transmission	90		—		—		90
Other	61		132		—		193
Total revenue from contracts with customers	3,551		1,700		54		5,305
Alternative revenue and other	180		34		—		214
Total revenues	$	3,731	$	1,734	$	54	$	5,519

	Year Ended Dec. 31, 2022
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	1,341	$	1,203	$	15	$	2,559
C&I	1,843		479		32		2,354
Other	52		—		—		52
Total retail	3,236		1,682		47		4,965
Wholesale	286		—		—		286
Transmission	88		—		—		88
Other	53		151		—		204
Total revenue from contracts with customers	3,663		1,833		47		5,543
Alternative revenue and other	132		27		6		165
Total revenues	$	3,795	$	1,860	$	53	$	5,708

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	Year Ended Dec. 31, 2021
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	1,174	$	816	$	12	$	2,002
C&I	1,660		308		30		1,998
Other	49		—		—		49
Total retail	2,883		1,124		42		4,049
Wholesale	228		—		—		228
Transmission	75		—		—		75
Other	44		159		—		203
Total revenue from contracts with customers	3,230		1,283		42		4,555
Alternative revenue and other	183		72		5		260
Total revenues	$	3,413	$	1,355	$	47	$	4,815

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:

	2023		2022		2021
Federal statutory rate	21.0	%	21.0	%	21.0	%
State income tax on pretax income, net of federal tax effect	3.5		3.5		3.6
Increases (decreases) in tax from:
Wind PTCs (a)	(14.5)		(14.3)		(14.3)
Plant regulatory differences (b)	(5.5)		(4.5)		(4.6)
Other tax credits, net NOL & tax credit allowances	(1.1)		(1.1)		(1.0)
Other, net	0.6		0.2		0.1
Effective income tax rate	4.0	%	4.8	%	4.8	%

(a)Wind PTCs net of estimated transfer discount are credited to customers (reduction to revenue) and do not materially impact net income.

(b)Plant regulatory differences primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit are offset by corresponding revenue reductions.

Components of income tax expense for the years ended Dec. 31:

(Millions of Dollars)	2023		2022		2021
Current federal tax expense	$	182	$	39	$	16
Current state tax expense	28		11		—
Current change in unrecognized tax benefit	—		—		(1)
Deferred federal tax benefit	(181)		(32)		(13)
Deferred state tax expense	2		21		31
Deferred change in unrecognized tax expense	1		1		3
Deferred ITCs	(3)		(3)		(3)
Total income tax expense	$	29	$	37	$	33

Components of deferred income tax expense as of Dec. 31:

(Millions of Dollars)	2023		2022		2021
Deferred tax (benefit) expense excluding items below	$	(89)	$	23	$	63
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(48)		(32)		(42)
Adjustments to deferred income taxes for wind production tax credit cash transfers (a)	(40)		—		—
Tax expense allocated to other comprehensive income and other	(1)		(1)		—
Deferred tax (benefit) expense	$	(178)	$	(10)	$	21

(a)Proceeds from tax credit transfers are included in cash received (paid) for income taxes in the consolidated statement of cash flows.

Components of the net deferred tax liability as of Dec. 31:

(Millions of Dollars)	2023		2022 (a)
Deferred tax liabilities:
Differences between book and tax bases of property	$	2,326	$	2,315
Regulatory assets	289		243
Operating lease assets	95		112
Deferred fuel costs	51		125
Pension expense and other employee benefits	22		27
Other	8		11
Total deferred tax liabilities	$	2,791	$	2,833
Deferred tax assets:
Tax credit carryforward	$	457	$	385
Regulatory liabilities	291		292
Operating lease liabilities	95		112
Bad debts	14		14
Deferred ITCs	10		7
Tax credit carryforward valuation allowances	(6)		(6)
Rate refund	4		21
NOL carryforward	—		9
Other	32		16
Total deferred tax assets	$	897	$	850
Net deferred tax liability	$	1,894	$	1,983

(a)Prior periods have been reclassified to conform to current year presentation.

Other Income Tax Matters — NOL amounts represent the tax loss that is carried forward and tax credits represent the deferred tax asset.

NOL and tax credit carryforwards as of Dec. 31 were as follows:

(Millions of Dollars)	2023		2022
Federal NOL carryforward	$	—	$	5
Federal tax credit carryforwards	444		368
Valuation allowances for federal credit carryforwards	(3)		—
State NOL carryforwards	—		223
State tax credit carryforwards, net of federal detriment (a)	13		16
Valuation allowances for state credit carryforwards, net of federal benefit (b)	(3)		(6)

(a)State tax credit carryforwards are net of federal detriment of $3 million and $4 million as of Dec. 31, 2023 and 2022, respectively.

(b)Valuation allowances for state tax credit carryforwards were net of federal benefit of $1 million and $2 million as of Dec. 31, 2023 and 2022, respectively.

Federal carryforward periods expire between 2038 and 2043 and state carryforward periods expire between 2024 and 2036.

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Unrecognized Tax Benefits

Federal Audit — PSCo is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s consolidated federal tax returns expire as follows:

Tax Year(s)	Expiration
2014 - 2016	March 2025
2020	September 2024

Additionally, the statute of limitations related to certain 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. As of Dec. 31, 2023 the IRS issued its Revenue Agent’s Report related to the federal tax loss carryback claim. The Company materially agrees with the report and re-recognized the related benefit in Dec. 2023.

State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2023, PSCo’s earliest open tax years that are subject to examination by state taxing authorities under applicable statutes of limitations are as follows:

State	Tax Year(s)	Expiration
Colorado	2014-2016	March 2026
Colorado	2019	October 2024

There are currently no state income tax audits in progress.

Unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which deductibility is highly certain, but for which there is uncertainty about the timing. A change in the timing of deductibility would not affect the ETR but would accelerate the payment to the taxing authority.

Unrecognized tax benefits - permanent vs temporary:

(Millions of Dollars)	Dec. 31, 2023		Dec. 31, 2022
Unrecognized tax benefit — Permanent tax positions	$	12	$	11
Unrecognized tax benefit — Temporary tax positions	—		2
Total unrecognized tax benefit	$	12	$	13

Changes in unrecognized tax benefits:

(Millions of Dollars)	2023		2022		2021
Balance at Jan. 1	$	13	$	11	$	9
Additions based on tax positions related to the current year	2		2		2
Reductions for tax positions of prior years	(3)		—		—
Balance at Dec. 31	$	12	$	13	$	11

Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards:

(Millions of Dollars)	Dec. 31, 2023		Dec. 31, 2022
NOL and tax credit carryforwards	$	(11)	$	(12)

As IRS and state audits resume, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $4 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. Payables for interest related to unrecognized tax benefits at Dec. 31, 2023, 2022 and 2021 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2023, 2022 or 2021.

8. Fair Value of Financial Assets and Liabilities

Fair Value Measurements

Accounting guidance for fair value measurements and disclosures provides a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. 

•Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are actively traded instruments with observable actual trading prices.

•Level 2 — Pricing inputs are other than actual trading prices in active markets but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts or priced with models using highly observable inputs.

•Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 include those valued with models requiring significant judgment or estimation.

Specific valuation methods include:

Interest rate derivatives — Fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.

Commodity derivatives — Methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When contracts relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges, the significance of the use of less observable inputs on a valuation is evaluated and may result in Level 3 classification.

Derivative Activities and Fair Value Measurements

PSCo 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 — PSCo 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, 2023, accumulated other comprehensive loss related to interest rate derivatives included $1 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings. As of Dec. 31, 2023, PSCo had no unsettled interest rate derivatives.

Wholesale and Commodity Trading — PSCo 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. PSCo 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.

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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 — PSCo 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 vehicle fuel.

When PSCo 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, 2023, PSCo had no commodity contracts designated as cash flow hedges.

Gross notional amounts of commodity forwards and options:

(Amounts in Millions) (a)(b)	Dec. 31, 2023	Dec. 31, 2022
MWh of electricity	2	8
MMBtu of natural gas	20	43

(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 — PSCo 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.

PSCo’s most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities. 

As of Dec. 31, 2023, four of PSCo’s ten most significant counterparties for these activities, comprising $30 million or 36% of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services or Fitch Ratings. 

Six of the ten most significant counterparties, comprising $40 million or 48% of this credit exposure, were not rated by these external ratings agencies, but based on PSCo’s internal analysis, had credit quality consistent with investment grade.

None of these significant counterparties had credit quality less than investment grade, based on internal analysis.

Eight of these significant counterparties are municipal, cooperative electric entities, RTOs or other utilities.

Credit Related Contingent Features — Contract provisions for derivative instruments that PSCo enters into, 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 PSCo’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies. As of Dec. 31, 2023 and 2022, there were no derivative liabilities position with such underlying contract provisions.

Also, certain contracts may 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, 2023 there were approximately $8 million of derivative instruments in a liability position with such underlying contract provisions. As of Dec. 31, 2022, there were no derivative liabilities in a liability position with such underlying contract provisions.

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 PSCo’s ability to fulfill its contractual obligations is reasonably expected to be impaired. PSCo had no collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 2023 and 2022.

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, 2023
Other derivative instruments
Natural gas commodity	$	—	$	(13)
Total	$	—	$	(13)
Year Ended Dec. 31, 2022
Other derivative instruments
Natural gas commodity	$	—	$	(15)
Total	$	—	$	(15)
Year Ended Dec. 31, 2021
Other derivative instruments
Natural gas commodity	$	—	$	(1)
Total	$	—	$	(1)

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	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, 2023
Derivatives designated as cash flow hedges
Interest rate	$	1	(a)	$	—		$	—
Total	$	1		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	(5)	(b)
Natural gas commodity	—			15		(c)	(16)		(c)(d)
Total	$	—		$	15		$	(21)
Year Ended Dec. 31, 2022
Derivatives designated as cash flow hedges
Interest rate	$	1	(a)	$	—		$	—
Total	$	1		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	7	(b)
Natural gas commodity	—			8		(c)	(17)		(c)(d)
Total	$	—		$	8		$	(10)
Year Ended Dec. 31, 2021
Derivatives designated as cash flow hedges
Interest rate	$	2	(a)	$	—		$	—
Total	$	2		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	12	(b)
Natural gas commodity	—			4		(c)	(15)		(c)(d)
Total	$	—		$	4		$	(3)

(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 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.

(d)Relates primarily to option premium amortization.

PSCo had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2023, 2022 and 2021. 

Derivative assets and liabilities measured at fair value on a recurring basis were as follows:

	Dec. 31, 2023												Dec. 31, 2022
	Fair Value						Fair Value Total		Netting (a)		Total		Fair Value						Fair Value Total		Netting (a)		Total
(Millions of Dollars)	Level 1		Level 2		Level 3								Level 1		Level 2		Level 3
Current derivative assets
Other derivative instruments:
Commodity trading	$	1	$	19	$	—	$	20	$	(17)	$	3	$	16	$	220	$	1	$	237	$	(184)	$	53
Natural gas commodity	—		8		—		8		—		8		—		12		—		12		—		12
Total current derivative assets	$	1	$	27	$	—	$	28	$	(17)	$	11	$	16	$	232	$	1	$	249	$	(184)	$	65
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	6	$	9	$	—	$	15	$	—	$	15	$	12	$	32	$	9	$	53	$	(31)	$	22
Total noncurrent derivative assets	$	6	$	9	$	—	$	15	$	—	$	15	$	12	$	32	$	9	$	53	$	(31)	$	22
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	1	$	25	$	—	$	26	$	(17)	$	9	$	5	$	237	$	1	$	243	$	(223)	$	20
Natural gas commodity	—		8		—		8		—		8		—		10		—		10		—		10
Total current derivative liabilities	$	1	$	33	$	—	$	34	$	(17)	$	17	$	5	$	247	$	1	$	253	$	(223)	$	30
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	2	$	1	$	—	$	3	$	(3)	$	—	$	7	$	40	$	—	$	47	$	(38)	$	9
Total noncurrent derivative liabilities	$	2	$	1	$	—	$	3	$	(3)	$	—	$	7	$	40	$	—	$	47	$	(38)	$	9

(a)PSCo nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement. At Dec. 31, 2023 and 2022, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2023 and 2022, derivative assets and liabilities include rights to reclaim cash collateral of $4 million and $46 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.

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Changes in Level 3 commodity derivatives:

	Year Ended Dec. 31
(Millions of Dollars)	2023		2022		2021
Balance at Jan. 1	$	9	$	(63)	$	(44)
Settlements (a)	—		12		4
Net transactions recorded during the period:
(Losses) gains recognized in earnings (a)	(9)		60		(23)
Balance at Dec. 31	$	—	$	9	$	(63)

(a)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:

	2023				2022
(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	7,450	$	6,580	$	6,860	$	5,881

Fair value of PSCo’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, 2023 and 2022, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.

9. Benefit Plans and Other Postretirement Benefits

Pension and Postretirement Health Care Benefits

Xcel Energy, which includes PSCo, 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 5.03, 5.14 and 2.26 percent in 2023, 2022, and 2021, 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 recognized for ratemaking and financial reporting purposes, 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, 2023 and 2022 were $12 million and $11 million, respectively, of which $2 million and $1 million was attributable to PSCo in 2023 and 2022, respectively. Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $2 million in 2023 and $17 million in 2022, respectively, of which immaterial amounts were attributable to PSCo.

Xcel Energy’s postretirement health care benefit plan is a continuation of certain welfare benefit programs for current employees. A full time employee’s date of hire or a retiree’s date of retirement determine eligibility for each of the programs.

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. Xcel Energy Inc. and PSCo continually review pension assumptions.

Pension cost determination assumes a forecasted mix of investment types over the long-term.

•Investment returns in 2023 were above the assumed level of 6.53%.

•Investment returns in 2022 were below the assumed level of 6.39%.

•Investment returns in 2021 were above the assumed level of 6.38%.

•In 2024, PSCo’s expected investment-return assumption is 6.53%.

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. 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, PSCo’s pension plan assets measured at fair value:

	Dec. 31, 2023 (a)										Dec. 31, 2022 (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	$	94	$	—	$	—	$	—	$	94	$	52	$	—	$	—	$	—	$	52
Commingled funds	177		—		—		464		641		355		—		—		317		672
Debt securities	—		287		1		—		288		—		286		1		—		287
Equity securities	12		—		—		—		12		17		—		—		—		17
Other	—		2		—		—		2		—		3		—		—		3
Total	$	283	$	289	$	1	$	464	$	1,037	$	424	$	289	$	1	$	317	$	1,031

(a)See Note 8 for further information on fair value measurement inputs and methods.

For each of the fair value hierarchy levels, PSCo’s proportionate allocation of the total postretirement benefit plan assets that were measured at fair value:

	Dec. 31, 2023 (a)										Dec. 31, 2022 (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	$	29	$	—	$	—	$	—	$	29	$	28	$	—	$	—	$	—	$	28
Insurance contracts	—		35		—		—		35		—		36		—		—		36
Commingled funds	20		—		—		63		83		47		—		—		56		103
Debt securities	—		165		1		—		166		—		153		1		—		154
Other	—		1		—		—		1		—		(1)		—		—		(1)
Total	$	49	$	201	$	1	$	63	$	314	$	75	$	188	$	1	$	56	$	320

(a)See Note 8 for further information on fair value measurement inputs and methods.

Immaterial assets were transferred in or out of Level 3 for 2023 and 2022.

Funded Status — Comparisons of the actuarially computed benefit obligation, changes in plan assets and funded status of the pension and postretirement health care plans for PSCo are as follows:

	Pension Benefits				Postretirement Benefits
(Millions of Dollars)	2023		2022		2023		2022
Change in Benefit Obligation:
Obligation at Jan. 1	$	1,032	$	1,363	$	296	$	369
Service cost	19		29		1		1
Interest cost	58		41		16		10
Actuarial (gain) loss	45		(317)		18		(55)
Plan participants’ contributions	—		—		7		7
Medicare subsidy reimbursements	—		—		—		1
Benefit payments	(83)		(84)		(42)		(37)
Obligation at Dec. 31	$	1,071	$	1,032	$	296	$	296
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	1,031	$	1,351	$	320	$	393
Actual return on plan assets	89		(276)		26		(46)
Employer contributions	—		40		3		3
Plan participants’ contributions	—		—		7		7
Benefit payments	(83)		(84)		(42)		(37)
Fair value of plan assets at Dec. 31	$	1,037	$	1,031	$	314	$	320
Funded status of plans at Dec. 31	$	(34)	$	(1)	$	18	$	24
Amounts recognized in the Consolidated Balance Sheet at Dec. 31:
Noncurrent assets	—		8		18		24
Noncurrent liabilities	(34)		(9)		—		—
Net amounts recognized	$	(34)	$	(1)	$	18	$	24

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	Pension Benefits				Postretirement Benefits
Significant Assumptions Used to Measure Benefit Obligations:	2023		2022		2023		2022
Discount rate for year-end valuation	5.49	%	5.80	%	5.54	%	5.80	%
Expected average long-term increase in compensation level	4.25	%	4.25	%	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	%	6.50	%
Health care costs trend rate — initial: Post-65	N/A		N/A		5.50	%	5.50	%
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		6		7

Accumulated benefit obligation for the pension plan was $1,010 million and $992 million as of Dec. 31, 2023 and 2022, respectively.

Net Periodic Benefit Cost (Credit) — Net periodic benefit cost (credit), other than the service cost component, is included in other income (expense) in the statements of income.

Components of net periodic benefit cost (credit) and amounts recognized in other comprehensive income and regulatory assets and liabilities:

	Pension Benefits									Postretirement Benefits
(Millions of Dollars)	2023			2022			2021			2023			2022			2021
Service cost	$	19		$	29		$	32		$	1		$	1		$	1
Interest cost	58			41			39			16			10			11
Expected return on plan assets	(76)			(78)			(73)			(15)			(15)			(16)
Amortization of prior service credit	—			—			—			—			(2)			(4)
Amortization of net loss	1			23			32			1			1			3
Settlement charge (a)	—			3			—			—			—			—
Net periodic pension cost (credit)	2			18			30			3			(5)			(5)
Effects of regulation	9			4			—			—			3			2
Net benefit cost (credit) recognized for financial reporting	$	11		$	22		$	30		$	3		$	(2)		$	(3)
Significant Assumptions Used to Measure Costs:
Discount rate	5.80		%	3.08		%	2.71		%	5.80		%	3.09		%	2.65		%
Expected average long-term increase in compensation level	4.25			3.75			3.75			N/A			N/A			N/A
Expected average long-term rate of return on assets	6.53			6.39			6.38			5.00			4.10			4.10

(a)A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2022, as a result of lump-sum distributions during the plan year, PSCo recorded a total pension settlement charge of $3 million. An immaterial amount was recorded in the income statement in 2022. There were no settlement charges recorded to the qualified pension plans in 2023 or 2021.

	Pension Benefits				Postretirement Benefits
(Millions of Dollars)	2023		2022		2023		2022
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	355	$	325	$	59	$	53
Prior service credit	(1)		(1)		—		—
Total	$	354	$	324	$	59	$	53
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	$	3	$	3	$	1	$	—
Noncurrent regulatory assets	351		320		58		53
Net-of-tax accumulated other comprehensive income			1				—
Total	$	354	$	324	$	59	$	53

Measurement date Dec. 31, 2023 Dec. 31, 2022 Dec. 31, 2023 Dec. 31, 2022

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 2021 - 2024 to meet minimum funding requirements. Total voluntary and required pension funding contributions across all four of Xcel Energy’s pension plans were as follows:

•$100 million in January 2024, of which $7 million was attributable to PSCo.

•$50 million in 2023, of which zero was attributable to PSCo.

•$50 million in 2022, of which $40 million was attributable to PSCo.

•$131 million in 2021, of which $46 million was attributable to PSCo.

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The postretirement health care plans have no funding requirements other than fulfilling benefit payment obligations when claims are presented and approved. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities.

Xcel Energy’s voluntary postretirement funding contributions were as follows:

•$11 million expected in 2024, of which $2 million is attributable to PSCo.

•$11 million during 2023, of which $3 million was attributable to PSCo.

•$13 million during 2022, of which $3 million was attributable to PSCo.

•$15 million during 2021, of which $3 million was attributable to PSCo.

Targeted asset allocations:

	Pension Benefits				Postretirement Benefits
	2023		2022		2023		2022
Long-duration fixed income securities	38	%	38	%	—	%	—	%
Domestic and international equity securities	31		33		9		16
Alternative investments	20		18		13		12
Short-to-intermediate fixed income securities	9		9		77		71
Cash	2		2		1		1
Total	100	%	100	%	100	%	100	%

The asset allocations above reflect target allocations approved in the calendar year to take effect in the subsequent year

Plan Amendments — In 2023, Xcel Energy amended the Xcel Energy Pension Plan and Xcel Energy Inc. Nonbargaining Pension Plan (South) to reduce supplemental social security benefits for all active participants on and after Jan. 1, 2024.

There was no significant plan amendments made in 2022 which affected the projected 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

PSCo’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
2024	$	89	$	31	$	2	$	29
2025	80		30		2		28
2026	80		29		2		27
2027	80		28		2		26
2028	79		27		2		25
2029-2033	384		123		12		111

Voluntary Retirement Program

Incremental to amounts presented above for postretirement benefits, Xcel Energy, which includes PSCo, recognized new postemployment costs and obligations in the fourth quarter of 2023 for employees accepted to a voluntary retirement program.

Utilizing employee information and the following inputs, the estimated PSCo obligations for the program of $2 million for health plan subsidies and an immaterial amount for other medical benefits, each commencing in 2024, were recognized in the fourth quarter of 2023. These unfunded obligations are presented in other current liabilities and noncurrent pension and employee benefit obligations in the consolidated balance sheet as of Dec. 31, 2023.

Significant Assumptions to Measure Benefit Obligations:	2023
Discount rate for year-end valuation	5.50	%
Mortality table	PRI-2012
Health care costs trend rate and ultimate trend assumption	7.00	%

Defined Contribution Plans

Xcel Energy, which includes PSCo, maintains 401(k) and other defined contribution plans that cover most employees. Total expense to these plans for PSCo was approximately $13 million in 2023, and $12 million in 2022 and 2021.

10. Commitments and Contingencies

Legal

PSCo 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 PSCo’s consolidated financial statements. Legal fees are generally expensed as incurred.

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 April 2022, CORE filed a supplement to include damages related to a 2022 outage. Also in 2022, CORE sent notice of withdrawal from the ownership agreement based on the same alleged breaches.

In February 2023, the court granted PSCo’s motion precluding CORE from seeking damages related to its withdrawal as part of the lawsuit. In October 2023, the jury ruled that CORE may not withdraw as a joint owner of the facility but awarded CORE lost power damages of $26 million. PSCo recognized a $34 million loss for the verdict in the third quarter of 2023, including estimated interest and other costs. PSCo intends to file an appeal of this decision.

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Marshall Wildfire Litigation — 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. On June 8, 2023, the Boulder County Sheriff’s Office released its Marshall Fire Investigative Summary and Review and its supporting documents (the “Sheriff’s Report”). According to an October 2022 statement from the Colorado Insurance Commissioner, the Marshall Fire is estimated to have caused more than $2 billion in property losses.

According to the Sheriff’s Report, on Dec. 30, 2021, a fire ignited on a residential property in Boulder, Colorado, located in PSCo’s service territory, for reasons unrelated to PSCo’s power lines. According to the Sheriff’s Report, approximately one hour and 20 minutes after the first ignition, a second fire ignited just south of the Marshall Mesa Trailhead in unincorporated Boulder County, Colorado, also located in PSCo’s service territory. According to the Sheriff’s Report, the second ignition started approximately 80 to 110 feet away from PSCo’s power lines in the area.

The Sheriff’s Report states that the most probable cause of the second ignition was hot particles discharged from PSCo’s power lines after one of the power lines detached from its insulator in strong winds, and further states that it cannot be ruled out that the second ignition was caused by an underground coal fire. According to the Sheriff’s Report, no design, installation or maintenance defects or deficiencies were identified on PSCo’s electrical circuit in the area of the second ignition. PSCo disputes that its power lines caused the second ignition.

PSCo is aware of 302 complaints, most of which have also named Xcel Energy Inc. and Xcel Energy Services, Inc. as additional defendants, relating to the Marshall Fire. The complaints are on behalf of at least 4,047 plaintiffs, and one complaint is filed on behalf of a putative class of first responders who allegedly were exposed to the threat of serious bodily injury, or smoke, soot and ash from the Marshall Fire. The complaints generally allege that PSCo’s equipment ignited the Marshall Fire and assert various causes of action under Colorado law, including negligence, premises liability, trespass, nuisance, wrongful death, willful and wanton conduct, negligent infliction of emotional distress, loss of consortium and inverse condemnation. In addition to seeking compensatory damages, certain of the complaints also seek exemplary damages.

In September 2023, the Boulder County District Court Judge consolidated eight lawsuits that were pending at that time into a single action for pretrial purposes and has subsequently consolidated additional lawsuits that have been filed. At the case management conference in February 2024, a trial date was set for September 2025.

Colorado courts do not apply strict liability in determining an electric utility company’s liability for fire-related damages. For inverse condemnation claims, Colorado courts assess whether a defendant acted with intent to take a plaintiff’s property or intentionally took an action which has the natural consequence of taking the property. For negligence claims, 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.

Colorado law does not impose joint and several liability in tort actions. Instead, under Colorado law, a defendant is liable for the degree or percentage of the negligence or fault attributable to that defendant, except where the defendant conspired with another defendant. A jury’s verdict in a Colorado civil case must be unanimous. Under Colorado law, in a civil action other than a medical malpractice action, the total award for noneconomic loss is capped at $0.6 million per defendant for claims that accrued at the time of the Marshall Fire unless the court finds justification to exceed that amount by clear and convincing evidence, in which case the maximum doubles.

Colorado law caps punitive or exemplary damages to an amount equal to the amount of the actual damages awarded to the injured party, except the court may increase any award of punitive damages to a sum up to three times the amount of actual damages if the conduct that is the subject of the claim has continued during the pendency of the case or the defendant has acted in a willful and wanton manner during the action which further aggravated plaintiff’s damages.

In the event Xcel Energy Inc. or PSCo was found liable related to this litigation and were required to pay damages, such amounts could exceed our insurance coverage of approximately $500 million and have a material adverse effect on our financial condition, results of operations or cash flows. However, due to uncertainty as to the cause of the fire and the extent and magnitude of potential damages, Xcel Energy Inc. and PSCo are unable to estimate the amount or range of possible losses in connection with the Marshall Fire.

Rate Matters

PSCo is involved in various regulatory proceedings arising in the ordinary course of business. Until resolution, typically in the form of a rate order, uncertainties may exist regarding the ultimate rate treatment for certain activities and transactions. Amounts have been recognized for probable and reasonably estimable losses that may result. Unless otherwise disclosed, any reasonably possible range of loss in excess of any recognized amount is not expected to have a material effect on the consolidated financial statements.

Environmental

New and changing federal and state environmental mandates can create financial liabilities for PSCo, which are normally recovered through the regulated rate process.

Site Remediation

Various federal and state environmental laws impose liability where hazardous substances or other regulated materials have been released to the environment. PSCo may sometimes pay all or a portion of the cost to remediate sites where past activities of PSCo’s predecessors or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former MGPs; and third-party sites, such as landfills, for which PSCo is alleged to have sent wastes to that site.

MGP, Landfill and Disposal Sites

PSCo is currently investigating, remediating or performing post-closure actions at two historical MGP, landfill or other disposal sites across its service territory, excluding sites that are being addressed under current coal ash regulations (see below).

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PSCo has recognized approximately $6 million 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 — PSCo’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.

If certain impacts to groundwater are detected, utilities are required to perform additional groundwater investigations and/or perform corrective actions beginning with an Assessment of Corrective Measures. Investigation and/or corrective action related to groundwater impacts are currently underway at four PSCo sites under the federal CCR program at a current estimated cost of at least $40 million. A liability has been recorded and is expected to be fully recoverable through regulatory mechanisms.

PSCo has executed an agreement with a third party that will excavate and process ash for beneficial use (at two sites) at a cost of approximately $45 million. An estimated liability has been recorded and amounts are expected to be fully recoverable through regulatory mechanisms.

AROs — AROs have been recorded for PSCo’s assets.

PSCo’s AROs were as follows:

	2023
(Millions  of Dollars)	Jan. 1, 2023		Accretion		Cash Flow Revisions (a)		Dec. 31, 2023
Electric
Steam, hydro and other production	$	180	$	8	$	—	$	188
Wind	44		2		—		46
Distribution	17		—		—		17
Natural gas
Transmission and distribution	235		11		(114)		132
Total liability	$	476	$	21	$	(114)	$	383

(a)In 2023, AROs were revised for changes in timing and estimates of cash flows. Changes in gas transmission and distribution AROs were primarily the result of changes to inflation and discount rate assumptions as well as updated mileage of gas lines and number of services.

	2022
(Millions  of Dollars)	Jan. 1, 2022		Amounts Incurred (a)		Accretion		Cash Flow Revisions (b)		Dec. 31, 2022
Electric
Steam, hydro and other production	$	152	$	34	$	6	$	(12)	$	180
Wind	42		—		2		—		44
Distribution	16		—		1		—		17
Natural gas
Transmission and distribution	212		—		10		13		235
Total liability	$	422	$	34	$	19	$	1	$	476

(a)Amounts incurred related to steam production pond remediation costs.

(b)In 2022, AROs were revised for changes in timing and estimates of cash flows. Revisions in steam, hydro, and other production AROs 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 PSCo’s facilities, but no confirmation or measurement of the cost of removal could be determined as of Dec. 31, 2023. Therefore, an ARO has not been recorded for these facilities.

Leases

PSCo 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 PSCo's rights to use leased assets. The present value of future operating lease payments is recognized in current and noncurrent operating lease liabilities. These amounts, adjusted for any prepayments or incentives, are recognized as operating lease ROU assets.

Most of PSCo’s leases do not contain a readily determinable discount rate. Therefore, the present value of future lease payments is generally calculated using the estimated incremental borrowing rate (weighted average of 4.2%). For currently existing asset classes, PSCo has elected to utilize the practical expedient under which non-lease components, such as asset maintenance costs included in payments, are not deducted from 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, 2023		Dec. 31, 2022
PPAs	$	623	$	612
Other	112		80
Gross operating lease ROU assets	735		692
Accumulated amortization	(369)		(255)
Net operating lease ROU assets	$	366	$	437

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.

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PSCo’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.

Finance lease ROU assets:

(Millions of Dollars)	Dec. 31, 2023		Dec. 31, 2022
Gas storage facilities	$	160	$	160
Gas pipeline	21		21
Gross finance lease ROU assets	181		181
Accumulated amortization	(67)		(64)
Net finance lease ROU assets	$	114	$	117

Components of lease expense:

(Millions of Dollars)	2023		2022		2021
Operating leases
PPA capacity payments	$	89	$	91	$	102
Other operating leases (a)	19		20		16
Total operating lease expense (b)	$	108	$	111	$	118
Finance leases
Amortization of ROU assets	$	3	$	4	$	7
Interest expense on lease liability	15		16		17
Total finance lease expense	$	18	$	20	$	24

(a)Includes immaterial short-term lease expense of for 2023, 2022 and 2021.

(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, 2023:

(Millions of Dollars)	PPA (a) (b) Operating Leases		Other Operating Leases		Total Operating Leases		Finance Leases
2024	$	98	$	19	$	117	$	18
2025	97		12		109		18
2026	74		8		82		18
2027	44		8		52		16
2028	20		8		28		15
Thereafter	39		6		45		333
Total minimum obligation	372		61		433		418
Interest component of obligation	(35)		(6)		(41)		(304)
Present value of minimum obligation	$	337	$	55	392		114
Less current portion					(102)		(3)
Noncurrent operating and finance lease liabilities					$	290	$	111
Weighted-average remaining lease term in years					4.6		36.8

(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 2032.

PPAs and Fuel Contracts

Non-Lease PPAs — PSCo has entered into PPAs with other utilities and energy suppliers for purchased power to meet system load and energy requirements, operating reserve obligations and as part of wholesale and commodity trading activities. In general, these agreements provide for energy payments, based on actual energy delivered, and may also include capacity payments. Certain PPAs, accounted for as executory contracts with various expiration dates through 2027, contain minimum energy purchase requirements.

Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $3 million, $3 million and $2 million in 2023, 2022 and 2021, respectively.

Capacity and energy payments are contingent on the IPP 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, 2023, the estimated future payments for capacity that PSCo is obligated to purchase pursuant to these executory contracts, subject to availability, were as follows:

(Millions of Dollars)	Capacity
2024	$	3
2025	3
2026	3
2027	1
2028	—
Thereafter	—
Total	$	10

Fuel Contracts — PSCo has entered into various long-term commitments for the purchase and delivery of a significant portion of its coal and natural gas requirements. These contracts expire between 2024 and 2060. PSCo is required to pay additional amounts depending on actual quantities delivered under these agreements.

Estimated minimum purchases under these contracts as of Dec. 31, 2023:

(Millions of Dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2024	$	143	$	221	$	108
2025	74		12		105
2026	39		—		105
2027	35		—		105
2028	—		—		62
Thereafter	—		—		382
Total	$	291	$	233	$	867

VIEs

Under certain PPAs, PSCo purchases power from IPPs for which PSCo is required to reimburse fuel costs, or to participate in tolling arrangements under which PSCo procures the natural gas required to produce the energy that it purchases. PSCo has determined that certain IPPs are VIEs, however PSCo 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.

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PSCo 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. PSCo concluded that these entities are not required to be consolidated in its consolidated financial statements because PSCo does not have the power to direct the activities that most significantly impact the entities’ economic performance. PSCo had approximately 1,207 MW and 1,442 MW of capacity under long-term PPAs at Dec. 31, 2023 and 2022, respectively, with entities that have been determined to be VIEs. These agreements have expiration dates through 2032.

11. Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31:

	2023
(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	$	(20)		$	(2)		$	(22)
Other comprehensive loss before reclassifications	—			—			—
Losses reclassified from net accumulated other comprehensive loss:
Amortization of interest rate hedges	1		(a)	—			1
Amortization of net actuarial loss	—			1		(b)	1
Net current period other comprehensive income	1			1			2
Accumulated other comprehensive loss at Dec. 31	$	(19)		$	(1)		$	(20)

(a)Included in interest charges.

(b)Included in the computation of net periodic pension and postretirement benefit costs. See Note 9 for further information.

	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	$	(21)		$	(1)	$	(22)
Other comprehensive loss before reclassifications	—			(1)		(1)
Losses reclassified from net accumulated other comprehensive loss:
Amortization of interest rate hedges	1		(a)	—		1
Net current period other comprehensive income (loss)	1			(1)		—
Accumulated other comprehensive loss at Dec. 31	(20)			(2)		(22)

(a)Included in interest charges.

12. Segment Information

PSCo evaluates performance based on profit or loss generated from the product or service provided. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment.

PSCo has the following reportable segments:

•Regulated Electric — The regulated electric utility segment generates, purchases, transmits, distributes and sells electricity in Colorado. 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 PSCo’s wholesale commodity and trading operations.

•Regulated Natural Gas — The regulated natural gas utility segment purchases, transports, stores, distributes and sells natural gas in portions of Colorado.

PSCo 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 and non-utility real estate activities.

Asset and capital expenditure information is not provided for PSCo’s reportable segments because as an integrated electric and natural gas utility, PSCo 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.

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PSCo’s segment information:

(Millions of Dollars)	2023		2022		2021
Regulated Electric
Operating revenues — external	$	3,731	$	3,795	$	3,413
Intersegment revenue	1		1		1
Total revenues	$	3,732	$	3,796	$	3,414
Depreciation and amortization	692		650		566
Interest charges and financing costs	224		200		179
Income tax benefit	(2)		(11)		(16)
Net income	529		550		495
Regulated Natural Gas
Total revenues	$	1,734	$	1,860	$	1,355
Depreciation and amortization	224		190		171
Interest charges and financing costs	67		59		53
Income tax expense	37		49		45
Net income	149		180		168
All Other
Total revenues (a)	$	54	$	53	$	47
Depreciation and amortization	8		8		7
Interest charges and financing costs	1		1		2
Income tax (benefit) expense	(6)		(1)		4
Net (loss) income	17		(3)		(3)
Consolidated Total
Total revenues (a)	$	5,520	$	5,709	$	4,816
Reconciling eliminations	(1)		(1)		(1)
Total operating revenues	$	5,519	$	5,708	$	4,815
Depreciation and amortization	924		848		744
Interest charges and financing costs	292		260		234
Income tax expense	29		37		33
Net income	695		727		660

(a)Operating revenues include $5 million of other affiliate revenue for the years ended Dec. 31, 2023, 2022 and 2021, respectively. See Note 13 for further information.

13. Related Party Transactions

Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy Inc., including PSCo. The services are provided and billed to each subsidiary in accordance with service agreements executed by each subsidiary. PSCo uses services provided by Xcel Energy Services Inc. whenever possible. Costs are charged directly to the subsidiary and are allocated if they cannot be directly assigned.

Xcel Energy, Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS have established a utility money pool arrangement.

See Note 5 for further information.

Significant affiliate transactions among the companies and related parties for the years ended Dec. 31:

(Millions of Dollars)	2023		2022		2021
Operating revenues:
Other	$	5	$	5	$	5
Operating expenses:
Other operating expenses — paid to Xcel Energy Services Inc.	679		670		617
Interest expense	5		2		—
Interest income	2		—		—

Accounts receivable and payable with affiliates at Dec. 31:

	2023				2022
(Millions of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Minnesota	$	—	$	5	$	2	$	—
NSP-Wisconsin	—		1		—		2
SPS	—		11		—		11
Other subsidiaries of Xcel Energy Inc.	28		66		9		62
	$	28	$	83	$	11	$	75

14. Workforce Reduction

In 2023, Xcel Energy implemented workforce actions to align resources and investments with evolving business and customer needs, and streamline the organization for long-term success.

In September 2023, Xcel Energy announced a voluntary retirement program to a group of eligible non-bargaining employees, with an enhanced retirement package including certain health care and cash benefits for accepted employees. Approximately 400 employees retired under this program in December 2023.

In November 2023, Xcel Energy, Inc. also reduced its non-bargaining workforce by approximately 150 employees through an involuntary severance program.

In the fourth quarter of 2023, Xcel Energy recorded total expense of $72 million related to these workforce actions, of which $20 million was attributable to PSCo. Expenses relate to the estimated cost of future health plan subsidies and other medical benefits for the voluntary retirement program, as well as severance and other employee payouts and legal and other professional fees.

For further information on the estimated obligations for future health plan subsidies and other medical benefits, see Note 9 to the consolidated financial statements.

ITEM 9 — CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

PSCo 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, 2023, based on an evaluation carried out under the supervision and with the participation of PSCo’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and procedures, the CEO and CFO have concluded that PSCo’s disclosure controls and procedures were effective.

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Internal Control Over Financial Reporting

No changes in PSCo’s internal control over financial reporting occurred during the most recent fiscal quarter ended Dec. 31, 2023 that materially affected, or are reasonably likely to materially affect, PSCo’s internal control over financial reporting. PSCo maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting. PSCo 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, 2023 on internal controls under section 404 of the Sarbanes-Oxley Act of 2002, PSCo conducted testing and monitoring of its internal control over financial reporting. Based on the control evaluation, testing and remediation performed, PSCo 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 PSCo’s Management Report on Internal Controls over Financial Reporting, which is contained in Item 8 herein.

This annual report does not include an attestation report of PSCo’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by PSCo’s independent registered public accounting firm pursuant to the rules of the SEC that permit PSCo to provide only management’s report in this annual report.

ITEM 9B — OTHER INFORMATION

None.

ITEM 9C — DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

PART III

Items 10, 11 and 12 of Part III of Form 10-K have been omitted from this report for PSCo in accordance with conditions set forth in general instructions I(1)(a) and (b) of Form 10-K for wholly-owned subsidiaries.

ITEM 10 — DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

ITEM 11 — EXECUTIVE COMPENSATION

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

ITEM 13 — CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information required under this Item is contained in Xcel Energy Inc.’s definitive Proxy Statement for its 2024 Annual Meeting of Shareholders, which is incorporated by reference.

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 2024 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, 2023.
	Report of Independent Registered Public Accounting Firm — Financial Statements
	Consolidated Statements of Income — For each of the three years ended Dec. 31, 2023, 2022, and 2021.
	Consolidated Statements of Comprehensive Income — For each of the three years ended Dec. 31, 2023, 2022, and 2021.
	Consolidated Statements of Cash Flows — For each of the three years ended Dec. 31, 2023, 2022, and 2021.
	Consolidated Balance Sheets — As of Dec. 31, 2023, 2022.
	Consolidated Statements of Common Stockholder’s Equity — For each of the three years ended Dec. 31, 2023, 2022, and 2021.
2	Schedule II — Valuation and Qualifying Accounts and Reserves for each of the years ended Dec. 31, 2023, 2022, and 2021.
3	Exhibits
*	Indicates incorporation by reference
+	Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors

Exhibit Number	Description	Report or Registration Statement	Exhibit Reference
3.01*	Amended and Restated Articles of Incorporation dated July 15, 1998	PSCo Form 10-Q for the quarter ended Sept. 30, 2017	3.01
3.02*	By-Laws of PSCo as Amended and Restated on Jan. 25, 2019	PSCo Form 10-K for the year ended Dec. 31, 2018	3.02
4.01*	Indenture, dated as of Oct. 1, 1993, by and between PSCo and U.S. Bank Trust Company, National Association (as successor to Morgan Guaranty Trust Company of New York), as Trustee, providing for the issuance of First Collateral Trust Bonds	Xcel Energy Inc. Form S-3 dated April 18, 2018	4(d)(3)

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4.02*	Supplemental Indenture No. 17, dated as of Aug. 1, 2007, by and between PSCo and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $350 million of 6.25% First Mortgage Bonds, Series No. 17 due Sept. 1, 2037	PSCo Form 8-K dated Aug. 8, 2007	4.01
4.03*	Supplemental Indenture No. 18, dated as of Aug. 1, 2008, by and between PSCo and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association, as Trustee, creating $300 million aggregate principal amount of 6.50% First Mortgage Bonds, Series No. 19 due Aug. 1, 2038	PSCo Form 8-K dated Aug. 6, 2008	4.01
4.04*	Supplemental Indenture No. 21, dated as of Aug. 1, 2011, by and between PSCo and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $250 million aggregate principal amount of 4.75% First Mortgage Bonds, Series No. 22 due Aug. 15, 2041	PSCo Form 8-K dated Aug. 9, 2011	4.01
4.05*	Supplemental Indenture No. 22, dated as of Sept. 1, 2012, between PSCo and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $500 million aggregate principal amount of 3.60% First Mortgage Bonds, Series No. 24 due Sept. 15, 2042	PSCo Form 8-K dated Sept. 11, 2012	4.01
4.06*	Supplemental Indenture No. 23, dated as of March 1, 2013, by and between PSCo and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $250 million aggregate principal amount of 2.50% First Mortgage Bonds, Series No. 25 due March 15, 2023 and $250 million aggregate principal amount of 3.95% First Mortgage Bonds, Series No. 26 due March 15, 2043	PSCo Form 8-K dated March 26, 2013	4.01
4.07*	Supplemental Indenture No. 24, dated as of March 1, 2014, by and between PSCo and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $300 million aggregate principal amount of 4.30% First Mortgage Bonds, Series No. 27 due March 15, 2044	PSCo Form 8-K dated March 10, 2014	4.01
4.08*	Supplemental Indenture No. 25, dated as of May 1, 2015, by and between PSCo and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $250 million aggregate principal amount of 2.90% First Mortgage Bonds, Series No. 28 due May 15, 2025	PSCo Form 8-K dated May 12, 2015	4.01
4.09*	Supplemental Indenture No. 26, dated as of June 1, 2016, by and between PSCo and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $250 million aggregate principal amount of 3.55% First Mortgage Bonds, Series No. 29 due June 15, 2046	PSCo Form 8-K dated June 13, 2016	4.01
4.10*	Supplemental Indenture No. 27, dated as of June 1, 2017, by and between PSCo and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $400 million aggregate principal amount of 3.80% First Mortgage Bonds, Series No. 30 due June 15, 2047	PSCo Form 8-K dated June 19, 2017	4.01
4.11*	Supplemental Indenture No. 28, dated as of June 1, 2018, by and between PSCo and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $350 million aggregate principal amount of 3.70% First Mortgage Bonds, Series No. 31 due June 15, 2028, and $350 million aggregate principal amount of 4.10% First Mortgage Bonds, Series No. 32 due June 15, 2048	PSCo Form 8-K dated June 21, 2018	4.01
4.12*	Supplemental Indenture No. 29, dated as of March 1, 2019, by and between PSCo and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $400 million aggregate principal amount of 4.05% First Mortgage Bonds, Series No. 33 due Sept. 15, 2049	PSCo Form 8-K dated March 13, 2019	4.01
4.13*	Supplemental Indenture No. 30, dated as of Aug. 1, 2019, by and between PSCo and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $550 million aggregate principal amount of 3.20% First Mortgage Bonds, Series No. 34 due March 1, 2050	PSCo Form 8-K dated August 13, 2019	4.01
4.14*	Supplemental Indenture No. 31, dated as of May 1, 2020, by and between PSCo and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $375 million aggregate principal amount of 2.70% First Mortgage Bonds, Series No. 35 due Jan. 15, 2051 and $375 million aggregate principal amount of 1.90% First Mortgage Bonds, Series No. 36 due Jan. 15, 2031	PSCo Form 8-K dated May 15, 2020	4.01
4.15*	Supplemental Indenture No. 32, dated as of February 1, 2021, by and between PSCo and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $750 million aggregate principal amount of 1.875% First Mortgage Bonds, Series No. 37 due June 15, 2031	PSCo Form 8-K dated March 1, 2021	4.01
4.16*	Supplemental Indenture No. 33, dated as of May 1, 2022, by and between PSCo and U.S. Bank Trust Company, National Association, as Trustee, creating $300 million aggregate principal amount of 4.10% First Mortgage Bonds, Series No. 38 due June 1, 2032 and $400 million aggregate principal amount of 4.50% First Mortgage Bonds, Series No. 39 due June 1, 2052	PSCo Form 8-K dated May 17, 2022	99.03
4.17*	Supplemental Indenture No. 34, dated as of March 1, 2023, between PSCo and U.S. Bank Trust Company, National Association, as successor Trustee, creating $850 million principal amount of 5.25% First Mortgage Bonds, Series No. 40 due April 1, 2053.	PSCo Form 8-K dated April 3, 2023	4.01
10.01*	Xcel Energy Inc. Nonqualified Pension Plan (2009 Restatement)	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008	10.02
10.02*+	Xcel Energy Senior Executive Severance and Change-in-Control Policy (2009 Restatement)	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008	10.05
10.03*+	Second Amendment to Exhibit 10.02 dated Oct. 26, 2011	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011	10.18
10.04*+	Fifth Amendment to Exhibit 10.02 dated May 3, 2016	Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2016	10.01
10.05*+	Seventh Amendment to Exhibit 10.02 dated May 7, 2018	Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2018	10.01
10.06*+	Eighth Amendment to Exhibit 10.02 dated March 31, 2020	Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2020	10.02
10.07*+	Ninth Amendment to Exhibit 10.02 dated May 22, 2020	Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2020	10.01
10.08*+	Xcel Energy Inc. Supplemental Executive Retirement Plan as amended and restated Jan. 1, 2009	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008	10.17
10.09*+	Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement)	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008	10.07
10.10*+	First Amendment to Exhibit 10.09 effective Nov. 29, 2011	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011	10.17
10.11*+	Second Amendment to Exhibit 10.09 dated May 21, 2013	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2013	10.22
10.12*+	Third Amendment to Exhibit 10.09 dated Sept. 30, 2016	Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2016	10.01

50

10.13*+	Fourth Amendment to Exhibit 10.09 dated Oct. 23, 2017	Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2017	10.1
10.14*+	Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018	10.34
10.15*+	Form of Award Agreement for Restricted Stock Units and/or Performance Share Units under the Xcel Energy Inc. 2015 Omnibus Incentive Plan for awards between 2020-2023	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2019	10.32
10.16+	Form of Award Agreement for Restricted Stock Units and/or Performance Share Units under the Xcel Energy Inc. 2015 Omnibus Incentive Plan for awards since 2024	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2023	10.16
10.17*+	Form of Award Agreement for Retention-Based Restricted Stock Units under the Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 8-K dated Dec. 10, 2021	10.01
10.18+	Xcel Energy Inc. Annual Incentive Plan, effective Feb. 21, 2024	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2023	10.18
10.19*+	Summary of Non-Employee Director Compensation, effective as of May 24, 2023	Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2023	10.01
10.20*+	Stock Equivalent Plan for Non-Employee Directors of Xcel Energy Inc. as amended and restated effective Feb. 23, 2011	Xcel Energy Inc. Definitive Proxy Statement dated April 5, 2011	Appendix A
10.21*+	Stock Program for Non-Employee Directors of Xcel Energy Inc. as Amended and Restated on Dec. 12, 2017 under the 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018	10.36
10.22*+	Form of Services Agreement between Xcel Energy Services Inc. and utility companies	Xcel Energy Inc. Form U5B dated Nov. 16, 2000	H-1
10.23*	Fourth Amended and Restated Credit Agreement, dated as of September 19, 2022, among PSCo, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank PLC, as Syndication Agents, and Citibank, N.A., MUFG Bank, Ltd., and Wells Fargo Bank, National Association, as Documentation Agents	Xcel Energy Inc. Form 8-K dated Sept. 19, 2022	99.03
23.01	Consent of Independent Registered Public Accounting Firm.
31.01	Principal Executive Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH	Inline XBRL Schema
101.CAL	Inline XBRL Calculation
101.DEF	Inline XBRL Definition
101.LAB	Inline XBRL Label
101.PRE	Inline XBRL Presentation
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

SCHEDULE II

Public Service Co. of Colorado and Subsidiaries Valuation and Qualifying Accounts Years Ended Dec. 31

	Allowance for bad debts
(Millions of Dollars)	2023		2022		2021
Balance at Jan. 1	$	54	$	40	$	29
Additions charged to costs and expenses	34		38		26
Additions charged to other accounts (a)	5		18		4
Deductions from reserves (b)	(37)		(42)		(19)
Balance at Dec. 31	$	56	$	54	$	40

(a)Recovery of amounts previously written-off.

(b)Deductions related primarily to bad debt write-offs.

Item 16 — Form 10-K Summary

None.

51

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.

	PUBLIC SERVICE COMPANY OF COLORADO
Feb. 21, 2024	/s/ BRIAN J. VAN ABEL
	Brian J. Van Abel
	Executive Vice President, Chief Financial Officer and Director

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.

/s/ ROBERT C. FRENZEL	/s/ ROBERT S. KENNEY
Robert C. Frenzel	Robert S. Kenney
Chairman, Chief Executive Officer and Director	President and Director
(Principal Executive Officer)
/s/ BRIAN J. VAN ABEL
Brian J. Van Abel
Executive Vice President, Chief Financial Officer and Director
(Principal Accounting Officer and Principal Financial Officer)

SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(D) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT

PSCo has not sent, and does not expect to send, an annual report or proxy statement to its security holder.

52

EX-23.01

Exhibit 23.01

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-255446-02 on Form S-3 of our report dated February 21, 2024, relating to the financial statements and financial statement schedule of Public Service Company of Colorado and subsidiaries appearing in this Annual Report on Form 10-K of Public Service Company of Colorado for the year ended December 31, 2023.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 21, 2024

EX-31.01

Exhibit 31.01

CERTIFICATION

I, Robert C. Frenzel, certify that:

1.I have reviewed this report on Form 10-K of Public Service Company of Colorado;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: Feb. 21, 2024

/s/ ROBERT C. FRENZEL

Robert C. Frenzel

Chairman, Chief Executive Officer and Director

1

EX-31.02

Exhibit 31.02

CERTIFICATION

I, Brian J. Van Abel, certify that:

1.I have reviewed this report on Form 10-K of Public Service Company of Colorado;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: Feb. 21, 2024

/s/ BRIAN J. VAN ABEL

Brian J. Van Abel

Executive Vice President, Chief Financial Officer and Director

2

EX-32.01

Exhibit 32.01

OFFICER CERTIFICATION

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Public Service Company of Colorado (PSCo) on Form 10-K for the year ended Dec. 31, 2023, as filed with the SEC on the date hereof (Form 10-K), each of the undersigned officers of PSCo certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer’s knowledge:

(1)The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of PSCo as of the dates and for the periods expressed in the Form 10-K.

Date: Feb. 21, 2024

/s/ ROBERT C. FRENZEL

Robert C. Frenzel

Chairman, Chief Executive Officer and Director

/s/ BRIAN J. VAN ABEL

Brian J. Van Abel

Executive Vice President, Chief Financial Officer and Director

The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document.

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to PSCo and will be retained by PSCo and furnished to the SEC or its staff upon request.

1

XML

Cover Page - USD ($)	12 Months Ended
	Dec. 31, 2023	Feb. 21, 2024	Jun. 30, 2023
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2023
Document Transition Report	false
Entity File Number	001-03280
Entity Registrant Name	PUBLIC SERVICE CO OF COLORADO
Entity Incorporation, State or Country Code	CO
Entity Tax Identification Number	84-0296600
Entity Address, Address Line One	1800 Larimer, Suite 1100
Entity Address, City or Town	Denver
Entity Address, State or Province	CO
Entity Address, Postal Zip Code	80202
City Area Code	303
Local Phone Number	571-7511
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		100
Entity Central Index Key	0000081018
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Public Float			$ 0
Document Financial Statement Error Correction [Flag]	false

XML

Audit Information	12 Months Ended
	Dec. 31, 2023
Auditor Information [Abstract]
Auditor Name	DELOITTE & TOUCHE LLP
Auditor Firm ID	34
Auditor Location	Minneapolis, Minnesota

XML

Accounting Pronouncements

12 Months Ended

Dec. 31, 2023

Accounting Standards Update and Change in Accounting Principle [Abstract]

Accounting Pronouncements

Recently Issued

Segment Reporting — In November 2023, the FASB issued ASU 2023-07 – Segment Reporting (Topic 280) – Improvements to Reportable Segment Disclosures, which extends the existing requirements for annual disclosures to quarterly periods, and requires that both annual and quarterly disclosures present segment expenses using line items consistent with information regularly provided to the chief operating decision maker. The ASU is effective for annual periods beginning after Dec. 15, 2023 and quarterly periods beginning after Dec. 15, 2024, and PSCo does not expect implementation of the new disclosure guidance to have a material impact to its consolidated financial statements.

Income Taxes — In December 2023, the FASB issued ASU 2023-09 – Income Taxes (Topic 740) – Improvements to Income Tax Disclosures, with new disclosure requirements including presentation of prescribed line items in the effective tax rate reconciliation and disclosures regarding state and local tax payments. The ASU is effective for annual periods beginning after Dec. 15, 2024, and PSCo does not expect implementation of the new disclosure guidance to have a material impact to its consolidated financial statements.

XML

CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Operating revenues
Electric	$ 3,731	$ 3,795	$ 3,413
Natural gas	1,734	1,860	1,355
Other	54	53	47
Total operating revenues	5,519	5,708	4,815
Operating expenses
Electric fuel and purchased power	1,364	1,485	1,336
Cost of natural gas sold and transported	910	1,053	606
Cost of sales — steam and other	17	18	15
Operating and maintenance expenses	865	905	831
Demand side management expenses	135	133	132
Depreciation and amortization	924	848	744
Taxes (other than income taxes)	287	272	256
Gain (Loss) Related to Litigation Settlement	(35)	0	0
Workforce Reduction Expense	20	0	0
Total operating expenses	4,557	4,714	3,920
Operating income	962	994	895
Other income (expense), net	15	(2)	4
Allowance for funds used during construction — equity	39	32	28
Interest charges and financing costs
Interest charges — includes other financing costs of $8, $8 and $8, respectively	(312)	(271)	(243)
Allowance for funds used during construction — debt	(20)	(11)	(9)
Total interest charges and financing costs	292	260	234
Income before income taxes	724	764	693
Income tax expense	29	37	33
Net income	$ 695	$ 727	$ 660

XML

CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Statement of Financial Position [Abstract]
Other financing costs	$ 8	$ 8	$ 8
Gain (Loss) Related to Litigation Settlement	35	0	0
Workforce Reduction Expense	$ 20	$ 0	$ 0

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Comprehensive income:
Net income	$ 695	$ 727	$ 660
Net pension and retiree medical gain (loss) arising during the period, net of tax	0	(1)	0
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), Reclassification Adjustment from AOCI, before Tax	1	0	0
Derivative instruments:
Reclassification of loss to net income, net of tax	1	1	2
Total other comprehensive income	2	0	2
Total comprehensive income	$ 697	$ 727	$ 662

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Operating activities
Net income	$ 695	$ 727	$ 660
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	929	854	754
Deferred income taxes	(138)	(10)	21
Allowance for equity funds used during construction	(39)	(32)	(28)
Provision for bad debts	34	38	26
Changes in operating assets and liabilities:
Accounts receivable	36	(227)	(58)
Accrued unbilled revenues	158	(169)	(52)
Inventories	(14)	(86)	(71)
Other current assets	22	12	(23)
Accounts payable	(107)	183	66
Net regulatory assets and liabilities	270	82	(526)
Other current liabilities	97	8	30
Pension and other employee benefit obligations	11	(13)	(53)
Other, net	0	(112)	(19)
Net cash provided by operating activities	1,954	1,255	727
Investing activities
Utility capital/construction expenditures	(2,360)	(1,880)	(1,604)
Investments in utility money pool arrangement	(367)	(45)	(273)
Repayments from utility money pool arrangement	367	45	273
Net cash used in investing activities	(2,360)	(1,880)	(1,604)
Financing activities
Proceeds from short-term borrowings, net	26	146	11
Borrowings under utility money pool arrangement	781	1,199	743
Repayments under utility money pool arrangement	(730)	(1,199)	(800)
Proceeds from issuance of long-term debt	834	686	737
Repayments of long-term debt	(250)	(300)	0
Capital contributions from parent	400	569	650
Dividends paid to parent	(652)	(491)	(467)
Net cash provided by financing activities	409	610	874
Net change in cash and cash equivalents	3	(15)	(3)
Cash, cash equivalents and restricted cash at beginning of period	10	25	28
Cash, cash equivalents and restricted cash at end of period	13	10	25
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(271)	(250)	(230)
Cash paid for income taxes, net	(126)	(79)	(14)
Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions	248	233	157
Inventory transfers to property, plant and equipment	75	12	10
Operating lease right-of-use assets	18	140	0
Allowance for equity funds used during construction	$ 39	$ 32	$ 28

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Current assets
Cash, cash equivalents and restricted cash at end of period	$ 13	$ 10
Accrued unbilled revenues	361	519
Inventories	258	319
Regulatory assets	304	411
Derivative instruments	11	65
Prepayments and other	95	103
Total current assets	1,562	2,000
Property, plant and equipment, net	21,035	19,652
Other assets
Regulatory assets	1,267	1,277
Derivative instruments	15	22
Operating lease right-of-use assets	366	437
Other	383	231
Total other assets	2,031	1,967
Total assets	24,628	23,619
Current liabilities
Current portion of long-term debt	0	250
Borrowings under utility money pool arrangement	51	0
Short-term debt	320	294
Regulatory liabilities	70	59
Taxes accrued	261	242
Accrued interest	68	59
Dividends payable to parent	72	120
Derivative instruments	17	30
Operating lease liabilities	102	80
Other	177	115
Total current liabilities	1,925	2,088
Deferred credits and other liabilities
Deferred income taxes	1,894	1,983
Regulatory liabilities	2,562	2,489
Asset retirement obligations	383	476
Derivative instruments	0	9
Customer advances	124	144
Pension and employee benefit obligations	40	13
Operating lease liabilities	290	379
Other	218	198
Total deferred credits and other liabilities	5,511	5,691
Commitments and contingencies
Capitalization
Long-term debt	7,450	6,610
Common stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2023 and Dec. 31, 2022, respectively	$ 0	$ 0
Common Stock, Shares Authorized	100	100
Common Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Common Stock, Shares, Outstanding	100	100
Additional paid in capital	$ 7,412	$ 6,992
Retained earnings	2,350	2,260
Accumulated other comprehensive loss	(20)	(22)
Total common stockholder's equity	9,742	9,230
Total liabilities and stockholder's equity	24,628	23,619
Affiliated Entity
Current assets
Accounts receivable, net	28	11
Current liabilities
Accounts payable	83	75
Related Party
Current assets
Accounts receivable, net	492	562
Current liabilities
Accounts payable	$ 704	$ 764

XML

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY - USD ($) $ in Millions	Total	Common stock	Additional Paid In Capital	Retained Earnings	Accumulated Other Comprehensive Income (Loss)
Balance (in shares) at Dec. 31, 2020		100
Beginning Balance at Dec. 31, 2020	$ 7,592	$ 0	$ 5,770	$ 1,846	$ (24)
Increase (Decrease) in Stockholder's Equity
Net income	660			660
Total other comprehensive income	2				2
Common dividends declared to parent	(466)			(466)
Contribution of capital by parent	656		656
Balance (in shares) at Dec. 31, 2021		100
Ending Balance at Dec. 31, 2021	8,444	$ 0	6,426	2,040	(22)
Increase (Decrease) in Stockholder's Equity
Net income	727			727
Total other comprehensive income	0
Common dividends declared to parent	(507)			(507)
Contribution of capital by parent	$ 566		566
Balance (in shares) at Dec. 31, 2022	100	100
Ending Balance at Dec. 31, 2022	$ 9,230	$ 0	6,992	2,260	(22)
Increase (Decrease) in Stockholder's Equity
Net income	695			695
Total other comprehensive income	2				2
Common dividends declared to parent	(605)			(605)
Contribution of capital by parent	$ 420		420
Balance (in shares) at Dec. 31, 2023	100	100
Ending Balance at Dec. 31, 2023	$ 9,742	$ 0	$ 7,412	$ 2,350	$ (20)

XML

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2023

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

General — PSCo is engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and the regulated purchase, transportation, distribution and sale of natural gas. 

PSCo’s consolidated financial statements include its wholly-owned subsidiaries. In the consolidation process, all intercompany transactions and balances are eliminated. PSCo has investments in several plants and transmission facilities jointly owned with nonaffiliated utilities. 

PSCo’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets, and PSCo’s proportionate share of operating costs associated with these facilities is included in its consolidated statements of income. 

PSCo’s consolidated financial statements are presented in accordance with GAAP. All of PSCo’s underlying accounting records also conform to the FERC uniform system of accounts or to systems required by its state regulatory commission. 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.

PSCo has evaluated events occurring after Dec. 31, 2023 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 — PSCo uses estimates based on the best information available to record 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 — PSCo accounts for income and expense items in accordance with accounting guidance for regulated operations. Under this guidance:

•Certain costs, which would otherwise be charged to expense or other comprehensive income, are deferred as regulatory assets based on the expected ability to recover the costs in future rates.

•Certain credits, which would otherwise be reflected as income or other comprehensive income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred.

Estimates and assumptions for recovery of deferred costs and refund of deferred credits are based on specific ratemaking decisions, precedent or other available information. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process.

If changes in the regulatory environment occur, PSCo 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 PSCo’s results of operations, financial condition and cash flows.

See Note 4 for further information.

Income Taxes — PSCo accounts for income taxes using the asset and liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the consolidated financial statements. Income taxes are deferred for all temporary differences between pretax financial and taxable income and between the book and tax bases of assets and liabilities utilizing rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the period that includes the enactment date.

Utility rate regulation has resulted in the recognition of regulatory assets and liabilities related to income taxes. The effects of PSCo’s tax rate changes are generally subject to a normalization method of accounting. Therefore, the revaluation of most of its 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. PSCo 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.

Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize over the book depreciable lives of related property. The requirement to defer and amortize these credits specifically applies to certain federal ITCs, as determined by tax regulations and PSCo tax elections. For tax credits otherwise eligible to be recognized when earned, PSCo 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. This evaluation includes consideration of whether tax credits are expected to be sold at a discount and impact the realization of amounts presented as deferred tax assets. Transferable tax credits are accounted for under ASC 740 Income Taxes, and valuation allowances and any adjustments for discounts incurred on sales transactions are recorded to deferred tax expense, typically recovered in regulatory mechanisms.

PSCo 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 income (expense), net or interest charges in the consolidated statements of income.

Xcel Energy Inc. and its subsidiaries, including PSCo 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 and replacement of items determined to be less than a unit of property are charged to expense 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 3.6% in 2023, 3.4% in 2022 and 3.2% in 2021.

See Note 3 for further information.

AROs — PSCo records AROs as a liability in the period incurred (if fair value can be reasonably estimated), with the offsetting/associated costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion and the capitalized costs are typically depreciated over the useful life of the long-lived asset. Changes resulting from revisions to timing or amounts of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO.

See Note 10 for further information.

Benefit Plans and Other Postretirement Benefits — PSCo maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans requires management to make various assumptions and estimates.

Certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are deferred as regulatory assets and liabilities, rather than recorded as other comprehensive income, based on regulatory recovery mechanisms.

See Note 9 for further information.

Environmental Costs — Environmental costs are recorded when it is probable PSCo is liable for remediation costs and the amount can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. For certain environmental costs related to facilities currently in use, such as for emission-control equipment, the cost is capitalized and depreciated over the life of the plant.

Estimated remediation costs are regularly adjusted as estimates are revised and remediation is performed. If other participating potentially responsible parties exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for PSCo’s expected share of the cost. 

Estimated future expenditures to restore sites are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.

See Note 10 for further information.

Revenue from Contracts with Customers — Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. PSCo 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.

PSCo recognizes physical sales to customers (native load and wholesale) on a gross basis in electric revenues and cost of sales. PSCo participates in SPP WEIS. Revenues for short-term physical wholesale sales of excess energy transacted through the imbalance market are recorded on a gross basis. Other revenues and charges settled/facilitated through SPP WEIS are recorded on a net basis in cost of sales.

See Note 6 for further information.

Cash and Cash Equivalents — PSCo considers investments in instruments with a remaining maturity of 3 months or less at the time of purchase to be cash equivalents.

Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. PSCo 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, 2023 and 2022, the allowance for bad debts was $56 million and $54 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, 2023		Dec. 31, 2022
Inventories
Materials and supplies	$	91	$	80
Fuel	83		68
Natural gas	84		171
Total inventories	$	258	$	319

Fair Value Measurements — PSCo presents cash equivalents, interest rate derivatives and commodity derivatives at estimated fair values in its consolidated financial statements. 

For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used to estimate fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price, quoted prices for similar contracts or internally prepared valuation models may be used to determine fair value.

For the pension and postretirement plan assets and nuclear decommissioning fund, published trading data and pricing models, generally using the most observable inputs available, are utilized to determine fair value for each security.

See Notes 8 and 9 for further information.

Derivative Instruments — PSCo 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. Derivatives 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 — PSCo enters into contracts for purchases and sales of commodities for use in its operations. At inception, contracts are evaluated to determine whether they contain a derivative, and if so, whether they may be exempted from derivative accounting if designated as normal purchases or normal sales.

See Note 8 for further information.

Commodity Trading Operations — All applicable gains and losses related to commodity trading activities are shown on a net basis in electric operating revenues in the consolidated statements of income.

Commodity trading activities are not associated with energy produced from PSCo’s generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms. 

See Note 8 for further information

Other Utility Items

AFUDC — AFUDC represents the cost of capital used to finance utility construction activity and is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in PSCo’s rate base.

Alternative Revenue — Certain rate rider mechanisms (including decoupling and 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 — PSCo has implemented programs to assist its retail customers in conserving energy and reducing peak demand on the electric and natural gas systems. These programs include approximately 20 unique DSM products, pilots and services for C&I customers, as well as approximately 23 DSM products, pilots and services for residential and low-income customers. Overall, the DSM portfolio provides rebates and/or incentives for nearly 1,000 unique measures.

The costs incurred for DSM programs are deferred if it is probable future revenue will be provided to permit recovery of the incurred cost. Revenues recognized for incentive programs designed for recovery of DSM program costs and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the year in which they are earned.

PSCo’s DSM program costs are recovered through a combination of base rate revenue and rider mechanisms. 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.

RECs — Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. An inventory accounting model is used to account for RECs.

Sales of RECs are recorded in electric revenues on a gross basis. Cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.

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Property Plant and Equipment Property Plant and Equipment

12 Months Ended

Dec. 31, 2023

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment Disclosure

Major classes of property, plant and equipment

(Millions of Dollars)	Dec. 31, 2023		Dec. 31, 2022
Property, plant and equipment, net
Electric plant	$	16,698	$	15,771
Natural gas plant	6,321		5,949
Common and other property	1,472		1,415
Plant to be retired (a)	1,203		1,305
CWIP	1,310		877
Total property, plant and equipment	27,004		25,317
Less accumulated depreciation	(5,969)		(5,665)
Property, plant and equipment, net	$	21,035	$	19,652

(a)Amounts include Comanche Units 2 and 3, Craig Units 1 and 2, Hayden Units 1 and 2 and coal generation assets at Pawnee pending facility gas conversion. Amounts are presented net of accumulated depreciation.

Joint Ownership of Generation, Transmission and Gas Facilities

Jointly owned assets as of Dec. 31, 2023:

(Millions of Dollars, Except Percent Owned)	Plant in Service		Accumulated Depreciation		Percent Owned
Electric generation:
Hayden Unit 1	$	157	$	108	76	%
Hayden Unit 2	151		87		37
Hayden common facilities	44		31		53
Craig Units 1 and 2	82		55		10
Craig common facilities	39		25		7
Comanche Unit 3	916		191		67
Comanche common facilities	29		4		77
Electric transmission:
Transmission and other facilities	189		75		Various
Gas transmission:
Rifle, CO to Avon, CO	28		9		60
Gas transmission compressor	8		2		50
Total (a)	$	1,643	$	587

(a)Projects additionally include $18 million in CWIP.

PSCo’s share of operating expenses and construction expenditures is included in the applicable utility accounts. Respective owners are responsible for providing their own financing.

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Regulatory Assets and Liabilities

12 Months Ended

Dec. 31, 2023

Regulatory Assets and Liabilities Disclosure [Abstract]

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. PSCo 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, 2023				Dec. 31, 2022
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Pension and retiree medical obligations	9	Various	$	2	$	396	$	3	$	367
Net AROs (a)	1, 10	Various	—		236		—		212
Depreciation differences		One to 10 years	16		184		16		187
Recoverable deferred taxes on AFUDC		Plant lives	—		135		—		119
Excess deferred taxes — TCJA	7	Various	—		55		2		54
Environmental remediation costs		Various	—		44		6		26
Conservation programs (b)	1	One to two years	12		33		8		16
Revenue decoupling		Various	—		31		—		—
Gas pipeline inspection costs		One to two years	3		25		—		13
Deferred natural gas, electric, steam energy/fuel costs		One to three years	221		22		312		200
Purchased power contract costs		Term of related contract	4		20		3		16
Grid modernization costs		Two years	15		14		14		22
Property tax		Various	3		7		8		2
Other		Various	28		65		39		43
Total regulatory assets			$	304	$	1,267	$	411	$	1,277

(a)Includes amounts recorded for future recovery of AROs.

(b)Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

Components of regulatory liabilities:

(Millions of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2023				Dec. 31, 2022
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Deferred income tax adjustments and TCJA refunds (a)	7	Various	$	2	$	1,260	$	2	$	1,298
Plant removal costs	1, 10	Various	—		769		—		705
Effects of regulation on employee benefit costs (b)		Various	—		234		—		227
Renewable resources and environmental initiatives		Various	—		152		—		141
Revenue decoupling		Various	—		63		—		55
ITC deferrals	1	Various	1		44		1		41
Deferred natural gas, electric, steam energy/fuel costs		Less than one year	34		—		3		—
Conservation programs	1	Less than one year	9		—		19		—
Formula rates		One to two years	8		—		16		—
Other		Various	16		40		18		22
Total regulatory liabilities			$	70	$	2,562	$	59	$	2,489

(a)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.

(b)Includes regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the prepaid pension asset.

PSCo’s regulatory assets not earning a return include past expenditures of $416 million and $538 million at Dec. 31, 2023 and 2022, respectively, which predominately relate to purchased natural gas and electric energy costs (including certain costs related to Winter Storm Uri), sales true-up and revenue decoupling and various renewable resources/environmental initiatives. Additionally, the unfunded portion of pension and retiree medical obligations and net AROs (i.e. deferrals for which cash has not been disbursed) do not earn a return.

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Borrowings and Other Financing Instruments

12 Months Ended

Dec. 31, 2023

Debt Disclosure [Abstract]

Borrowings and Other Financing Instruments

5. Borrowings and Other Financing Instruments

Short-Term Borrowings

PSCo meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility and the money pool.

Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc.

Money pool borrowings:

(Millions of Dollars, Except Interest Rates)	Three Months Ended Dec. 31, 2023			Year Ended Dec. 31
				2023			2022			2021
Borrowing limit	$	250		$	250		$	250		$	250
Amount outstanding at period end	51			51			—			—
Average amount outstanding	64			23			29			12
Maximum amount outstanding	250			250			250			243
Weighted average interest rate, computed on a daily basis	5.33		%	5.31		%	1.66		%	0.07		%
Weighted average interest rate at end of period	5.34			5.34			N/A			N/A

Commercial Paper — Commercial paper borrowings:

(Millions of Dollars, Except Interest Rates)	Three Months Ended Dec. 31, 2023			Year Ended Dec. 31
				2023			2022			2021
Borrowing limit	$	700		$	700		$	700		$	700
Amount outstanding at period end	320			320			294			147
Average amount outstanding	189			124			71			26
Maximum amount outstanding	369			454			328			322
Weighted average interest rate, computed on a daily basis	5.53		%	5.17		%	2.56		%	0.19		%
Weighted average interest rate at end of period	5.56			5.56			4.73			0.22

Letters of Credit — PSCo uses letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2023 and 2022, there were $29 million and $27 million of letters of credit outstanding under the credit facility, respectively. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, PSCo must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under this credit facility. The credit facility provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

Features of PSCo’s credit facility:

Debt-to-Total Capitalization Ratio (a)				Amount Facility May Be Increased (millions of dollars)		Additional Periods for Which a One-Year Extension May Be Requested (b)
2023		2022
44.8	%	44.0	%	$	100	2

(a)The credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%.

(b)All extension requests are subject to majority bank group approval.

The credit facility has a cross-default provision that provides PSCo would be in default on its borrowings under the facility if PSCo or any of its subsidiaries whose total assets exceed 15% of PSCo’s consolidated total assets, default on indebtedness in an aggregate principal amount exceeding $75 million.

If PSCo does not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2023, PSCo was in compliance with all financial covenants.

PSCo had the following committed credit facility available as of Dec. 31, 2023 (in millions of dollars):

Credit Facility (a)		Drawn (b)		Available
$	700	$	349	$	351

(a)This credit facility matures in September 2027.

(b)Includes letters of credit and outstanding commercial paper.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. PSCo had no direct advances on the facility outstanding at Dec. 31, 2023 and 2022.

Long-Term Borrowings and Other Financing Instruments

Generally, the property of PSCo is subject to the lien of its first mortgage indenture for the benefit of bondholders. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses for refinanced debt are deferred and amortized over the life of the new issuance.

Long-term debt obligations for PSCo as of Dec. 31 (in millions of dollars):

Financing Instrument	Interest Rate		Maturity Date	2023		2022
First mortgage bonds	2.50	%	March 15, 2023	$	—	$	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	1.875		June 15, 2031	750		750
First mortgage bonds (a)	4.10		June 1, 2032	300		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 (a)	4.50		June 1, 2052	400		400
First mortgage bonds (b)	5.25		April 1, 2053	850		—
Unamortized discount				(41)		(37)
Unamortized debt issuance cost				(59)		(53)
Current maturities				—		(250)
Total long-term debt				$	7,450	$	6,610

(a)2022 financing.

(b)2023 financing.

Maturities of long-term debt:

(Millions of Dollars)
2024	$	—
2025	250
2026	—
2027	—
2028	350

Deferred Financing Costs — Deferred financing costs of approximately $59 million and $53 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt as of Dec. 31, 2023 and 2022, respectively. 

Capital Stock — PSCo has authorized the issuance of preferred stock.

Preferred Stock Authorized (Shares)	Par Value of Preferred Stock		Preferred Stock Outstanding (Shares) 2023 and 2022
10,000,000	$	0.01	—

Dividend Restrictions — PSCo’s 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.

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Revenues

12 Months Ended

Dec. 31, 2023

Revenue from Contract with Customer [Abstract]

Revenues

Revenue is classified by the type of goods/services rendered and market/customer type. PSCo’s operating revenues consisted of the following:

	Year Ended Dec. 31, 2023
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	1,295	$	1,109	$	19	$	2,423
C&I	1,816		459		30		2,305
Other	52		—		5		57
Total retail	3,163		1,568		54		4,785
Wholesale	237		—		—		237
Transmission	90		—		—		90
Other	61		132		—		193
Total revenue from contracts with customers	3,551		1,700		54		5,305
Alternative revenue and other	180		34		—		214
Total revenues	$	3,731	$	1,734	$	54	$	5,519

	Year Ended Dec. 31, 2022
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	1,341	$	1,203	$	15	$	2,559
C&I	1,843		479		32		2,354
Other	52		—		—		52
Total retail	3,236		1,682		47		4,965
Wholesale	286		—		—		286
Transmission	88		—		—		88
Other	53		151		—		204
Total revenue from contracts with customers	3,663		1,833		47		5,543
Alternative revenue and other	132		27		6		165
Total revenues	$	3,795	$	1,860	$	53	$	5,708

	Year Ended Dec. 31, 2021
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	1,174	$	816	$	12	$	2,002
C&I	1,660		308		30		1,998
Other	49		—		—		49
Total retail	2,883		1,124		42		4,049
Wholesale	228		—		—		228
Transmission	75		—		—		75
Other	44		159		—		203
Total revenue from contracts with customers	3,230		1,283		42		4,555
Alternative revenue and other	183		72		5		260
Total revenues	$	3,413	$	1,355	$	47	$	4,815

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Income Taxes Income Taxes

12 Months Ended

Dec. 31, 2023

Income Tax Disclosure [Abstract]

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:

	2023		2022		2021
Federal statutory rate	21.0	%	21.0	%	21.0	%
State income tax on pretax income, net of federal tax effect	3.5		3.5		3.6
Increases (decreases) in tax from:
Wind PTCs (a)	(14.5)		(14.3)		(14.3)
Plant regulatory differences (b)	(5.5)		(4.5)		(4.6)
Other tax credits, net NOL & tax credit allowances	(1.1)		(1.1)		(1.0)
Other, net	0.6		0.2		0.1
Effective income tax rate	4.0	%	4.8	%	4.8	%

(a)Wind PTCs net of estimated transfer discount are credited to customers (reduction to revenue) and do not materially impact net income.

(b)Plant regulatory differences primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit are offset by corresponding revenue reductions.

Components of income tax expense for the years ended Dec. 31:

(Millions of Dollars)	2023		2022		2021
Current federal tax expense	$	182	$	39	$	16
Current state tax expense	28		11		—
Current change in unrecognized tax benefit	—		—		(1)
Deferred federal tax benefit	(181)		(32)		(13)
Deferred state tax expense	2		21		31
Deferred change in unrecognized tax expense	1		1		3
Deferred ITCs	(3)		(3)		(3)
Total income tax expense	$	29	$	37	$	33

Components of deferred income tax expense as of Dec. 31:

(Millions of Dollars)	2023		2022		2021
Deferred tax (benefit) expense excluding items below	$	(89)	$	23	$	63
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(48)		(32)		(42)
Adjustments to deferred income taxes for wind production tax credit cash transfers (a)	(40)		—		—
Tax expense allocated to other comprehensive income and other	(1)		(1)		—
Deferred tax (benefit) expense	$	(178)	$	(10)	$	21

(a)Proceeds from tax credit transfers are included in cash received (paid) for income taxes in the consolidated statement of cash flows.

Components of the net deferred tax liability as of Dec. 31:

(Millions of Dollars)	2023		2022 (a)
Deferred tax liabilities:
Differences between book and tax bases of property	$	2,326	$	2,315
Regulatory assets	289		243
Operating lease assets	95		112
Deferred fuel costs	51		125
Pension expense and other employee benefits	22		27
Other	8		11
Total deferred tax liabilities	$	2,791	$	2,833
Deferred tax assets:
Tax credit carryforward	$	457	$	385
Regulatory liabilities	291		292
Operating lease liabilities	95		112
Bad debts	14		14
Deferred ITCs	10		7
Tax credit carryforward valuation allowances	(6)		(6)
Rate refund	4		21
NOL carryforward	—		9
Other	32		16
Total deferred tax assets	$	897	$	850
Net deferred tax liability	$	1,894	$	1,983

(a)Prior periods have been reclassified to conform to current year presentation.

Other Income Tax Matters — NOL amounts represent the tax loss that is carried forward and tax credits represent the deferred tax asset.

NOL and tax credit carryforwards as of Dec. 31 were as follows:

(Millions of Dollars)	2023		2022
Federal NOL carryforward	$	—	$	5
Federal tax credit carryforwards	444		368
Valuation allowances for federal credit carryforwards	(3)		—
State NOL carryforwards	—		223
State tax credit carryforwards, net of federal detriment (a)	13		16
Valuation allowances for state credit carryforwards, net of federal benefit (b)	(3)		(6)

(a)State tax credit carryforwards are net of federal detriment of $3 million and $4 million as of Dec. 31, 2023 and 2022, respectively.

(b)Valuation allowances for state tax credit carryforwards were net of federal benefit of $1 million and $2 million as of Dec. 31, 2023 and 2022, respectively.

Federal carryforward periods expire between 2038 and 2043 and state carryforward periods expire between 2024 and 2036.

Unrecognized Tax Benefits

Federal Audit — PSCo is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s consolidated federal tax returns expire as follows:

Tax Year(s)	Expiration
2014 - 2016	March 2025
2020	September 2024

Additionally, the statute of limitations related to certain 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. As of Dec. 31, 2023 the IRS issued its Revenue Agent’s Report related to the federal tax loss carryback claim. The Company materially agrees with the report and re-recognized the related benefit in Dec. 2023.

State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2023, PSCo’s earliest open tax years that are subject to examination by state taxing authorities under applicable statutes of limitations are as follows:

State	Tax Year(s)	Expiration
Colorado	2014-2016	March 2026
Colorado	2019	October 2024

There are currently no state income tax audits in progress.

Unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which deductibility is highly certain, but for which there is uncertainty about the timing. A change in the timing of deductibility would not affect the ETR but would accelerate the payment to the taxing authority.

Unrecognized tax benefits - permanent vs temporary:

(Millions of Dollars)	Dec. 31, 2023		Dec. 31, 2022
Unrecognized tax benefit — Permanent tax positions	$	12	$	11
Unrecognized tax benefit — Temporary tax positions	—		2
Total unrecognized tax benefit	$	12	$	13

Changes in unrecognized tax benefits:

(Millions of Dollars)	2023		2022		2021
Balance at Jan. 1	$	13	$	11	$	9
Additions based on tax positions related to the current year	2		2		2
Reductions for tax positions of prior years	(3)		—		—
Balance at Dec. 31	$	12	$	13	$	11

Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards:

(Millions of Dollars)	Dec. 31, 2023		Dec. 31, 2022
NOL and tax credit carryforwards	$	(11)	$	(12)

As IRS and state audits resume, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $4 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. Payables for interest related to unrecognized tax benefits at Dec. 31, 2023, 2022 and 2021 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2023, 2022 or 2021.

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Fair Value of Financial Assets and Liabilities

12 Months Ended

Dec. 31, 2023

Fair Value Disclosures [Abstract]

Fair Value of Financial Assets and Liabilities

Fair Value Measurements

Accounting guidance for fair value measurements and disclosures provides a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. 

•Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are actively traded instruments with observable actual trading prices.

•Level 2 — Pricing inputs are other than actual trading prices in active markets but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts or priced with models using highly observable inputs.

•Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 include those valued with models requiring significant judgment or estimation.

Specific valuation methods include:

Interest rate derivatives — Fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.

Commodity derivatives — Methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When contracts relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges, the significance of the use of less observable inputs on a valuation is evaluated and may result in Level 3 classification.

Derivative Activities and Fair Value Measurements

PSCo 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 — PSCo 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, 2023, accumulated other comprehensive loss related to interest rate derivatives included $1 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings. As of Dec. 31, 2023, PSCo had no unsettled interest rate derivatives.

Wholesale and Commodity Trading — PSCo 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. PSCo 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 — PSCo 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 vehicle fuel.

When PSCo 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, 2023, PSCo had no commodity contracts designated as cash flow hedges.

Gross notional amounts of commodity forwards and options:

(Amounts in Millions) (a)(b)	Dec. 31, 2023	Dec. 31, 2022
MWh of electricity	2	8
MMBtu of natural gas	20	43

(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 — PSCo 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.

PSCo’s most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities. 

As of Dec. 31, 2023, four of PSCo’s ten most significant counterparties for these activities, comprising $30 million or 36% of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services or Fitch Ratings. 

Six of the ten most significant counterparties, comprising $40 million or 48% of this credit exposure, were not rated by these external ratings agencies, but based on PSCo’s internal analysis, had credit quality consistent with investment grade.

None of these significant counterparties had credit quality less than investment grade, based on internal analysis.

Eight of these significant counterparties are municipal, cooperative electric entities, RTOs or other utilities.

Credit Related Contingent Features — Contract provisions for derivative instruments that PSCo enters into, 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 PSCo’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies. As of Dec. 31, 2023 and 2022, there were no derivative liabilities position with such underlying contract provisions.

Also, certain contracts may 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, 2023 there were approximately $8 million of derivative instruments in a liability position with such underlying contract provisions. As of Dec. 31, 2022, there were no derivative liabilities in a liability position with such underlying contract provisions.

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 PSCo’s ability to fulfill its contractual obligations is reasonably expected to be impaired. PSCo had no collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 2023 and 2022.

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, 2023
Other derivative instruments
Natural gas commodity	$	—	$	(13)
Total	$	—	$	(13)
Year Ended Dec. 31, 2022
Other derivative instruments
Natural gas commodity	$	—	$	(15)
Total	$	—	$	(15)
Year Ended Dec. 31, 2021
Other derivative instruments
Natural gas commodity	$	—	$	(1)
Total	$	—	$	(1)

	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, 2023
Derivatives designated as cash flow hedges
Interest rate	$	1	(a)	$	—		$	—
Total	$	1		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	(5)	(b)
Natural gas commodity	—			15		(c)	(16)		(c)(d)
Total	$	—		$	15		$	(21)
Year Ended Dec. 31, 2022
Derivatives designated as cash flow hedges
Interest rate	$	1	(a)	$	—		$	—
Total	$	1		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	7	(b)
Natural gas commodity	—			8		(c)	(17)		(c)(d)
Total	$	—		$	8		$	(10)
Year Ended Dec. 31, 2021
Derivatives designated as cash flow hedges
Interest rate	$	2	(a)	$	—		$	—
Total	$	2		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	12	(b)
Natural gas commodity	—			4		(c)	(15)		(c)(d)
Total	$	—		$	4		$	(3)

(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 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.

(d)Relates primarily to option premium amortization.

PSCo had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2023, 2022 and 2021. 

Derivative assets and liabilities measured at fair value on a recurring basis were as follows:

	Dec. 31, 2023												Dec. 31, 2022
	Fair Value						Fair Value Total		Netting (a)		Total		Fair Value						Fair Value Total		Netting (a)		Total
(Millions of Dollars)	Level 1		Level 2		Level 3								Level 1		Level 2		Level 3
Current derivative assets
Other derivative instruments:
Commodity trading	$	1	$	19	$	—	$	20	$	(17)	$	3	$	16	$	220	$	1	$	237	$	(184)	$	53
Natural gas commodity	—		8		—		8		—		8		—		12		—		12		—		12
Total current derivative assets	$	1	$	27	$	—	$	28	$	(17)	$	11	$	16	$	232	$	1	$	249	$	(184)	$	65
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	6	$	9	$	—	$	15	$	—	$	15	$	12	$	32	$	9	$	53	$	(31)	$	22
Total noncurrent derivative assets	$	6	$	9	$	—	$	15	$	—	$	15	$	12	$	32	$	9	$	53	$	(31)	$	22
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	1	$	25	$	—	$	26	$	(17)	$	9	$	5	$	237	$	1	$	243	$	(223)	$	20
Natural gas commodity	—		8		—		8		—		8		—		10		—		10		—		10
Total current derivative liabilities	$	1	$	33	$	—	$	34	$	(17)	$	17	$	5	$	247	$	1	$	253	$	(223)	$	30
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	2	$	1	$	—	$	3	$	(3)	$	—	$	7	$	40	$	—	$	47	$	(38)	$	9
Total noncurrent derivative liabilities	$	2	$	1	$	—	$	3	$	(3)	$	—	$	7	$	40	$	—	$	47	$	(38)	$	9

(a)PSCo nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement. At Dec. 31, 2023 and 2022, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2023 and 2022, derivative assets and liabilities include rights to reclaim cash collateral of $4 million and $46 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.

Changes in Level 3 commodity derivatives:

	Year Ended Dec. 31
(Millions of Dollars)	2023		2022		2021
Balance at Jan. 1	$	9	$	(63)	$	(44)
Settlements (a)	—		12		4
Net transactions recorded during the period:
(Losses) gains recognized in earnings (a)	(9)		60		(23)
Balance at Dec. 31	$	—	$	9	$	(63)

(a)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:

	2023				2022
(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	7,450	$	6,580	$	6,860	$	5,881

Fair value of PSCo’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, 2023 and 2022, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2023

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Legal

PSCo 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 PSCo’s consolidated financial statements. Legal fees are generally expensed as incurred.

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 April 2022, CORE filed a supplement to include damages related to a 2022 outage. Also in 2022, CORE sent notice of withdrawal from the ownership agreement based on the same alleged breaches.

In February 2023, the court granted PSCo’s motion precluding CORE from seeking damages related to its withdrawal as part of the lawsuit. In October 2023, the jury ruled that CORE may not withdraw as a joint owner of the facility but awarded CORE lost power damages of $26 million. PSCo recognized a $34 million loss for the verdict in the third quarter of 2023, including estimated interest and other costs. PSCo intends to file an appeal of this decision.

Marshall Wildfire Litigation — 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. On June 8, 2023, the Boulder County Sheriff’s Office released its Marshall Fire Investigative Summary and Review and its supporting documents (the “Sheriff’s Report”). According to an October 2022 statement from the Colorado Insurance Commissioner, the Marshall Fire is estimated to have caused more than $2 billion in property losses.

According to the Sheriff’s Report, on Dec. 30, 2021, a fire ignited on a residential property in Boulder, Colorado, located in PSCo’s service territory, for reasons unrelated to PSCo’s power lines. According to the Sheriff’s Report, approximately one hour and 20 minutes after the first ignition, a second fire ignited just south of the Marshall Mesa Trailhead in unincorporated Boulder County, Colorado, also located in PSCo’s service territory. According to the Sheriff’s Report, the second ignition started approximately 80 to 110 feet away from PSCo’s power lines in the area.

The Sheriff’s Report states that the most probable cause of the second ignition was hot particles discharged from PSCo’s power lines after one of the power lines detached from its insulator in strong winds, and further states that it cannot be ruled out that the second ignition was caused by an underground coal fire. According to the Sheriff’s Report, no design, installation or maintenance defects or deficiencies were identified on PSCo’s electrical circuit in the area of the second ignition. PSCo disputes that its power lines caused the second ignition.

PSCo is aware of 302 complaints, most of which have also named Xcel Energy Inc. and Xcel Energy Services, Inc. as additional defendants, relating to the Marshall Fire. The complaints are on behalf of at least 4,047 plaintiffs, and one complaint is filed on behalf of a putative class of first responders who allegedly were exposed to the threat of serious bodily injury, or smoke, soot and ash from the Marshall Fire. The complaints generally allege that PSCo’s equipment ignited the Marshall Fire and assert various causes of action under Colorado law, including negligence, premises liability, trespass, nuisance, wrongful death, willful and wanton conduct, negligent infliction of emotional distress, loss of consortium and inverse condemnation. In addition to seeking compensatory damages, certain of the complaints also seek exemplary damages.

In September 2023, the Boulder County District Court Judge consolidated eight lawsuits that were pending at that time into a single action for pretrial purposes and has subsequently consolidated additional lawsuits that have been filed. At the case management conference in February 2024, a trial date was set for September 2025.

Colorado courts do not apply strict liability in determining an electric utility company’s liability for fire-related damages. For inverse condemnation claims, Colorado courts assess whether a defendant acted with intent to take a plaintiff’s property or intentionally took an action which has the natural consequence of taking the property. For negligence claims, 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.

Colorado law does not impose joint and several liability in tort actions. Instead, under Colorado law, a defendant is liable for the degree or percentage of the negligence or fault attributable to that defendant, except where the defendant conspired with another defendant. A jury’s verdict in a Colorado civil case must be unanimous. Under Colorado law, in a civil action other than a medical malpractice action, the total award for noneconomic loss is capped at $0.6 million per defendant for claims that accrued at the time of the Marshall Fire unless the court finds justification to exceed that amount by clear and convincing evidence, in which case the maximum doubles.

Colorado law caps punitive or exemplary damages to an amount equal to the amount of the actual damages awarded to the injured party, except the court may increase any award of punitive damages to a sum up to three times the amount of actual damages if the conduct that is the subject of the claim has continued during the pendency of the case or the defendant has acted in a willful and wanton manner during the action which further aggravated plaintiff’s damages.

In the event Xcel Energy Inc. or PSCo was found liable related to this litigation and were required to pay damages, such amounts could exceed our insurance coverage of approximately $500 million and have a material adverse effect on our financial condition, results of operations or cash flows. However, due to uncertainty as to the cause of the fire and the extent and magnitude of potential damages, Xcel Energy Inc. and PSCo are unable to estimate the amount or range of possible losses in connection with the Marshall Fire.

Rate Matters

PSCo is involved in various regulatory proceedings arising in the ordinary course of business. Until resolution, typically in the form of a rate order, uncertainties may exist regarding the ultimate rate treatment for certain activities and transactions. Amounts have been recognized for probable and reasonably estimable losses that may result. Unless otherwise disclosed, any reasonably possible range of loss in excess of any recognized amount is not expected to have a material effect on the consolidated financial statements.

Environmental

New and changing federal and state environmental mandates can create financial liabilities for PSCo, which are normally recovered through the regulated rate process.

Site Remediation

Various federal and state environmental laws impose liability where hazardous substances or other regulated materials have been released to the environment. PSCo may sometimes pay all or a portion of the cost to remediate sites where past activities of PSCo’s predecessors or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former MGPs; and third-party sites, such as landfills, for which PSCo is alleged to have sent wastes to that site.

MGP, Landfill and Disposal Sites

PSCo is currently investigating, remediating or performing post-closure actions at two historical MGP, landfill or other disposal sites across its service territory, excluding sites that are being addressed under current coal ash regulations (see below).

PSCo has recognized approximately $6 million 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 — PSCo’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.

If certain impacts to groundwater are detected, utilities are required to perform additional groundwater investigations and/or perform corrective actions beginning with an Assessment of Corrective Measures. Investigation and/or corrective action related to groundwater impacts are currently underway at four PSCo sites under the federal CCR program at a current estimated cost of at least $40 million. A liability has been recorded and is expected to be fully recoverable through regulatory mechanisms.

PSCo has executed an agreement with a third party that will excavate and process ash for beneficial use (at two sites) at a cost of approximately $45 million. An estimated liability has been recorded and amounts are expected to be fully recoverable through regulatory mechanisms.

AROs — AROs have been recorded for PSCo’s assets.

PSCo’s AROs were as follows:

	2023
(Millions  of Dollars)	Jan. 1, 2023		Accretion		Cash Flow Revisions (a)		Dec. 31, 2023
Electric
Steam, hydro and other production	$	180	$	8	$	—	$	188
Wind	44		2		—		46
Distribution	17		—		—		17
Natural gas
Transmission and distribution	235		11		(114)		132
Total liability	$	476	$	21	$	(114)	$	383

(a)In 2023, AROs were revised for changes in timing and estimates of cash flows. Changes in gas transmission and distribution AROs were primarily the result of changes to inflation and discount rate assumptions as well as updated mileage of gas lines and number of services.

	2022
(Millions  of Dollars)	Jan. 1, 2022		Amounts Incurred (a)		Accretion		Cash Flow Revisions (b)		Dec. 31, 2022
Electric
Steam, hydro and other production	$	152	$	34	$	6	$	(12)	$	180
Wind	42		—		2		—		44
Distribution	16		—		1		—		17
Natural gas
Transmission and distribution	212		—		10		13		235
Total liability	$	422	$	34	$	19	$	1	$	476

(a)Amounts incurred related to steam production pond remediation costs.

(b)In 2022, AROs were revised for changes in timing and estimates of cash flows. Revisions in steam, hydro, and other production AROs 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 PSCo’s facilities, but no confirmation or measurement of the cost of removal could be determined as of Dec. 31, 2023. Therefore, an ARO has not been recorded for these facilities.

Leases

PSCo 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 PSCo's rights to use leased assets. The present value of future operating lease payments is recognized in current and noncurrent operating lease liabilities. These amounts, adjusted for any prepayments or incentives, are recognized as operating lease ROU assets.

Most of PSCo’s leases do not contain a readily determinable discount rate. Therefore, the present value of future lease payments is generally calculated using the estimated incremental borrowing rate (weighted average of 4.2%). For currently existing asset classes, PSCo has elected to utilize the practical expedient under which non-lease components, such as asset maintenance costs included in payments, are not deducted from 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, 2023		Dec. 31, 2022
PPAs	$	623	$	612
Other	112		80
Gross operating lease ROU assets	735		692
Accumulated amortization	(369)		(255)
Net operating lease ROU assets	$	366	$	437

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.

PSCo’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.

Finance lease ROU assets:

(Millions of Dollars)	Dec. 31, 2023		Dec. 31, 2022
Gas storage facilities	$	160	$	160
Gas pipeline	21		21
Gross finance lease ROU assets	181		181
Accumulated amortization	(67)		(64)
Net finance lease ROU assets	$	114	$	117

Components of lease expense:

(Millions of Dollars)	2023		2022		2021
Operating leases
PPA capacity payments	$	89	$	91	$	102
Other operating leases (a)	19		20		16
Total operating lease expense (b)	$	108	$	111	$	118
Finance leases
Amortization of ROU assets	$	3	$	4	$	7
Interest expense on lease liability	15		16		17
Total finance lease expense	$	18	$	20	$	24

(a)Includes immaterial short-term lease expense of for 2023, 2022 and 2021.

(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, 2023:

(Millions of Dollars)	PPA (a) (b) Operating Leases		Other Operating Leases		Total Operating Leases		Finance Leases
2024	$	98	$	19	$	117	$	18
2025	97		12		109		18
2026	74		8		82		18
2027	44		8		52		16
2028	20		8		28		15
Thereafter	39		6		45		333
Total minimum obligation	372		61		433		418
Interest component of obligation	(35)		(6)		(41)		(304)
Present value of minimum obligation	$	337	$	55	392		114
Less current portion					(102)		(3)
Noncurrent operating and finance lease liabilities					$	290	$	111
Weighted-average remaining lease term in years					4.6		36.8

(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 2032.

PPAs and Fuel Contracts

Non-Lease PPAs — PSCo has entered into PPAs with other utilities and energy suppliers for purchased power to meet system load and energy requirements, operating reserve obligations and as part of wholesale and commodity trading activities. In general, these agreements provide for energy payments, based on actual energy delivered, and may also include capacity payments. Certain PPAs, accounted for as executory contracts with various expiration dates through 2027, contain minimum energy purchase requirements.

Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $3 million, $3 million and $2 million in 2023, 2022 and 2021, respectively.

Capacity and energy payments are contingent on the IPP 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, 2023, the estimated future payments for capacity that PSCo is obligated to purchase pursuant to these executory contracts, subject to availability, were as follows:

(Millions of Dollars)	Capacity
2024	$	3
2025	3
2026	3
2027	1
2028	—
Thereafter	—
Total	$	10

Fuel Contracts — PSCo has entered into various long-term commitments for the purchase and delivery of a significant portion of its coal and natural gas requirements. These contracts expire between 2024 and 2060. PSCo is required to pay additional amounts depending on actual quantities delivered under these agreements.

Estimated minimum purchases under these contracts as of Dec. 31, 2023:

(Millions of Dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2024	$	143	$	221	$	108
2025	74		12		105
2026	39		—		105
2027	35		—		105
2028	—		—		62
Thereafter	—		—		382
Total	$	291	$	233	$	867

VIEs

Under certain PPAs, PSCo purchases power from IPPs for which PSCo is required to reimburse fuel costs, or to participate in tolling arrangements under which PSCo procures the natural gas required to produce the energy that it purchases. PSCo has determined that certain IPPs are VIEs, however PSCo 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.

PSCo 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. PSCo concluded that these entities are not required to be consolidated in its consolidated financial statements because PSCo does not have the power to direct the activities that most significantly impact the entities’ economic performance. PSCo had approximately 1,207 MW and 1,442 MW of capacity under long-term PPAs at Dec. 31, 2023 and 2022, respectively, with entities that have been determined to be VIEs. These agreements have expiration dates through 2032.

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Other Comprehensive Income

12 Months Ended

Dec. 31, 2023

Stockholders' Equity Note [Abstract]

Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31:

	2023
(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	$	(20)		$	(2)		$	(22)
Other comprehensive loss before reclassifications	—			—			—
Losses reclassified from net accumulated other comprehensive loss:
Amortization of interest rate hedges	1		(a)	—			1
Amortization of net actuarial loss	—			1		(b)	1
Net current period other comprehensive income	1			1			2
Accumulated other comprehensive loss at Dec. 31	$	(19)		$	(1)		$	(20)

(a)Included in interest charges.

(b)Included in the computation of net periodic pension and postretirement benefit costs. See Note 9 for further information.

	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	$	(21)		$	(1)	$	(22)
Other comprehensive loss before reclassifications	—			(1)		(1)
Losses reclassified from net accumulated other comprehensive loss:
Amortization of interest rate hedges	1		(a)	—		1
Net current period other comprehensive income (loss)	1			(1)		—
Accumulated other comprehensive loss at Dec. 31	(20)			(2)		(22)

(a)Included in interest charges.

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Segments and Related Information

12 Months Ended

Dec. 31, 2023

Segment Reporting [Abstract]

Segment Information

PSCo evaluates performance based on profit or loss generated from the product or service provided. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment.

PSCo has the following reportable segments:

•Regulated Electric — The regulated electric utility segment generates, purchases, transmits, distributes and sells electricity in Colorado. 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 PSCo’s wholesale commodity and trading operations.

•Regulated Natural Gas — The regulated natural gas utility segment purchases, transports, stores, distributes and sells natural gas in portions of Colorado.

PSCo 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 and non-utility real estate activities.

Asset and capital expenditure information is not provided for PSCo’s reportable segments because as an integrated electric and natural gas utility, PSCo 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.

PSCo’s segment information:

(Millions of Dollars)	2023		2022		2021
Regulated Electric
Operating revenues — external	$	3,731	$	3,795	$	3,413
Intersegment revenue	1		1		1
Total revenues	$	3,732	$	3,796	$	3,414
Depreciation and amortization	692		650		566
Interest charges and financing costs	224		200		179
Income tax benefit	(2)		(11)		(16)
Net income	529		550		495
Regulated Natural Gas
Total revenues	$	1,734	$	1,860	$	1,355
Depreciation and amortization	224		190		171
Interest charges and financing costs	67		59		53
Income tax expense	37		49		45
Net income	149		180		168
All Other
Total revenues (a)	$	54	$	53	$	47
Depreciation and amortization	8		8		7
Interest charges and financing costs	1		1		2
Income tax (benefit) expense	(6)		(1)		4
Net (loss) income	17		(3)		(3)
Consolidated Total
Total revenues (a)	$	5,520	$	5,709	$	4,816
Reconciling eliminations	(1)		(1)		(1)
Total operating revenues	$	5,519	$	5,708	$	4,815
Depreciation and amortization	924		848		744
Interest charges and financing costs	292		260		234
Income tax expense	29		37		33
Net income	695		727		660

(a)Operating revenues include $5 million of other affiliate revenue for the years ended Dec. 31, 2023, 2022 and 2021, respectively. See Note 13 for further information.

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Related Party Transactions

12 Months Ended

Dec. 31, 2023

Related Party Transactions [Abstract]

Related Party Transactions

Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy Inc., including PSCo. The services are provided and billed to each subsidiary in accordance with service agreements executed by each subsidiary. PSCo uses services provided by Xcel Energy Services Inc. whenever possible. Costs are charged directly to the subsidiary and are allocated if they cannot be directly assigned.

Xcel Energy, Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS have established a utility money pool arrangement.

See Note 5 for further information.

Significant affiliate transactions among the companies and related parties for the years ended Dec. 31:

(Millions of Dollars)	2023		2022		2021
Operating revenues:
Other	$	5	$	5	$	5
Operating expenses:
Other operating expenses — paid to Xcel Energy Services Inc.	679		670		617
Interest expense	5		2		—
Interest income	2		—		—

Accounts receivable and payable with affiliates at Dec. 31:

	2023				2022
(Millions of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Minnesota	$	—	$	5	$	2	$	—
NSP-Wisconsin	—		1		—		2
SPS	—		11		—		11
Other subsidiaries of Xcel Energy Inc.	28		66		9		62
	$	28	$	83	$	11	$	75

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Compensation Related Costs, Postemployment Benefits

12 Months Ended

Dec. 31, 2023

Postemployment Benefits [Abstract]

Postemployment Benefits Disclosure

In 2023, Xcel Energy implemented workforce actions to align resources and investments with evolving business and customer needs, and streamline the organization for long-term success.

In September 2023, Xcel Energy announced a voluntary retirement program to a group of eligible non-bargaining employees, with an enhanced retirement package including certain health care and cash benefits for accepted employees. Approximately 400 employees retired under this program in December 2023.

In November 2023, Xcel Energy, Inc. also reduced its non-bargaining workforce by approximately 150 employees through an involuntary severance program.

In the fourth quarter of 2023, Xcel Energy recorded total expense of $72 million related to these workforce actions, of which $20 million was attributable to PSCo. Expenses relate to the estimated cost of future health plan subsidies and other medical benefits for the voluntary retirement program, as well as severance and other employee payouts and legal and other professional fees.

For further information on the estimated obligations for future health plan subsidies and other medical benefits, see Note 9 to the consolidated financial statements.

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Schedule II, Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2023

SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]

Schedule II, Valuation and Qualifying Accounts

Public Service Co. of Colorado and Subsidiaries Valuation and Qualifying Accounts Years Ended Dec. 31

	Allowance for bad debts
(Millions of Dollars)	2023		2022		2021
Balance at Jan. 1	$	54	$	40	$	29
Additions charged to costs and expenses	34		38		26
Additions charged to other accounts (a)	5		18		4
Deductions from reserves (b)	(37)		(42)		(19)
Balance at Dec. 31	$	56	$	54	$	40

(a)Recovery of amounts previously written-off.

(b)Deductions related primarily to bad debt write-offs.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2023

Accounting Policies [Abstract]

Business and System of Accounts

General — PSCo is engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and the regulated purchase, transportation, distribution and sale of natural gas. 

PSCo’s consolidated financial statements are presented in accordance with GAAP. All of PSCo’s underlying accounting records also conform to the FERC uniform system of accounts or to systems required by its state regulatory commission. 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.

Principles of Consolidation

PSCo’s consolidated financial statements include its wholly-owned subsidiaries. In the consolidation process, all intercompany transactions and balances are eliminated. PSCo has investments in several plants and transmission facilities jointly owned with nonaffiliated utilities. 

PSCo’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets, and PSCo’s proportionate share of operating costs associated with these facilities is included in its consolidated statements of income.

Subsequent Events

PSCo has evaluated events occurring after Dec. 31, 2023 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

Use of Estimates — PSCo uses estimates based on the best information available to record 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

Regulatory Accounting — PSCo accounts for income and expense items in accordance with accounting guidance for regulated operations. Under this guidance:

•Certain costs, which would otherwise be charged to expense or other comprehensive income, are deferred as regulatory assets based on the expected ability to recover the costs in future rates.

•Certain credits, which would otherwise be reflected as income or other comprehensive income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred.

Estimates and assumptions for recovery of deferred costs and refund of deferred credits are based on specific ratemaking decisions, precedent or other available information. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process.

If changes in the regulatory environment occur, PSCo 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 PSCo’s results of operations, financial condition and cash flows.

See Note 4 for further information.

Income Taxes

Income Taxes — PSCo accounts for income taxes using the asset and liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the consolidated financial statements. Income taxes are deferred for all temporary differences between pretax financial and taxable income and between the book and tax bases of assets and liabilities utilizing rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the period that includes the enactment date.

Utility rate regulation has resulted in the recognition of regulatory assets and liabilities related to income taxes. The effects of PSCo’s tax rate changes are generally subject to a normalization method of accounting. Therefore, the revaluation of most of its 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. PSCo 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.

Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize over the book depreciable lives of related property. The requirement to defer and amortize these credits specifically applies to certain federal ITCs, as determined by tax regulations and PSCo tax elections. For tax credits otherwise eligible to be recognized when earned, PSCo 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. This evaluation includes consideration of whether tax credits are expected to be sold at a discount and impact the realization of amounts presented as deferred tax assets. Transferable tax credits are accounted for under ASC 740 Income Taxes, and valuation allowances and any adjustments for discounts incurred on sales transactions are recorded to deferred tax expense, typically recovered in regulatory mechanisms.

PSCo 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 income (expense), net or interest charges in the consolidated statements of income.

Xcel Energy Inc. and its subsidiaries, including PSCo 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

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 and replacement of items determined to be less than a unit of property are charged to expense 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 3.6% in 2023, 3.4% in 2022 and 3.2% in 2021.

See Note 3 for further information.

Asset Retirement Obligations

AROs — PSCo records AROs as a liability in the period incurred (if fair value can be reasonably estimated), with the offsetting/associated costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion and the capitalized costs are typically depreciated over the useful life of the long-lived asset. Changes resulting from revisions to timing or amounts of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO.

See Note 10 for further information.

Benefit Plans and Other Postretirement Benefits

Benefit Plans and Other Postretirement Benefits — PSCo maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans requires management to make various assumptions and estimates.

Certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are deferred as regulatory assets and liabilities, rather than recorded as other comprehensive income, based on regulatory recovery mechanisms.

See Note 9 for further information.

Environmental Costs

Environmental Costs — Environmental costs are recorded when it is probable PSCo is liable for remediation costs and the amount can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. For certain environmental costs related to facilities currently in use, such as for emission-control equipment, the cost is capitalized and depreciated over the life of the plant.

Estimated remediation costs are regularly adjusted as estimates are revised and remediation is performed. If other participating potentially responsible parties exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for PSCo’s expected share of the cost. 

Estimated future expenditures to restore sites are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.

See Note 10 for further information.

Revenue From Contracts With Customers

Revenue from Contracts with Customers — Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. PSCo 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.

PSCo recognizes physical sales to customers (native load and wholesale) on a gross basis in electric revenues and cost of sales. PSCo participates in SPP WEIS. Revenues for short-term physical wholesale sales of excess energy transacted through the imbalance market are recorded on a gross basis. Other revenues and charges settled/facilitated through SPP WEIS are recorded on a net basis in cost of sales.

See Note 6 for further information.

Cash and Cash Equivalents

Cash and Cash Equivalents — PSCo considers investments in instruments with a remaining maturity of 3 months or less at the time of purchase to be cash equivalents.

Accounts Receivable and Allowance for Bad Debts

Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. PSCo 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, 2023 and 2022, the allowance for bad debts was $56 million and $54 million, respectively.

Inventory

Inventory — Inventory is recorded at the lower of average cost or net realizable value and consisted of the following:

(Millions of Dollars)	Dec. 31, 2023		Dec. 31, 2022
Inventories
Materials and supplies	$	91	$	80
Fuel	83		68
Natural gas	84		171
Total inventories	$	258	$	319

Fair Value Measurements

Fair Value Measurements — PSCo presents cash equivalents, interest rate derivatives and commodity derivatives at estimated fair values in its consolidated financial statements. 

For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used to estimate fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price, quoted prices for similar contracts or internally prepared valuation models may be used to determine fair value.

For the pension and postretirement plan assets and nuclear decommissioning fund, published trading data and pricing models, generally using the most observable inputs available, are utilized to determine fair value for each security.

See Notes 8 and 9 for further information.

Derivative Instruments

Derivative Instruments — PSCo 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. Derivatives 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 — PSCo enters into contracts for purchases and sales of commodities for use in its operations. At inception, contracts are evaluated to determine whether they contain a derivative, and if so, whether they may be exempted from derivative accounting if designated as normal purchases or normal sales.

See Note 8 for further information.

Commodity Trading Operations

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 PSCo’s generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms. 

See Note 8 for further information

AFUDC

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 PSCo’s rate base.

Alternative Revenue Programs

Alternative Revenue — Certain rate rider mechanisms (including decoupling and 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 — PSCo has implemented programs to assist its retail customers in conserving energy and reducing peak demand on the electric and natural gas systems. These programs include approximately 20 unique DSM products, pilots and services for C&I customers, as well as approximately 23 DSM products, pilots and services for residential and low-income customers. Overall, the DSM portfolio provides rebates and/or incentives for nearly 1,000 unique measures.

The costs incurred for DSM programs are deferred if it is probable future revenue will be provided to permit recovery of the incurred cost. Revenues recognized for incentive programs designed for recovery of DSM program costs and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the year in which they are earned.

PSCo’s DSM program costs are recovered through a combination of base rate revenue and rider mechanisms. Regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers.

Emission Allowances

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.

Renewable Energy Credits

RECs — Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. An inventory accounting model is used to account for RECs.

Sales of RECs are recorded in electric revenues on a gross basis. Cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.

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Summary of Significant Accounting Policies Inventory (Tables)

12 Months Ended

Dec. 31, 2023

Balance Sheet Related Disclosure - Inventory [Abstract]

Public Utilities, Inventory

Inventory — Inventory is recorded at the lower of average cost or net realizable value and consisted of the following:

(Millions of Dollars)	Dec. 31, 2023		Dec. 31, 2022
Inventories
Materials and supplies	$	91	$	80
Fuel	83		68
Natural gas	84		171
Total inventories	$	258	$	319

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Property Plant and Equipment Property Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2023

Property, Plant and Equipment [Abstract]

Public Utility Property, Plant, and Equipment

Major classes of property, plant and equipment

(Millions of Dollars)	Dec. 31, 2023		Dec. 31, 2022
Property, plant and equipment, net
Electric plant	$	16,698	$	15,771
Natural gas plant	6,321		5,949
Common and other property	1,472		1,415
Plant to be retired (a)	1,203		1,305
CWIP	1,310		877
Total property, plant and equipment	27,004		25,317
Less accumulated depreciation	(5,969)		(5,665)
Property, plant and equipment, net	$	21,035	$	19,652

Schedule of Jointly Owned Utility Plants

Joint Ownership of Generation, Transmission and Gas Facilities

Jointly owned assets as of Dec. 31, 2023:

(Millions of Dollars, Except Percent Owned)	Plant in Service		Accumulated Depreciation		Percent Owned
Electric generation:
Hayden Unit 1	$	157	$	108	76	%
Hayden Unit 2	151		87		37
Hayden common facilities	44		31		53
Craig Units 1 and 2	82		55		10
Craig common facilities	39		25		7
Comanche Unit 3	916		191		67
Comanche common facilities	29		4		77
Electric transmission:
Transmission and other facilities	189		75		Various
Gas transmission:
Rifle, CO to Avon, CO	28		9		60
Gas transmission compressor	8		2		50
Total (a)	$	1,643	$	587

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Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2023

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets

Components of regulatory assets:

(Millions of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2023				Dec. 31, 2022
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Pension and retiree medical obligations	9	Various	$	2	$	396	$	3	$	367
Net AROs (a)	1, 10	Various	—		236		—		212
Depreciation differences		One to 10 years	16		184		16		187
Recoverable deferred taxes on AFUDC		Plant lives	—		135		—		119
Excess deferred taxes — TCJA	7	Various	—		55		2		54
Environmental remediation costs		Various	—		44		6		26
Conservation programs (b)	1	One to two years	12		33		8		16
Revenue decoupling		Various	—		31		—		—
Gas pipeline inspection costs		One to two years	3		25		—		13
Deferred natural gas, electric, steam energy/fuel costs		One to three years	221		22		312		200
Purchased power contract costs		Term of related contract	4		20		3		16
Grid modernization costs		Two years	15		14		14		22
Property tax		Various	3		7		8		2
Other		Various	28		65		39		43
Total regulatory assets			$	304	$	1,267	$	411	$	1,277

(a)Includes amounts recorded for future recovery of AROs.

(b)Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

Regulatory Liabilities

Components of regulatory liabilities:

(Millions of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2023				Dec. 31, 2022
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Deferred income tax adjustments and TCJA refunds (a)	7	Various	$	2	$	1,260	$	2	$	1,298
Plant removal costs	1, 10	Various	—		769		—		705
Effects of regulation on employee benefit costs (b)		Various	—		234		—		227
Renewable resources and environmental initiatives		Various	—		152		—		141
Revenue decoupling		Various	—		63		—		55
ITC deferrals	1	Various	1		44		1		41
Deferred natural gas, electric, steam energy/fuel costs		Less than one year	34		—		3		—
Conservation programs	1	Less than one year	9		—		19		—
Formula rates		One to two years	8		—		16		—
Other		Various	16		40		18		22
Total regulatory liabilities			$	70	$	2,562	$	59	$	2,489

(a)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.

(b)Includes regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the prepaid pension asset.

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Borrowings and Other Financing Instruments (Tables)

12 Months Ended

Dec. 31, 2023

Debt Disclosure [Abstract]

Money Pool [Table Text Block]

Money pool borrowings:

(Millions of Dollars, Except Interest Rates)	Three Months Ended Dec. 31, 2023			Year Ended Dec. 31
				2023			2022			2021
Borrowing limit	$	250		$	250		$	250		$	250
Amount outstanding at period end	51			51			—			—
Average amount outstanding	64			23			29			12
Maximum amount outstanding	250			250			250			243
Weighted average interest rate, computed on a daily basis	5.33		%	5.31		%	1.66		%	0.07		%
Weighted average interest rate at end of period	5.34			5.34			N/A			N/A

Schedule of Short-term Debt [Table Text Block]

Commercial paper borrowings:

(Millions of Dollars, Except Interest Rates)	Three Months Ended Dec. 31, 2023			Year Ended Dec. 31
				2023			2022			2021
Borrowing limit	$	700		$	700		$	700		$	700
Amount outstanding at period end	320			320			294			147
Average amount outstanding	189			124			71			26
Maximum amount outstanding	369			454			328			322
Weighted average interest rate, computed on a daily basis	5.53		%	5.17		%	2.56		%	0.19		%
Weighted average interest rate at end of period	5.56			5.56			4.73			0.22

Schedule Of Debt To Total Capitalization Ratio [Table Text Block]

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)
2023		2022
44.8	%	44.0	%	$	100	2

(a)The credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%.

(b)All extension requests are subject to majority bank group approval.

Schedule of Line of Credit Facilities [Table Text Block]

PSCo had the following committed credit facility available as of Dec. 31, 2023 (in millions of dollars):

Credit Facility (a)		Drawn (b)		Available
$	700	$	349	$	351

(a)This credit facility matures in September 2027.

(b)Includes letters of credit and outstanding commercial paper.

^[1],[2]

Schedule of Capitalization [Table Text Block]

Long-term debt obligations for PSCo as of Dec. 31 (in millions of dollars):

Financing Instrument	Interest Rate		Maturity Date	2023		2022
First mortgage bonds	2.50	%	March 15, 2023	$	—	$	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	1.875		June 15, 2031	750		750
First mortgage bonds (a)	4.10		June 1, 2032	300		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 (a)	4.50		June 1, 2052	400		400
First mortgage bonds (b)	5.25		April 1, 2053	850		—
Unamortized discount				(41)		(37)
Unamortized debt issuance cost				(59)		(53)
Current maturities				—		(250)
Total long-term debt				$	7,450	$	6,610

(a)2022 financing.

(b)2023 financing.

^[3],[4]

Schedule of Maturities of Long-term Debt [Table Text Block]

Maturities of long-term debt:

(Millions of Dollars)
2024	$	—
2025	250
2026	—
2027	—
2028	350

Preferred Stock

Capital Stock — PSCo has authorized the issuance of preferred stock.

Preferred Stock Authorized (Shares)	Par Value of Preferred Stock		Preferred Stock Outstanding (Shares) 2023 and 2022
10,000,000	$	0.01	—

[1] Includes letters of credit and outstanding commercial paper.

[2] This credit facility matures in September 2027.

[3] 2022 financing

[4] 2023 financing.

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Revenues (Tables)

12 Months Ended

Dec. 31, 2023

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

Revenue is classified by the type of goods/services rendered and market/customer type. PSCo’s operating revenues consisted of the following:

	Year Ended Dec. 31, 2023
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	1,295	$	1,109	$	19	$	2,423
C&I	1,816		459		30		2,305
Other	52		—		5		57
Total retail	3,163		1,568		54		4,785
Wholesale	237		—		—		237
Transmission	90		—		—		90
Other	61		132		—		193
Total revenue from contracts with customers	3,551		1,700		54		5,305
Alternative revenue and other	180		34		—		214
Total revenues	$	3,731	$	1,734	$	54	$	5,519

	Year Ended Dec. 31, 2022
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	1,341	$	1,203	$	15	$	2,559
C&I	1,843		479		32		2,354
Other	52		—		—		52
Total retail	3,236		1,682		47		4,965
Wholesale	286		—		—		286
Transmission	88		—		—		88
Other	53		151		—		204
Total revenue from contracts with customers	3,663		1,833		47		5,543
Alternative revenue and other	132		27		6		165
Total revenues	$	3,795	$	1,860	$	53	$	5,708

	Year Ended Dec. 31, 2021
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	1,174	$	816	$	12	$	2,002
C&I	1,660		308		30		1,998
Other	49		—		—		49
Total retail	2,883		1,124		42		4,049
Wholesale	228		—		—		228
Transmission	75		—		—		75
Other	44		159		—		203
Total revenue from contracts with customers	3,230		1,283		42		4,555
Alternative revenue and other	183		72		5		260
Total revenues	$	3,413	$	1,355	$	47	$	4,815

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Preferred Stock (Tables)

12 Months Ended

Dec. 31, 2023

Equity [Abstract]

Preferred Stock

Capital Stock — PSCo has authorized the issuance of preferred stock.

Preferred Stock Authorized (Shares)	Par Value of Preferred Stock		Preferred Stock Outstanding (Shares) 2023 and 2022
10,000,000	$	0.01	—

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2023

Income Tax Disclosure [Abstract]

Summary of Statute of Limitations Applicable to Open Tax Years

Tax Year(s)	Expiration
2014 - 2016	March 2025
2020	September 2024

Reconciliation of Unrecognized Tax Benefits

Unrecognized tax benefits - permanent vs temporary:

(Millions of Dollars)	Dec. 31, 2023		Dec. 31, 2022
Unrecognized tax benefit — Permanent tax positions	$	12	$	11
Unrecognized tax benefit — Temporary tax positions	—		2
Total unrecognized tax benefit	$	12	$	13

Changes in unrecognized tax benefits:

(Millions of Dollars)	2023		2022		2021
Balance at Jan. 1	$	13	$	11	$	9
Additions based on tax positions related to the current year	2		2		2
Reductions for tax positions of prior years	(3)		—		—
Balance at Dec. 31	$	12	$	13	$	11

Tax Benefits Associated with NOL and Tax Credit Carryforwards

Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards:

(Millions of Dollars)	Dec. 31, 2023		Dec. 31, 2022
NOL and tax credit carryforwards	$	(11)	$	(12)

NOL and Tax Credit Carryforwards

NOL amounts represent the tax loss that is carried forward and tax credits represent the deferred tax asset.

NOL and tax credit carryforwards as of Dec. 31 were as follows:

(Millions of Dollars)	2023		2022
Federal NOL carryforward	$	—	$	5
Federal tax credit carryforwards	444		368
Valuation allowances for federal credit carryforwards	(3)		—
State NOL carryforwards	—		223
State tax credit carryforwards, net of federal detriment (a)	13		16
Valuation allowances for state credit carryforwards, net of federal benefit (b)	(3)		(6)

(a)State tax credit carryforwards are net of federal detriment of $3 million and $4 million as of Dec. 31, 2023 and 2022, respectively.

(b)Valuation allowances for state tax credit carryforwards were net of federal benefit of $1 million and $2 million as of Dec. 31, 2023 and 2022, respectively.

Schedule of Effective Income Tax Rate Reconciliation

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:

	2023		2022		2021
Federal statutory rate	21.0	%	21.0	%	21.0	%
State income tax on pretax income, net of federal tax effect	3.5		3.5		3.6
Increases (decreases) in tax from:
Wind PTCs (a)	(14.5)		(14.3)		(14.3)
Plant regulatory differences (b)	(5.5)		(4.5)		(4.6)
Other tax credits, net NOL & tax credit allowances	(1.1)		(1.1)		(1.0)
Other, net	0.6		0.2		0.1
Effective income tax rate	4.0	%	4.8	%	4.8	%

(a)Wind PTCs net of estimated transfer discount are credited to customers (reduction to revenue) and do not materially impact net income.

(b)Plant regulatory differences primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit are offset by corresponding revenue reductions.

Schedule of Components of Income Tax Expense (Benefit)

Components of income tax expense for the years ended Dec. 31:

(Millions of Dollars)	2023		2022		2021
Current federal tax expense	$	182	$	39	$	16
Current state tax expense	28		11		—
Current change in unrecognized tax benefit	—		—		(1)
Deferred federal tax benefit	(181)		(32)		(13)
Deferred state tax expense	2		21		31
Deferred change in unrecognized tax expense	1		1		3
Deferred ITCs	(3)		(3)		(3)
Total income tax expense	$	29	$	37	$	33

Components of deferred income tax expense as of Dec. 31:

(Millions of Dollars)	2023		2022		2021
Deferred tax (benefit) expense excluding items below	$	(89)	$	23	$	63
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(48)		(32)		(42)
Adjustments to deferred income taxes for wind production tax credit cash transfers (a)	(40)		—		—
Tax expense allocated to other comprehensive income and other	(1)		(1)		—
Deferred tax (benefit) expense	$	(178)	$	(10)	$	21

(a)Proceeds from tax credit transfers are included in cash received (paid) for income taxes in the consolidated statement of cash flows.

Schedule of Deferred Tax Assets and Liabilities

Components of the net deferred tax liability as of Dec. 31:

(Millions of Dollars)	2023		2022 (a)
Deferred tax liabilities:
Differences between book and tax bases of property	$	2,326	$	2,315
Regulatory assets	289		243
Operating lease assets	95		112
Deferred fuel costs	51		125
Pension expense and other employee benefits	22		27
Other	8		11
Total deferred tax liabilities	$	2,791	$	2,833
Deferred tax assets:
Tax credit carryforward	$	457	$	385
Regulatory liabilities	291		292
Operating lease liabilities	95		112
Bad debts	14		14
Deferred ITCs	10		7
Tax credit carryforward valuation allowances	(6)		(6)
Rate refund	4		21
NOL carryforward	—		9
Other	32		16
Total deferred tax assets	$	897	$	850
Net deferred tax liability	$	1,894	$	1,983

(a)Prior periods have been reclassified to conform to current year presentation.

State Summary of Statute of Limitatios applicable to Open Tax Years

PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2023, PSCo’s earliest open tax years that are subject to examination by state taxing authorities under applicable statutes of limitations are as follows:

State	Tax Year(s)	Expiration
Colorado	2014-2016	March 2026
Colorado	2019	October 2024

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Fair Value of Financial Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2023

Fair Value Disclosures [Abstract]

Gross Notional Amounts of Commodity Forwards and Options

Gross notional amounts of commodity forwards and options:

(Amounts in Millions) (a)(b)	Dec. 31, 2023	Dec. 31, 2022
MWh of electricity	2	8
MMBtu of natural gas	20	43

(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.

Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income

	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, 2023
Other derivative instruments
Natural gas commodity	$	—	$	(13)
Total	$	—	$	(13)
Year Ended Dec. 31, 2022
Other derivative instruments
Natural gas commodity	$	—	$	(15)
Total	$	—	$	(15)
Year Ended Dec. 31, 2021
Other derivative instruments
Natural gas commodity	$	—	$	(1)
Total	$	—	$	(1)

	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, 2023
Derivatives designated as cash flow hedges
Interest rate	$	1	(a)	$	—		$	—
Total	$	1		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	(5)	(b)
Natural gas commodity	—			15		(c)	(16)		(c)(d)
Total	$	—		$	15		$	(21)
Year Ended Dec. 31, 2022
Derivatives designated as cash flow hedges
Interest rate	$	1	(a)	$	—		$	—
Total	$	1		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	7	(b)
Natural gas commodity	—			8		(c)	(17)		(c)(d)
Total	$	—		$	8		$	(10)
Year Ended Dec. 31, 2021
Derivatives designated as cash flow hedges
Interest rate	$	2	(a)	$	—		$	—
Total	$	2		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	12	(b)
Natural gas commodity	—			4		(c)	(15)		(c)(d)
Total	$	—		$	4		$	(3)

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 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.

(d)Relates primarily to option premium amortization.

Derivative Assets and Liabilities Measured at Fair Value on a Recurring Basis by Hierarchy Level

Derivative assets and liabilities measured at fair value on a recurring basis were as follows:

	Dec. 31, 2023												Dec. 31, 2022
	Fair Value						Fair Value Total		Netting (a)		Total		Fair Value						Fair Value Total		Netting (a)		Total
(Millions of Dollars)	Level 1		Level 2		Level 3								Level 1		Level 2		Level 3
Current derivative assets
Other derivative instruments:
Commodity trading	$	1	$	19	$	—	$	20	$	(17)	$	3	$	16	$	220	$	1	$	237	$	(184)	$	53
Natural gas commodity	—		8		—		8		—		8		—		12		—		12		—		12
Total current derivative assets	$	1	$	27	$	—	$	28	$	(17)	$	11	$	16	$	232	$	1	$	249	$	(184)	$	65
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	6	$	9	$	—	$	15	$	—	$	15	$	12	$	32	$	9	$	53	$	(31)	$	22
Total noncurrent derivative assets	$	6	$	9	$	—	$	15	$	—	$	15	$	12	$	32	$	9	$	53	$	(31)	$	22
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	1	$	25	$	—	$	26	$	(17)	$	9	$	5	$	237	$	1	$	243	$	(223)	$	20
Natural gas commodity	—		8		—		8		—		8		—		10		—		10		—		10
Total current derivative liabilities	$	1	$	33	$	—	$	34	$	(17)	$	17	$	5	$	247	$	1	$	253	$	(223)	$	30
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	2	$	1	$	—	$	3	$	(3)	$	—	$	7	$	40	$	—	$	47	$	(38)	$	9
Total noncurrent derivative liabilities	$	2	$	1	$	—	$	3	$	(3)	$	—	$	7	$	40	$	—	$	47	$	(38)	$	9

(a)PSCo nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement. At Dec. 31, 2023 and 2022, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2023 and 2022, derivative assets and liabilities include rights to reclaim cash collateral of $4 million and $46 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.

Changes in Level 3 commodity derivatives:

	Year Ended Dec. 31
(Millions of Dollars)	2023		2022		2021
Balance at Jan. 1	$	9	$	(63)	$	(44)
Settlements (a)	—		12		4
Net transactions recorded during the period:
(Losses) gains recognized in earnings (a)	(9)		60		(23)
Balance at Dec. 31	$	—	$	9	$	(63)

(a)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:

	2023				2022
(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	7,450	$	6,580	$	6,860	$	5,881

Fair value of PSCo’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, 2023 and 2022, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.

Carrying Amount and Fair Value of Long-term Debt

	2023				2022
(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	7,450	$	6,580	$	6,860	$	5,881

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation

Changes in Level 3 commodity derivatives:

	Year Ended Dec. 31
(Millions of Dollars)	2023		2022		2021
Balance at Jan. 1	$	9	$	(63)	$	(44)
Settlements (a)	—		12		4
Net transactions recorded during the period:
(Losses) gains recognized in earnings (a)	(9)		60		(23)
Balance at Dec. 31	$	—	$	9	$	(63)

(a)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.

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Benefit Plans and Other Postretirement Benefits (Tables)

12 Months Ended

Dec. 31, 2023

Benefit Plans and Other Postretirement Benefits [Abstract]

Target Asset Allocations and Plan Assets Measured at Fair Value

For each of the fair value hierarchy levels, PSCo’s pension plan assets measured at fair value:

	Dec. 31, 2023 (a)										Dec. 31, 2022 (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	$	94	$	—	$	—	$	—	$	94	$	52	$	—	$	—	$	—	$	52
Commingled funds	177		—		—		464		641		355		—		—		317		672
Debt securities	—		287		1		—		288		—		286		1		—		287
Equity securities	12		—		—		—		12		17		—		—		—		17
Other	—		2		—		—		2		—		3		—		—		3
Total	$	283	$	289	$	1	$	464	$	1,037	$	424	$	289	$	1	$	317	$	1,031

(a)See Note 8 for further information on fair value measurement inputs and methods.

	Dec. 31, 2023 (a)										Dec. 31, 2022 (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	$	29	$	—	$	—	$	—	$	29	$	28	$	—	$	—	$	—	$	28
Insurance contracts	—		35		—		—		35		—		36		—		—		36
Commingled funds	20		—		—		63		83		47		—		—		56		103
Debt securities	—		165		1		—		166		—		153		1		—		154
Other	—		1		—		—		1		—		(1)		—		—		(1)
Total	$	49	$	201	$	1	$	63	$	314	$	75	$	188	$	1	$	56	$	320

(a)See Note 8 for further information on fair value measurement inputs and methods

	Pension Benefits				Postretirement Benefits
	2023		2022		2023		2022
Long-duration fixed income securities	38	%	38	%	—	%	—	%
Domestic and international equity securities	31		33		9		16
Alternative investments	20		18		13		12
Short-to-intermediate fixed income securities	9		9		77		71
Cash	2		2		1		1
Total	100	%	100	%	100	%	100	%

Change in Projected Benefit Obligation

	Pension Benefits				Postretirement Benefits
(Millions of Dollars)	2023		2022		2023		2022
Change in Benefit Obligation:
Obligation at Jan. 1	$	1,032	$	1,363	$	296	$	369
Service cost	19		29		1		1
Interest cost	58		41		16		10
Actuarial (gain) loss	45		(317)		18		(55)
Plan participants’ contributions	—		—		7		7
Medicare subsidy reimbursements	—		—		—		1
Benefit payments	(83)		(84)		(42)		(37)
Obligation at Dec. 31	$	1,071	$	1,032	$	296	$	296
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	1,031	$	1,351	$	320	$	393
Actual return on plan assets	89		(276)		26		(46)
Employer contributions	—		40		3		3
Plan participants’ contributions	—		—		7		7
Benefit payments	(83)		(84)		(42)		(37)
Fair value of plan assets at Dec. 31	$	1,037	$	1,031	$	314	$	320
Funded status of plans at Dec. 31	$	(34)	$	(1)	$	18	$	24
Amounts recognized in the Consolidated Balance Sheet at Dec. 31:
Noncurrent assets	—		8		18		24
Noncurrent liabilities	(34)		(9)		—		—
Net amounts recognized	$	(34)	$	(1)	$	18	$	24

Amounts Not Yet Recognized as Components of Net Periodic Benefit Costs Recorded on the Balance Sheet Based Upon Expected Recovery in Rates

	Pension Benefits				Postretirement Benefits
(Millions of Dollars)	2023		2022		2023		2022
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	355	$	325	$	59	$	53
Prior service credit	(1)		(1)		—		—
Total	$	354	$	324	$	59	$	53
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	$	3	$	3	$	1	$	—
Noncurrent regulatory assets	351		320		58		53
Net-of-tax accumulated other comprehensive income			1				—
Total	$	354	$	324	$	59	$	53

Measurement date Dec. 31, 2023 Dec. 31, 2022 Dec. 31, 2023 Dec. 31, 2022

Components of Net Periodic Benefit Costs

Net Periodic Benefit Cost (Credit) — Net periodic benefit cost (credit), other than the service cost component, is included in other income (expense) in the statements of income.

Components of net periodic benefit cost (credit) and amounts recognized in other comprehensive income and regulatory assets and liabilities:

	Pension Benefits									Postretirement Benefits
(Millions of Dollars)	2023			2022			2021			2023			2022			2021
Service cost	$	19		$	29		$	32		$	1		$	1		$	1
Interest cost	58			41			39			16			10			11
Expected return on plan assets	(76)			(78)			(73)			(15)			(15)			(16)
Amortization of prior service credit	—			—			—			—			(2)			(4)
Amortization of net loss	1			23			32			1			1			3
Settlement charge (a)	—			3			—			—			—			—
Net periodic pension cost (credit)	2			18			30			3			(5)			(5)
Effects of regulation	9			4			—			—			3			2
Net benefit cost (credit) recognized for financial reporting	$	11		$	22		$	30		$	3		$	(2)		$	(3)
Significant Assumptions Used to Measure Costs:
Discount rate	5.80		%	3.08		%	2.71		%	5.80		%	3.09		%	2.65		%
Expected average long-term increase in compensation level	4.25			3.75			3.75			N/A			N/A			N/A
Expected average long-term rate of return on assets	6.53			6.39			6.38			5.00			4.10			4.10

(a)A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2022, as a result of lump-sum distributions during the plan year, PSCo recorded a total pension settlement charge of $3 million. An immaterial amount was recorded in the income statement in 2022. There were no settlement charges recorded to the qualified pension plans in 2023 or 2021.

Projected Benefit Payments for the Pension and Postretirement Benefit Plans

PSCo’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
2024	$	89	$	31	$	2	$	29
2025	80		30		2		28
2026	80		29		2		27
2027	80		28		2		26
2028	79		27		2		25
2029-2033	384		123		12		111

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2023

Commitments and Contingencies Disclosure [Abstract]

Asset Retirement Obligations

PSCo’s AROs were as follows:

	2023
(Millions  of Dollars)	Jan. 1, 2023		Accretion		Cash Flow Revisions (a)		Dec. 31, 2023
Electric
Steam, hydro and other production	$	180	$	8	$	—	$	188
Wind	44		2		—		46
Distribution	17		—		—		17
Natural gas
Transmission and distribution	235		11		(114)		132
Total liability	$	476	$	21	$	(114)	$	383

(a)In 2023, AROs were revised for changes in timing and estimates of cash flows. Changes in gas transmission and distribution AROs were primarily the result of changes to inflation and discount rate assumptions as well as updated mileage of gas lines and number of services.

	2022
(Millions  of Dollars)	Jan. 1, 2022		Amounts Incurred (a)		Accretion		Cash Flow Revisions (b)		Dec. 31, 2022
Electric
Steam, hydro and other production	$	152	$	34	$	6	$	(12)	$	180
Wind	42		—		2		—		44
Distribution	16		—		1		—		17
Natural gas
Transmission and distribution	212		—		10		13		235
Total liability	$	422	$	34	$	19	$	1	$	476

(a)Amounts incurred related to steam production pond remediation costs.

(b)In 2022, AROs were revised for changes in timing and estimates of cash flows. Revisions in steam, hydro, and other production AROs 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.

Assets and Liabilities, Lessee [Table Text Block]

Operating lease ROU assets:

(Millions of Dollars)	Dec. 31, 2023		Dec. 31, 2022
PPAs	$	623	$	612
Other	112		80
Gross operating lease ROU assets	735		692
Accumulated amortization	(369)		(255)
Net operating lease ROU assets	$	366	$	437

Finance lease ROU assets:

(Millions of Dollars)	Dec. 31, 2023		Dec. 31, 2022
Gas storage facilities	$	160	$	160
Gas pipeline	21		21
Gross finance lease ROU assets	181		181
Accumulated amortization	(67)		(64)
Net finance lease ROU assets	$	114	$	117

Lease, Cost [Table Text Block]

Components of lease expense:

(Millions of Dollars)	2023		2022		2021
Operating leases
PPA capacity payments	$	89	$	91	$	102
Other operating leases (a)	19		20		16
Total operating lease expense (b)	$	108	$	111	$	118
Finance leases
Amortization of ROU assets	$	3	$	4	$	7
Interest expense on lease liability	15		16		17
Total finance lease expense	$	18	$	20	$	24

(a)Includes immaterial short-term lease expense of for 2023, 2022 and 2021.

(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.

Operating and Finance Lease Commitments, Maturity

Commitments under operating and finance leases as of Dec. 31, 2023:

(Millions of Dollars)	PPA (a) (b) Operating Leases		Other Operating Leases		Total Operating Leases		Finance Leases
2024	$	98	$	19	$	117	$	18
2025	97		12		109		18
2026	74		8		82		18
2027	44		8		52		16
2028	20		8		28		15
Thereafter	39		6		45		333
Total minimum obligation	372		61		433		418
Interest component of obligation	(35)		(6)		(41)		(304)
Present value of minimum obligation	$	337	$	55	392		114
Less current portion					(102)		(3)
Noncurrent operating and finance lease liabilities					$	290	$	111
Weighted-average remaining lease term in years					4.6		36.8

(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 2032.

Estimated Future Payments for Capacity and Energy Pursuant to Purchased Power Agreements

At Dec. 31, 2023, the estimated future payments for capacity that PSCo is obligated to purchase pursuant to these executory contracts, subject to availability, were as follows:

(Millions of Dollars)	Capacity
2024	$	3
2025	3
2026	3
2027	1
2028	—
Thereafter	—
Total	$	10

Estimated Minimum Purchases Under Fuel Contracts

Estimated minimum purchases under these contracts as of Dec. 31, 2023:

(Millions of Dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2024	$	143	$	221	$	108
2025	74		12		105
2026	39		—		105
2027	35		—		105
2028	—		—		62
Thereafter	—		—		382
Total	$	291	$	233	$	867

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Other Comprehensive Income (Tables)

12 Months Ended

Dec. 31, 2023

Stockholders' Equity Note [Abstract]

Changes in Accumulated Other Comprehensive Income (Loss), Net of Tax

Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31:

	2023
(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	$	(20)		$	(2)		$	(22)
Other comprehensive loss before reclassifications	—			—			—
Losses reclassified from net accumulated other comprehensive loss:
Amortization of interest rate hedges	1		(a)	—			1
Amortization of net actuarial loss	—			1		(b)	1
Net current period other comprehensive income	1			1			2
Accumulated other comprehensive loss at Dec. 31	$	(19)		$	(1)		$	(20)

(a)Included in interest charges.

(b)Included in the computation of net periodic pension and postretirement benefit costs. See Note 9 for further information.

	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	$	(21)		$	(1)	$	(22)
Other comprehensive loss before reclassifications	—			(1)		(1)
Losses reclassified from net accumulated other comprehensive loss:
Amortization of interest rate hedges	1		(a)	—		1
Net current period other comprehensive income (loss)	1			(1)		—
Accumulated other comprehensive loss at Dec. 31	(20)			(2)		(22)

(a)Included in interest charges.

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Segments and Related Information (Tables)

12 Months Ended

Dec. 31, 2023

Segment Reporting [Abstract]

Results from Operations by Reportable Segment

PSCo’s segment information:

(Millions of Dollars)	2023		2022		2021
Regulated Electric
Operating revenues — external	$	3,731	$	3,795	$	3,413
Intersegment revenue	1		1		1
Total revenues	$	3,732	$	3,796	$	3,414
Depreciation and amortization	692		650		566
Interest charges and financing costs	224		200		179
Income tax benefit	(2)		(11)		(16)
Net income	529		550		495
Regulated Natural Gas
Total revenues	$	1,734	$	1,860	$	1,355
Depreciation and amortization	224		190		171
Interest charges and financing costs	67		59		53
Income tax expense	37		49		45
Net income	149		180		168
All Other
Total revenues (a)	$	54	$	53	$	47
Depreciation and amortization	8		8		7
Interest charges and financing costs	1		1		2
Income tax (benefit) expense	(6)		(1)		4
Net (loss) income	17		(3)		(3)
Consolidated Total
Total revenues (a)	$	5,520	$	5,709	$	4,816
Reconciling eliminations	(1)		(1)		(1)
Total operating revenues	$	5,519	$	5,708	$	4,815
Depreciation and amortization	924		848		744
Interest charges and financing costs	292		260		234
Income tax expense	29		37		33
Net income	695		727		660

(a)Operating revenues include $5 million of other affiliate revenue for the years ended Dec. 31, 2023, 2022 and 2021, respectively. See Note 13 for further information.

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Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2023

Related Party Transactions [Abstract]

Related Party Transactions

Significant affiliate transactions among the companies and related parties for the years ended Dec. 31:

(Millions of Dollars)	2023		2022		2021
Operating revenues:
Other	$	5	$	5	$	5
Operating expenses:
Other operating expenses — paid to Xcel Energy Services Inc.	679		670		617
Interest expense	5		2		—
Interest income	2		—		—

Accounts receivable and payable with affiliates at Dec. 31:

	2023				2022
(Millions of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Minnesota	$	—	$	5	$	2	$	—
NSP-Wisconsin	—		1		—		2
SPS	—		11		—		11
Other subsidiaries of Xcel Energy Inc.	28		66		9		62
	$	28	$	83	$	11	$	75

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Summary of Significant Accounting Policies (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021
Property, Plant and Equipment [Abstract]
Depreciation expense expressed as a percentage of average depreciable property	3.60%	3.40%	3.20%
Cash and Cash Equivalents [Abstract]
Maximum number of months remaing	3 months
Accounts and Financing Receivable, after Allowance for Credit Loss, Current and Noncurrent [Abstract]
Accounts Receivable, Allowance for Credit Loss, Current	$ 56	$ 54
Alternative Revenue Programs [Abstract]
Number of DSM Products, Commercial and Industrial Customers	20
Number of DSM Products, Residential and Low-income Customers	23
maximum number of months following end of annual period in which revenues are to be included	24 months
DSM Measurements	1,000
Public Utilities, Inventory [Line Items]
Inventories	$ 258	319
Maximum number of months remaing	3 months
maximum number of months following end of annual period in which revenues are to be included	24 months
Materials and supplies
Public Utilities, Inventory [Line Items]
Inventories	$ 91	80
Public Utilities, Inventory, Fuel [Member]
Public Utilities, Inventory [Line Items]
Inventories	83	68
Public Utilities, Inventory, Natural Gas [Member]
Public Utilities, Inventory [Line Items]
Inventories	$ 84	$ 171

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Property Plant and Equipment Property Plant and Equipment (Details) - USD ($) $ in Millions		Dec. 31, 2023	Dec. 31, 2022
Property, Plant and Equipment [Line Items]
Property, plant and equipment		$ 27,004	$ 25,317
Accumulated depreciation		5,969	5,665
Property, plant and equipment, net		21,035	19,652
Electric plant
Property, Plant and Equipment [Line Items]
Property, plant and equipment		16,698	15,771
Natural gas plant
Property, Plant and Equipment [Line Items]
Property, plant and equipment		6,321	5,949
Common and other property
Property, Plant and Equipment [Line Items]
Property, plant and equipment		1,472	1,415
Plant to be retired
Property, Plant and Equipment [Line Items]
Property, plant and equipment	[1]	1,203	1,305
CWIP
Property, Plant and Equipment [Line Items]
Property, plant and equipment		$ 1,310	$ 877

[1] Amounts include Comanche Units 2 and 3, Craig Units 1 and 2, Hayden Units 1 and 2 and coal generation assets at Pawnee pending facility gas conversion. Amounts are presented net of accumulated depreciation.

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Property Plant and Equipment Joint Ownership (Details) $ in Millions	Dec. 31, 2023 USD ($)
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 1,643	[1]
Accumulated Depreciation	587	[1]
CWIP	18
Electric Generation | Hayden Unit 1
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	157
Accumulated Depreciation	$ 108
Percent Owned	76.00%
Electric Generation | Hayden Unit 2
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 151
Accumulated Depreciation	$ 87
Percent Owned	37.00%
Electric Generation | Hayden Common Facilities
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 44
Accumulated Depreciation	$ 31
Percent Owned	53.00%
Electric Generation | Craig Units 1 and 2
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 82
Accumulated Depreciation	$ 55
Percent Owned	10.00%
Electric Generation | Craig Common Facilities 1, 2 and 3
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 39
Accumulated Depreciation	$ 25
Percent Owned	7.00%
Electric Generation | Comanche Unit 3
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 916
Accumulated Depreciation	$ 191
Percent Owned	67.00%
Electric Generation | Comanche Common Facilities
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 29
Accumulated Depreciation	$ 4
Percent Owned	77.00%
Electric Transmission | Transmission and Other Facilities
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 189
Accumulated Depreciation	75
Gas Transportation | Rifle to Avon
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	28
Accumulated Depreciation	$ 9
Percent Owned	60.00%
Gas Transportation | Gas Transportation Compressor
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 8
Accumulated Depreciation	$ 2
Percent Owned	50.00%

[1] Projects additionally include $18 million in CWIP.

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Regulatory Assets and Liabilities, Regulatory Assets (Details) - USD ($) $ in Millions		Dec. 31, 2023	Dec. 31, 2022
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 304	$ 411
Regulatory Asset, Noncurrent		1,267	1,277
Regulatory assets not currently earning a return		416	538
Pension and Retiree Medical Obligations
Regulatory Assets [Line Items]
Regulatory Asset, Current		2	3
Regulatory Asset, Noncurrent		396	367
Recoverable Purchased Natural Gas and Electric Energy Costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		221	312
Regulatory Asset, Noncurrent		$ 22	200
Recoverable Purchased Natural Gas and Electric Energy Costs | Minimum
Regulatory Assets [Line Items]
Regulatory Asset, Amortization Period		3 years
Recoverable Purchased Natural Gas and Electric Energy Costs | Maximum
Regulatory Assets [Line Items]
Regulatory Asset, Amortization Period		1 year
Depreciation differences
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 16	16
Regulatory Asset, Noncurrent		$ 184	187
Depreciation differences | Minimum
Regulatory Assets [Line Items]
Regulatory Asset, Amortization Period		1 year
Depreciation differences | Maximum
Regulatory Assets [Line Items]
Regulatory Asset, Amortization Period		10 years
Net AROs
Regulatory Assets [Line Items]
Regulatory Asset, Current	[1]	$ 0	0
Regulatory Asset, Noncurrent	[1]	236	212
Recoverable Deferred Taxes on AFUDC Recorded in Plant
Regulatory Assets [Line Items]
Regulatory Asset, Current		0	0
Regulatory Asset, Noncurrent		135	119
Excess deferred taxes - TCJA
Regulatory Assets [Line Items]
Regulatory Asset, Current		0	2
Regulatory Asset, Noncurrent		55	54
Purchased Power Agreements
Regulatory Assets [Line Items]
Regulatory Asset, Current		4	3
Regulatory Asset, Noncurrent		20	16
Property Tax
Regulatory Assets [Line Items]
Regulatory Asset, Current		3	8
Regulatory Asset, Noncurrent		7	2
Gas pipeline inspection costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		3	0
Regulatory Asset, Noncurrent		$ 25	13
Gas pipeline inspection costs | Minimum
Regulatory Assets [Line Items]
Regulatory Asset, Amortization Period		1 year
Gas pipeline inspection costs | Maximum
Regulatory Assets [Line Items]
Regulatory Asset, Amortization Period		2 years
Conservation programs
Regulatory Assets [Line Items]
Regulatory Asset, Current	[2]	$ 12	8
Regulatory Asset, Noncurrent	[2]	$ 33	16
Conservation programs | Minimum
Regulatory Assets [Line Items]
Regulatory Asset, Amortization Period		1 year
Conservation programs | Maximum
Regulatory Assets [Line Items]
Regulatory Asset, Amortization Period		2 years
Other
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 28	39
Regulatory Asset, Noncurrent		65	43
Environmental remediation costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		0	6
Regulatory Asset, Noncurrent		44	26
Grid modernization costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		15	14
Regulatory Asset, Noncurrent		$ 14	22
Regulatory Asset, Amortization Period		2 years
Revenue Decoupling
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 0	0
Regulatory Asset, Noncurrent		$ 31	$ 0

[1] Includes amounts recorded for future recovery of AROs.

[2] Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

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Regulatory Assets and Liabilities, Regulatory Liabilities (Details) - USD ($) $ in Millions		Dec. 31, 2023	Dec. 31, 2022
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 70	$ 59
Regulatory Liability, Noncurrent		$ 2,562	2,489
Minimum | Deferred Electric, Gas, and Steam Production Costs
Regulatory Liabilities [Line Items]
Regulatory Asset, Amortization Period		1 year
Deferred Income Tax Adjustments and TCJA Refunds
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[1]	$ 2	2
Regulatory Liability, Noncurrent	[1]	1,260	1,298
Plant Removal Costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		0	0
Regulatory Liability, Noncurrent		769	705
Effects of regulation on employee benefit costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[2]	0	0
Regulatory Liability, Noncurrent	[2]	234	227
Renewable Resources and Environmental Initiatives
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		0	0
Regulatory Liability, Noncurrent		152	141
ITC Deferrals
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		1	1
Regulatory Liability, Noncurrent		44	41
Sales True Up and Revenue Decoupling [Member]
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		0	0
Regulatory Liability, Noncurrent		63	55
Conservation programs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		9	19
Regulatory Liability, Noncurrent		$ 0	0
Conservation programs | Minimum
Regulatory Liabilities [Line Items]
Regulatory Liability, Amortization Period		1 year
Deferred Electric, Gas, and Steam Production Costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 34	3
Regulatory Liability, Noncurrent		0	0
Other
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		16	18
Regulatory Liability, Noncurrent		40	22
Formula rates
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		8	16
Regulatory Liability, Noncurrent		$ 0	$ 0
Formula rates | Minimum
Regulatory Liabilities [Line Items]
Regulatory Liability, Amortization Period		1 year
Formula rates | Maximum
Regulatory Liabilities [Line Items]
Regulatory Liability, Amortization Period		2 years

[1] 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.

[2] Includes regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the prepaid pension asset.

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Borrowings and Other Financing Instruments, Short-Term Borrowings (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Short-term Debt [Line Items]
Short-term debt	$ 320	$ 320	$ 294
Letter of Credit
Short-term Debt [Line Items]
Line of Credit Facility, Expiration Period		1 year
Commercial Paper [Member]
Short-term Debt [Line Items]
Borrowing limit	700	$ 700	700	$ 700
Short-term debt	320	320	294	147
Average amount outstanding	$ 189	$ 124	$ 71	$ 26
Weighted average interest rate at period end (percentage)	5.56%	5.56%	4.73%	0.22%
Line of Credit Facility, Interest Rate During Period	5.53%	5.17%	2.56%	0.19%
Maximum amount outstanding	$ 369	$ 454	$ 328	$ 322
Money Pool
Short-term Debt [Line Items]
Borrowing limit	250	250	250	250
Short-term debt	51	51	0	0
Average amount outstanding	$ 64	$ 23	$ 29	$ 12
Line of Credit Facility, Interest Rate During Period	5.33%	5.31%	1.66%	0.07%
Maximum amount outstanding	$ 250	$ 250	$ 250	$ 243
Line of Credit Facility, Interest Rate at Period End	5.34%	5.34%

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Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 320	$ 294
Letter of Credit
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 29	$ 27
Letter of Credit
Line of Credit Facility [Line Items]
Line of Credit Facility, Expiration Period	1 year

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Borrowings and Other Financing Instruments, Credit Facility (Details) - Credit Facility $ in Millions		12 Months Ended
		Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)
Line of Credit Facility [Line Items]
Line Of Credit Facility Debt To Total Capitalization Ratio (as a percent)	[1]	44.80%	44.00%
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval	[2]	2
Line Of Credit Facility Maximum Amount Credit Facility May Be Increased		$ 100
Line Of Credit Facility Maximum Debt To Total Capitalization Ratio Allowed		65.00%
Direct advances on the credit facility outstanding		$ 0	$ 0
PSCo [Member]
Line of Credit Facility [Line Items]
Credit facility	[3]	700
Drawn	[4]	349
Available		$ 351
PSCo [Member]
Line of Credit Facility [Line Items]
Line Of Credit Facility Minimum Threshhold Percentage Of Subsidiary Assets To Consolidated Assets Required To Initiate Cross Default Provisions		15.00%
Line of Credit Facility, Minimum Amount of Indebtedness in Default to Initiate Cross Default Provisions		$ 75

[1] The credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%.

[2] All extension requests are subject to majority bank group approval.

[3] This credit facility matures in September 2027.

[4] Includes letters of credit and outstanding commercial paper.

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Borrowings and Other Financing Instruments, Long-Term Borrowings (Details) - USD ($) $ in Millions		Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net		$ (41)	$ (37)
Unamortized Debt Issuance Expense		(59)	(53)
Long-term Debt, Current Maturities		0	(250)
Long-term Debt		7,450	6,610
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months		0
Long-term Debt, Maturities, Repayments of Principal in Year Two		250
Long-term Debt, Maturities, Repayments of Principal in Year Three		0
Long-term Debt, Maturities, Repayments of Principal in Year Four		0
Long-term Debt, Maturities, Repayments of Principal in Year Five		350
Deferred Finance Costs, Noncurrent, Net		59	53
Long-term Debt		7,450	6,610
First Mortgage Bonds | Series Due March 15, 2023 [Member]
Debt Instrument [Line Items]
Face amount		$ 0	250
Interest rate, stated percentage (in hundredths)		2.50%
First Mortgage Bonds | Series Due May 15, 2025 [Member]
Debt Instrument [Line Items]
Face amount		$ 250	250
Interest rate, stated percentage (in hundredths)		2.90%
First Mortgage Bonds | Series Due June 15, 2028 [Member]
Debt Instrument [Line Items]
Face amount		$ 350	350
Interest rate, stated percentage (in hundredths)		3.70%
First Mortgage Bonds | Series Due Jan. 15, 2031 [Member]
Debt Instrument [Line Items]
Face amount		$ 375	375
Interest rate, stated percentage (in hundredths)		1.90%
First Mortgage Bonds | Series Due Sept. 1, 2037 [Member]
Debt Instrument [Line Items]
Face amount		$ 350	350
Interest rate, stated percentage (in hundredths)		6.25%
First Mortgage Bonds | Series Due Aug. 1, 2038 [Member]
Debt Instrument [Line Items]
Face amount		$ 300	300
Interest rate, stated percentage (in hundredths)		6.50%
First Mortgage Bonds | Series Due Aug. 15, 2041 [Member]
Debt Instrument [Line Items]
Face amount		$ 250	250
Interest rate, stated percentage (in hundredths)		4.75%
First Mortgage Bonds | Series Due Sept. 15, 2042 [Member]
Debt Instrument [Line Items]
Face amount		$ 500	500
Interest rate, stated percentage (in hundredths)		3.60%
First Mortgage Bonds | Series Due March 15, 2043 [Member]
Debt Instrument [Line Items]
Face amount		$ 250	250
Interest rate, stated percentage (in hundredths)		3.95%
First Mortgage Bonds | Series Due March 15, 2044 [Member]
Debt Instrument [Line Items]
Face amount		$ 300	300
Interest rate, stated percentage (in hundredths)		4.30%
First Mortgage Bonds | Series Due June 15, 2046 [Member]
Debt Instrument [Line Items]
Face amount		$ 250	250
Interest rate, stated percentage (in hundredths)		3.55%
First Mortgage Bonds | Series Due June 15, 2047 [Member]
Debt Instrument [Line Items]
Face amount		$ 400	400
Interest rate, stated percentage (in hundredths)		3.80%
First Mortgage Bonds | Series Due June 15, 2048 [Member]
Debt Instrument [Line Items]
Face amount		$ 350	350
Interest rate, stated percentage (in hundredths)		4.10%
First Mortgage Bonds | Series Due September 15, 2049 [Domain]
Debt Instrument [Line Items]
Face amount		$ 400	400
Interest rate, stated percentage (in hundredths)		4.05%
First Mortgage Bonds | Series Due March 1, 2050 [Domain]
Debt Instrument [Line Items]
Face amount		$ 550	550
Interest rate, stated percentage (in hundredths)		3.20%
First Mortgage Bonds | Series Due Jan. 15, 2051 [Member]
Debt Instrument [Line Items]
Face amount		$ 375	375
Interest rate, stated percentage (in hundredths)		2.70%
First Mortgage Bonds | Series Due June 15, 2031
Debt Instrument [Line Items]
Face amount		$ 750	750
Interest rate, stated percentage (in hundredths)		1.875%
First Mortgage Bonds | Series Due June 1, 2032 2
Debt Instrument [Line Items]
Face amount	[1]	$ 300	300
Interest rate, stated percentage (in hundredths)	[1]	4.10%
First Mortgage Bonds | Series Due June 1, 2052
Debt Instrument [Line Items]
Face amount	[1]	$ 400	400
Interest rate, stated percentage (in hundredths)	[1]	4.50%
First Mortgage Bonds | Series Due April 1, 2053
Debt Instrument [Line Items]
Face amount	[2]	$ 850	$ 0
Interest rate, stated percentage (in hundredths)	[2]	5.25%

[1] 2022 financing

[2] 2023 financing.

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Borrowings and Other Financing Instruments Preferred Stock (Details) - PSCo [Member] - $ / shares	Dec. 31, 2023	Dec. 31, 2022
Preferred Stock [Abstract]
Preferred Stock, Shares Authorized	10,000,000
Preferred Stock, Par or Stated Value Per Share	$ 0.01
Preferred stock, shares outstanding (in shares)	0	0
Debt Instrument [Line Items]
Preferred Stock, Shares Authorized	10,000,000
Preferred Stock, Par or Stated Value Per Share	$ 0.01
Preferred stock, shares outstanding (in shares)	0	0

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Revenues (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Retail
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	$ 4,785	$ 4,965	$ 4,049
Retail | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	2,423	2,559	2,002
Retail | C&I
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	2,305	2,354	1,998
Retail | Other
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	57	52	49
Wholesale
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	237	286	228
Transmission
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	90	88	75
Other
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	193	204	203
Total revenue from contracts with customers
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	5,305	5,543	4,555
Alternative revenue and other
Disaggregation of Revenue [Line Items]
Alternative revenue and other	214	165	260
Regulated Electric | Retail
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	3,163	3,236	2,883
Regulated Electric | Retail | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	1,295	1,341	1,174
Regulated Electric | Retail | C&I
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	1,816	1,843	1,660
Regulated Electric | Retail | Other
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	52	52	49
Regulated Electric | Wholesale
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	237	286	228
Regulated Electric | Transmission
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	90	88	75
Regulated Electric | Other
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	61	53	44
Regulated Electric | Total revenue from contracts with customers
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	3,551	3,663	3,230
Regulated Electric | Alternative revenue and other
Disaggregation of Revenue [Line Items]
Alternative revenue and other	180	132	183
Regulated Natural Gas | Retail
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	1,568	1,682	1,124
Regulated Natural Gas | Retail | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	1,109	1,203	816
Regulated Natural Gas | Retail | C&I
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	459	479	308
Regulated Natural Gas | Retail | Other
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	0	0	0
Regulated Natural Gas | Wholesale
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	0	0	0
Regulated Natural Gas | Transmission
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	0	0	0
Regulated Natural Gas | Other
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	132	151	159
Regulated Natural Gas | Total revenue from contracts with customers
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	1,700	1,833	1,283
Regulated Natural Gas | Alternative revenue and other
Disaggregation of Revenue [Line Items]
Alternative revenue and other	34	27	72
All Other | Retail
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	54	47	42
All Other | Retail | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	19	15	12
All Other | Retail | C&I
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	30	32	30
All Other | Retail | Other
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	5	0	0
All Other | Wholesale
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	0	0	0
All Other | Transmission
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	0	0	0
All Other | Other
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	0	0	0
All Other | Total revenue from contracts with customers
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	54	47	42
All Other | Alternative revenue and other
Disaggregation of Revenue [Line Items]
Alternative revenue and other	0	6	5
Total revenues
Disaggregation of Revenue [Line Items]
Total revenues	5,519	5,708	4,815
Total revenues | Regulated Electric
Disaggregation of Revenue [Line Items]
Total revenues	3,731	3,795	3,413
Total revenues | Regulated Natural Gas
Disaggregation of Revenue [Line Items]
Total revenues	1,734	1,860	1,355
Total revenues | All Other
Disaggregation of Revenue [Line Items]
Total revenues	$ 54	$ 53	$ 47

XML

State Audits	12 Months Ended
	Dec. 31, 2023 USD ($)
Income Tax Disclosure [Abstract]
Potential Tax Adjustments	$ 0

XML

Unrealized Tax Benefits - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Jan. 01, 2023	Jan. 01, 2022	Jan. 01, 2021
Income Tax Disclosure [Abstract]
Upper bound of decrease in unrecognized tax benefit that is reasonably possible	$ 4
Unrecognized Tax Benefits, Income Tax Penalties Expense	0
Unrecognized tax benefit — Permanent tax positions	12	$ 11
Unrecognized tax benefit — Temporary tax positions	0	2
Total unrecognized tax benefit	12	13	$ 11	$ 13	$ 11	$ 9
Additions based on tax positions related to the current year	2	2	2
Reductions for tax positions of prior years	(3)	0	$ 0
NOL and tax credit carryforwards	$ (11)	$ (12)

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Other Income Tax Matters - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022		Dec. 31, 2021
Income Tax Examination [Line Items]
Federal detriment		$ 3	$ 4
Federal Benefit		1	2
Federal NOL carryforward		0	5
Federal tax credit carryforwards		444	368
State NOL carryforwards		0	223
state tax credit carryforward, net of federal detirment	[1]	13	16
valuation allowances for state credit carryforwards, net of federal benefit	[2]	$ (3)	$ (6)
Federal statutory rate		21.00%	21.00%		21.00%
State income tax on pretax income, net of federal tax effect		3.50%	3.50%		3.60%
Effective Income Tax Rate Reconciliation, Tax Credit, Percent	[3]	(14.50%)	(14.30%)		(14.30%)
Plant regulatory differences (b)	[4]	(5.50%)	(4.50%)		(4.60%)
Other tax credits, net NOL & tax credit allowances		(1.10%)	(1.10%)		(1.00%)
Other, net		0.60%	0.20%		0.10%
Effective income tax rate		4.00%	4.80%		4.80%
Total income tax expense		$ 29	$ 37		$ 33
Deferred tax (benefit) expense excluding items below		(89)	23		63
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities		(48)	(32)		(42)
Tax expense allocated to other comprehensive income and other		(1)	(1)		0
Total deferred tax assets		(178)	(10)		(21)
Operating lease liabilities		392
Adjustments to deferred income taxes for wind production tax credit cash transfers	[5]	(40)	0		0
Deferred Tax Assets, Valuation Allowance		(3)	0
income tax expense [Member]
Income Tax Examination [Line Items]
Current federal tax expense		182	39		16
Current state tax expense		28	11		0
Current change in unrecognized tax benefit		0	0		(1)
Deferred federal tax benefit		(181)	(32)		(13)
Deferred state tax expense		2	21		31
Deferred change in unrecognized tax expense		1	1		3
Deferred ITCs		3	3		(3)
Total income tax expense		29	37		$ 33
Net Deferred Tax Liablility [Member]
Income Tax Examination [Line Items]
Deferred ITCs		(10)	(7)	[6]
Total deferred tax assets		(897)	(850)	[6]
Differences between book and tax bases of property		2,326	2,315	[6]
Regulatory assets		289	243	[6]
Operating Lease Assets		95	112	[3]
Deferred Fuel Cost		51	125	[6]
Pension expense and other employee benefits		22	27	[6]
Other		8	11	[6]
Total deferred tax liabilities		2,791	2,833	[6]
Deferred Tax Assets, Tax Credit Carryforwards		457	385	[6]
Regulatory Liability		291	292	[6]
Operating lease liabilities		95	112	[6]
Bad debts		14	14	[6]
Operating Loss Carryforwards		0	9
Tax Credit Valuation Allowance		(6)	(6)	[6]
Other		32	16	[6]
Net deferred tax liability		1,894	1,983	[6]
Deferred Tax Assets Rate Refund		$ 4	$ 21	[6]

[1] State tax credit carryforwards are net of federal detriment of $3 million and $4 million as of Dec. 31, 2023 and 2022, respectively.

[2] Valuation allowances for state tax credit carryforwards were net of federal benefit of $1 million and $2 million as of Dec. 31, 2023 and 2022, respectively.

[3] Wind PTCs net of estimated transfer discount are credited to customers (reduction to revenue) and do not materially impact net income.

[4] Plant regulatory differences primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit are offset by corresponding revenue reductions.

[5] Proceeds from tax credit transfers are included in cash received (paid) for income taxes in the consolidated statement of cash flows.

[6] Prior periods have been reclassified to conform to current year presentation.

XML

Interest Rate Derivatives (Details) - Interest Rate Swap $ in Millions	Dec. 31, 2023 USD ($)
Derivative [Line Items]
Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net	$ 1
Derivative Liability, Notional Amount	$ 0

XML

Commodity Derivatives (Details) MWh in Millions, MMBTU in Millions, $ in Millions		Dec. 31, 2023 USD ($) MWh MMBTU	Dec. 31, 2022 MWh MMBTU
Derivative [Line Items]
Cash Flow Hedges Derivative Instruments at Fair Value, Net | $		$ 0
Electric Commodity
Derivative [Line Items]
Notional Amount | MWh	[1],[2]	2	8
Natural Gas Commodity
Derivative [Line Items]
Notional Amount | MMBTU	[1],[2]	20	43

[1] Not reflective of net positions in the underlying commodities.

[2] Notional amounts for options included on a gross basis, but weighted for the probability of exercise.

XML

Consideration of Credit Risk and Concentrations (Details) - Credit Concentration Risk $ in Millions	Dec. 31, 2023 USD ($) Counterparty
Derivative [Line Items]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure	10
Municipal or Cooperative Entities or Other Utilities
Derivative [Line Items]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure	8
External Credit Rating, Investment Grade
Derivative [Line Items]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure	4
Wholesale, trading and non trading commodity credit exposure for the most significant counterparties | $	$ 30
Percentage of wholesale, trading and non trading commodity credit exposure for the most significant counterparties	36.00%
External Credit Rating, Non Investment Grade [Member]
Derivative [Line Items]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure	0
Internal Investment Grade
Derivative [Line Items]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure	6
Wholesale, trading and non trading commodity credit exposure for the most significant counterparties | $	$ 40
Percentage of wholesale, trading and non trading commodity credit exposure for the most significant counterparties	48.00%

XML

Qualifying Cash Flow Hedges (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Impact of Derivative Activity [Abstract]
Fair Value Hedges, Net		$ 0	$ 0	$ 0
Not Designated as Hedging Instrument
Impact of Derivative Activity [Abstract]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax		0	0	0
Derivative Instruments Gain (Loss) Reclassified To Regulatory Assets And Liabilities Net		(13)	(15)	(1)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net		0	0	0
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities)		(15)	(8)	4
Derivative, Gain (Loss) on Derivative, Net		(21)	(10)	(3)
Not Designated as Hedging Instrument | Commodity Trading Contract
Impact of Derivative Activity [Abstract]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net		0	0	0
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities)		0	0	0
Derivative, Gain (Loss) on Derivative, Net	[1]	(5)	7	12
Not Designated as Hedging Instrument | Natural Gas Commodity Contract
Impact of Derivative Activity [Abstract]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax		0	0	0
Derivative Instruments Gain (Loss) Reclassified To Regulatory Assets And Liabilities Net		(13)	(15)	(1)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net		0	0	0
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities)	[2]	(15)	(8)	(4)
Derivative, Gain (Loss) on Derivative, Net	[2],[3]	(16)	(17)	(15)
Designated as Hedging Instrument | Cash Flow Hedges
Impact of Derivative Activity [Abstract]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net		(1)	(1)	(2)
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities)		0	0	0
Derivative, Gain (Loss) on Derivative, Net		0	0	0
Designated as Hedging Instrument | Cash Flow Hedges | Interest Rate Contract
Impact of Derivative Activity [Abstract]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	[4]	(1)	(1)	(2)
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities)		0	0	0
Derivative, Gain (Loss) on Derivative, Net		$ 0	$ 0	$ 0

[1] Recorded to electric revenues. Presented amounts do not reflect non-derivative transactions or margin sharing with customers.

[2] 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.

[3] Relates primarily to option premium amortization.

[4] Recorded to interest charges.

XML

Credit Related Contingent Features (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Fair Value Disclosures [Abstract]
Derivative, Gross Liability Position, Aggregate Fair Value	$ 0	$ 0
Derivative, Gross Liability with Cross Default Position, Aggregate Fair Value	8	0
Collateral Already Posted Adequate Assurance Clauses Aggregate Fair Value	$ 0	$ 0

XML

Recurring Fair Value Measurements (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Derivatives, Fair Value [Line Items]
Derivative Asset, Noncurrent, Statement of Financial Position [Extensible Enumeration]		Assets	Assets
Derivative Liability, Current, Statement of Financial Position [Extensible Enumeration]		Liabilities, Current	Liabilities, Current
Return Cash Collateral		$ 0	$ 0
Reclaim Cash Collateral		$ 4	$ 46
Derivative Asset, Current, Statement of Financial Position [Extensible Enumeration]		Assets, Current	Assets, Current
Commodity Contract
Derivatives, Fair Value [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs, Beginning Balance		$ 9	$ (63)	$ (44)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Settlements	[1]	0	12	4
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings	[1]	(9)	60	(23)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs, Ending Balance		0	9	$ (63)
Fair Value Measured on a Recurring Basis
Derivatives, Fair Value [Line Items]
Derivative Asset, Net		15	22
Derivative Liability, Current		17	30
Derivative Liability, Net		0	9
Derivative Asset, Current		11	65
Fair Value Measured on a Recurring Basis | Other Derivative Instruments | Commodity Contract
Derivatives, Fair Value [Line Items]
Derivative Asset, Net		15	22
Derivative Liability, Current		9	20
Derivative Liability, Net		0	9
Derivative Asset, Current		3	53
Fair Value Measured on a Recurring Basis | Other Derivative Instruments | Natural Gas Commodity Contract
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		8	12
Netting	[2]	0	0
Derivative Liability, Current		8	10
Derivative Liability, Gross		8	10
Netting	[2]	0	0
Derivative Asset, Current		8	12
Fair Value Measured on a Recurring Basis | Other Derivative Instruments | Natural Gas Commodity Contract | Level 1
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		0	0
Derivative Liability, Gross		0	0
Fair Value Measured on a Recurring Basis | Other Derivative Instruments | Natural Gas Commodity Contract | Level 2
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		8	12
Derivative Liability, Gross		8	10
Fair Value Measured on a Recurring Basis | Other Derivative Instruments | Natural Gas Commodity Contract | Level 3
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		0	0
Derivative Liability, Gross		0	0
Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		28	249
Netting	[2]	(17)	(184)
Fair Value Measured on a Recurring Basis | Other Current Assets | Level 1
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		1	16
Fair Value Measured on a Recurring Basis | Other Current Assets | Level 2
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		27	232
Fair Value Measured on a Recurring Basis | Other Current Assets | Level 3
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		0	1
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Contract
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		20	237
Netting	[2]	(17)	(184)
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Contract | Level 1
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		1	16
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Contract | Level 2
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		19	220
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Contract | Level 3
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		0	1
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		15	53
Netting	[2]	0	(31)
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Level 1
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		6	12
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Level 2
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		9	32
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Level 3
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		0	9
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Contract
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		15	53
Netting	[2]	0	(31)
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Contract | Level 1
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		6	12
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Contract | Level 2
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		9	32
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Contract | Level 3
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		0	9
Fair Value Measured on a Recurring Basis | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		34	253
Netting	[2]	(17)	(223)
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Level 1
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		1	5
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Level 2
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		33	247
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Level 3
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		0	1
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Contract
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		26	243
Netting	[2]	(17)	(223)
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Contract | Level 1
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		1	5
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Contract | Level 2
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		25	237
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Contract | Level 3
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		0	1
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		3	47
Netting	[2]	(3)	(38)
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Level 1
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		2	7
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Level 2
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		1	40
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Level 3
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		0	0
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Contract
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		3	47
Netting	[2]	(3)	(38)
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Contract | Level 1
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		2	7
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Contract | Level 2
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		1	40
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Contract | Level 3
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		$ 0	$ 0

[1] 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.

[2] PSCo nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement. At Dec. 31, 2023 and 2022, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2023 and 2022, derivative assets and liabilities include rights to reclaim cash collateral of $4 million and $46 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.

XML

Fair Value of Long-Term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Derivatives, Fair Value [Line Items]
Long-term Debt, Gross	$ 7,450	$ 6,860
Level 2
Derivatives, Fair Value [Line Items]
Long-term debt, Fair Value	$ 6,580	$ 5,881

XML

Benefit Plans and Other Postretirement Benefits, Pension Benefits (Details) - USD ($)		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023		Dec. 31, 2022		Dec. 31, 2021	Jan. 01, 2020	Jan. 01, 2019
Target Pension Asset Allocations [Abstract]
annual interest crediting rates			$ 5.03		$ 5.14		$ 2.26
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan assets at net asset value			464,000,000	[1]	317,000,000	[2]
Fair value of plan assets			1,037,000,000	[1]	1,031,000,000	[2]	1,351,000,000
Pension Benefits [Abstract]
Total benefit obligation			1,071,000,000		1,032,000,000			$ 1,032,000,000	$ 1,363,000,000
Net benefit cost recognized for financial reporting			$ 11,000,000		$ 22,000,000		$ 30,000,000
Expected average long-term rate of return on assets (as a percent)			6.53%		6.39%		6.38%
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			100.00%		100.00%
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	[3]		$ 0		$ (3,000,000)		$ 0
Pension Plan [Member] | PSCo [Member]
Target Pension Asset Allocations [Abstract]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement					(3,000,000)
Total contributions to Xcel Energy's pension plans during the period			0		40,000,000		$ 46,000,000
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Pension Benefits [Abstract]
Total benefit obligation			1,000,000		1,000,000
Xcel Energy Inc. | Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Pension Benefits [Abstract]
Total benefit obligation			12,000,000		11,000,000
Net benefit cost recognized for financial reporting			2,000,000		17,000,000
Equity Securities [Member] | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan assets at net asset value			0	[1]	0	[2]
Fair value of plan assets			$ 12,000,000	[1]	$ 17,000,000	[2]
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			31.00%		33.00%
Long-Duration Fixed Income and Interest Rate Swap Securities [Member] | Pension Plan [Member]
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			38.00%		38.00%
Short-to-intermediate fixed income securities [Member] | Pension Plan [Member]
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			9.00%		9.00%
Alternative Investments [Member] | Pension Plan [Member]
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			20.00%		18.00%
Cash | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan assets at net asset value			$ 0	[1]	$ 0	[2]
Fair value of plan assets			$ 94,000,000	[1]	$ 52,000,000	[2]
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			2.00%		2.00%
Subsequent Event | Pension Plan [Member]
Pension Benefits [Abstract]
Expected average long-term rate of return on assets for next fiscal year (as a percent)		6.53%

[1] See Note 8 for further information on fair value measurement inputs and methods.

[2] See Note 8 for further information on fair value measurement inputs and methods.

[3] A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2022, as a result of lump-sum distributions during the plan year, PSCo recorded a total pension settlement charge of $3 million. An immaterial amount was recorded in the income statement in 2022. There were no settlement charges recorded to the qualified pension plans in 2023 or 2021

XML

Benefit Plans and Other Postretirement Benefits, Fair Value of Pension Plan Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023		Dec. 31, 2022		Dec. 31, 2021	Jan. 01, 2020	Jan. 01, 2019
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Liability, Defined Benefit Plan, Noncurrent	$ (40)		$ (13)
assets transferred	0		0
Pension Plan [Member]
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	1,037	[1]	1,031	[2]	$ 1,351
Plan assets at net asset value	(464)	[1]	(317)	[2]
Service cost	19		29		32
Interest cost	58		41		39
Actuarial (gain) loss	45		(317)
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant	0		0
Medicare subsidy reimbursements	0		0
Defined Benefit Plan, Benefit Obligation, Benefits Paid	(83)		(84)
Total benefit obligation	1,071		1,032			$ 1,032	$ 1,363
Actual return (loss) on plan assets	89		(276)
Employer contributions	0		40
Plan participants' contributions	0		0
Defined Benefit Plan, Plan Assets, Benefits Paid	(83)		(84)
Assets for Plan Benefits, Defined Benefit Plan	0		8
Liability, Defined Benefit Plan, Noncurrent	(34)		(9)
Pension Plan [Member] | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	283	[1]	424	[2]
Pension Plan [Member] | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	289	[1]	289	[2]
Pension Plan [Member] | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	1	[1]	1	[2]
Pension Plan [Member] | Cash
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	94	[1]	52	[2]
Plan assets at net asset value	0	[1]	0	[2]
Pension Plan [Member] | Cash | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	94	[1]	52	[2]
Pension Plan [Member] | Cash | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	[1]	0	[2]
Pension Plan [Member] | Cash | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	[1]	0	[2]
Pension Plan [Member] | Commingled funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	641	[1]	672	[2]
Plan assets at net asset value	(464)	[1]	(317)	[2]
Pension Plan [Member] | Commingled funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	177	[1]	355	[2]
Pension Plan [Member] | Commingled funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	[1]	0	[2]
Pension Plan [Member] | Commingled funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	[1]	0	[2]
Pension Plan [Member] | Debt Securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	288	[1]	287	[2]
Plan assets at net asset value	0	[1]	0	[2]
Pension Plan [Member] | Debt Securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	[1]	0	[2]
Pension Plan [Member] | Debt Securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	287	[1]	286	[2]
Pension Plan [Member] | Debt Securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	1	[1]	1	[2]
Pension Plan [Member] | Equity Securities [Member]
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	12	[1]	17	[2]
Plan assets at net asset value	0	[1]	0	[2]
Pension Plan [Member] | Equity Securities [Member] | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	12	[1]	17	[2]
Pension Plan [Member] | Equity Securities [Member] | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	[1]	0	[2]
Pension Plan [Member] | Equity Securities [Member] | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	[1]	0	[2]
Pension Plan [Member] | Other
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	2	[1]	3	[2]
Plan assets at net asset value	0	[1]	0	[2]
Pension Plan [Member] | Other | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	[1]	0	[2]
Pension Plan [Member] | Other | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	2	[1]	3	[2]
Pension Plan [Member] | Other | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	[1]	0	[2]
Other Postretirement Benefits Plan [Member]
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	314	[2]	320	[1]	393
Plan assets at net asset value	(63)	[2]	(56)	[1]
Service cost	1		1		1
Interest cost	16		10		$ 11
Actuarial (gain) loss	18		(55)
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant	7		7
Medicare subsidy reimbursements	0		1
Defined Benefit Plan, Benefit Obligation, Benefits Paid	(42)		(37)
Total benefit obligation	296		296			$ 296	$ 369
Actual return (loss) on plan assets	26		(46)
Employer contributions	3		3
Plan participants' contributions	7		7
Defined Benefit Plan, Plan Assets, Benefits Paid	(42)		(37)
Assets for Plan Benefits, Defined Benefit Plan	18		24
Liability, Defined Benefit Plan, Noncurrent	0		0
Other Postretirement Benefits Plan [Member] | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	49	[2]	75	[1]
Other Postretirement Benefits Plan [Member] | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	201	[2]	188	[1]
Other Postretirement Benefits Plan [Member] | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	1	[2]	1	[1]
Other Postretirement Benefits Plan [Member] | Cash
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	29	[2]	28	[1]
Plan assets at net asset value	0	[2]	0	[1]
Other Postretirement Benefits Plan [Member] | Cash | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	29	[2]	28	[1]
Other Postretirement Benefits Plan [Member] | Cash | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	[2]	0	[1]
Other Postretirement Benefits Plan [Member] | Cash | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	[2]	0	[1]
Other Postretirement Benefits Plan [Member] | Commingled funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	83	[2]	103	[1]
Plan assets at net asset value	(63)	[2]	(56)	[1]
Other Postretirement Benefits Plan [Member] | Commingled funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	20	[2]	47	[1]
Other Postretirement Benefits Plan [Member] | Commingled funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	[2]	0	[1]
Other Postretirement Benefits Plan [Member] | Commingled funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	[2]	0	[1]
Other Postretirement Benefits Plan [Member] | Debt Securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	166	[2]	154	[1]
Plan assets at net asset value	0	[2]	0	[1]
Other Postretirement Benefits Plan [Member] | Debt Securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	[2]	0	[1]
Other Postretirement Benefits Plan [Member] | Debt Securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	165	[2]	153	[1]
Other Postretirement Benefits Plan [Member] | Debt Securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	1	[2]	1	[1]
Other Postretirement Benefits Plan [Member] | Other
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	1	[2]	(1)	[1]
Plan assets at net asset value	0	[2]	0	[1]
Other Postretirement Benefits Plan [Member] | Other | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	[2]	0	[1]
Other Postretirement Benefits Plan [Member] | Other | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	1	[2]	(1)	[1]
Other Postretirement Benefits Plan [Member] | Other | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 0	[2]	$ 0	[1]

[1] See Note 8 for further information on fair value measurement inputs and methods.

[2] See Note 8 for further information on fair value measurement inputs and methods.

XML

Benefit Plans and Other Postretirement Benefits, Pension Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) $ in Millions		12 Months Ended
		Dec. 31, 2024 USD ($)		Dec. 31, 2023 USD ($) Plan		Dec. 31, 2022 USD ($)		Dec. 31, 2021 USD ($)
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Utilities Operating Expense, Maintenance, Operations, and Other Costs and Expenses				$ 865.0		$ 905.0		$ 831.0
Significant Assumptions Used to Measure Costs [Abstract]
Liability, Defined Benefit Plan, Noncurrent				40.0		13.0
Other Pension, Postretirement and Supplemental Plans [Member]
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1		$ 1.0		1.0
Obligation at Dec. 31				1.0		1.0
Other Pension, Postretirement and Supplemental Plans [Member] | Xcel Energy Inc.
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1		12.0		11.0
Obligation at Dec. 31				12.0		11.0
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Net benefit cost recognized for financial reporting				2.0		17.0
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated Benefit Obligation at Dec. 31				1,010.0		992.0
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1		1,071.0		1,032.0
Service cost				19.0		29.0		32.0
Interest cost				58.0		41.0		39.0
Actuarial (gain) loss				45.0		(317.0)
Benefit payments				(83.0)		(84.0)
Obligation at Dec. 31				1,071.0		1,032.0
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		$ 1,037.0	[1]	1,031.0	[2]	1,351.0
Actual return (loss) on plan assets				89.0		(276.0)
Employer contributions				0.0		40.0
Plan participants' contributions				0.0		0.0
Benefit payments				(83.0)		(84.0)
Fair value of plan assets at Dec. 31				1,037.0	[1]	1,031.0	[2]	1,351.0
Funded Status of Plans at Dec. 31 [Abstract]
Funded status				34.0		1.0
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss				355.0		325.0
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, Prior Service Cost (Credit), before Tax				(1.0)		(1.0)
Total				354.0		324.0
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates [Abstract]
Current regulatory assets				3.0		3.0
Noncurrent regulatory assets				351.0		320.0
Net-of-tax accumulated OCI						1.0
Total				$ 354.0		$ 324.0
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)				5.49%		5.80%
Expected average long-term increase in compensation level (as a percent)				4.25%		4.25%
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost				$ 19.0		$ 29.0		32.0
Interest cost				58.0		41.0		39.0
Expected return on plan assets				(76.0)		(78.0)		(73.0)
Amortization of prior service (credit) cost				0.0		0.0		0.0
Amortization of net loss				1.0		23.0		32.0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	[3]			0.0		(3.0)		0.0
Net periodic pension cost				2.0		18.0		30.0
Defined Benefit Plan, Costs Not Recognized Due To Regulation				9.0		4.0		0.0
Net benefit cost recognized for financial reporting				$ 11.0		$ 22.0		$ 30.0
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)				5.80%		3.08%		2.71%
Expected average long-term increase in compensation level (as a percent)				4.25%		3.75%		3.75%
Expected average long-term rate of return on assets (as a percent)				6.53%		6.39%		6.38%
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant				$ 0.0		$ 0.0
Medicare subsidy reimbursements				0.0		0.0
Liability, Defined Benefit Plan, Noncurrent				34.0		9.0
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position				(34.0)		(1.0)
Pension Plan [Member] | PSCo [Member]
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period				$ 0.0		40.0		$ 46.0
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement						$ (3.0)
Pension Plan [Member] | Xcel Energy Inc.
Cash Flows [Abstract]
Number of pension plans to which contributions were made | Plan				4
Pension Plan [Member] | Subsequent Event
Significant Assumptions Used to Measure Costs [Abstract]
Expected average long-term rate of return on assets for next fiscal year (as a percent)		6.53%

[1] See Note 8 for further information on fair value measurement inputs and methods.

[2] See Note 8 for further information on fair value measurement inputs and methods.

[3] A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2022, as a result of lump-sum distributions during the plan year, PSCo recorded a total pension settlement charge of $3 million. An immaterial amount was recorded in the income statement in 2022. There were no settlement charges recorded to the qualified pension plans in 2023 or 2021

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Benefit Plans and Other Postretirement Benefits, Postretirement Health Care Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Postretirement Health Care Benefits [Abstract]
Estimated costs of health plan subsidies - VRP	$ 2
Estimated cost of other medical benefits - VRP		$ 0
Other Postretirement Benefits Plan [Member]
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	100.00%	100.00%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	5.54%	5.80%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Pre-65	6.50%	6.50%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Post-65	5.50%	5.50%
Ultimate health care trend assumption rate (as a percent)	4.50%	4.50%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate, VRP	0.0550
Defined Benefit Plan, Health Care Cost Trend Rate Assumed and Ultimate Trend Assumption, VRP	0.0700
Other Postretirement Benefits Plan [Member] | Domestic and international equity securities
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	9.00%	16.00%
Other Postretirement Benefits Plan [Member] | Long-Duration Fixed Income and Interest Rate Swap Securities [Member]
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	0.00%	0.00%
Other Postretirement Benefits Plan [Member] | Short-to-intermediate fixed income securities
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	77.00%	71.00%
Other Postretirement Benefits Plan [Member] | Alternative investments
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	13.00%	12.00%
Other Postretirement Benefits Plan [Member] | Cash
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	1.00%	1.00%
Pension Plan [Member]
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	100.00%	100.00%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	5.49%	5.80%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase	4.25%	4.25%
Pension Plan [Member] | Domestic and international equity securities
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	31.00%	33.00%
Pension Plan [Member] | Long-Duration Fixed Income and Interest Rate Swap Securities [Member]
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	38.00%	38.00%
Pension Plan [Member] | Short-to-intermediate fixed income securities
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	9.00%	9.00%
Pension Plan [Member] | Alternative investments
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	20.00%	18.00%
Pension Plan [Member] | Cash
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	2.00%	2.00%

XML

Benefit Plans and Other Postretirement Benefits, Fair Value of Postretirement Benefit Plan Assets (Details) - Other Postretirement Benefits Plan [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023		Dec. 31, 2022		Dec. 31, 2021
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 314	[1]	$ 320	[2]	$ 393
Plan assets at net asset value	63	[1]	56	[2]
Service cost	1		1		$ 1
Service cost			1
Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	49	[1]	75	[2]
Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	201	[1]	188	[2]
Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	1	[1]	1	[2]
Debt Securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	166	[1]	154	[2]
Plan assets at net asset value	0	[1]	0	[2]
Debt Securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	[1]	0	[2]
Debt Securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	165	[1]	153	[2]
Debt Securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	1	[1]	1	[2]
Cash
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	29	[1]	28	[2]
Plan assets at net asset value	0	[1]	0	[2]
Cash | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	29	[1]	28	[2]
Cash | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	[1]	0	[2]
Cash | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	[1]	0	[2]
Insurance contracts
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	35	[1]	36	[2]
Plan assets at net asset value	0	[1]	0	[2]
Insurance contracts | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	[1]	0	[2]
Insurance contracts | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	35	[1]	36	[2]
Insurance contracts | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	[1]	0	[2]
Other
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	1	[1]	(1)	[2]
Plan assets at net asset value	0	[1]	0	[2]
Other | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	[1]	0	[2]
Other | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	1	[1]	(1)	[2]
Other | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	[1]	0	[2]
Commingled funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	83	[1]	103	[2]
Plan assets at net asset value	63	[1]	56	[2]
Commingled funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	20	[1]	47	[2]
Commingled funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	[1]	0	[2]
Commingled funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 0	[1]	$ 0	[2]

[1] See Note 8 for further information on fair value measurement inputs and methods.

[2] See Note 8 for further information on fair value measurement inputs and methods.

XML

Benefit Plans and Other Postretirement Benefits, Postretirement Benefit Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) - USD ($)		12 Months Ended
		Dec. 31, 2023		Dec. 31, 2022		Dec. 31, 2021
Significant Assumptions Used to Measure Costs [Abstract]
Liability, Defined Benefit Plan, Noncurrent		$ 40,000,000		$ 13,000,000
Defined Contribution Plan, Administrative Expense		13,000,000		13,000,000
Other Postretirement Benefits Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan assets at net asset value		63,000,000	[1]	56,000,000	[2]
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1		296,000,000
Service cost		1,000,000		1,000,000		$ 1,000,000
Interest cost		16,000,000		10,000,000		11,000,000
Medicare subsidy reimbursements		0		1,000,000
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant		7,000,000		7,000,000
Actuarial (gain) loss		18,000,000		(55,000,000)
Benefit payments		(42,000,000)		(37,000,000)
Obligation at Dec. 31		296,000,000		296,000,000
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		320,000,000	[2]	393,000,000
Actual return (loss) on plan assets		26,000,000		(46,000,000)
Plan participants' contributions		7,000,000		7,000,000
Employer contributions		3,000,000		3,000,000
Benefit payments		(42,000,000)		(37,000,000)
Fair value of plan assets at Dec. 31		314,000,000	[1]	320,000,000	[2]	393,000,000
Funded Status of Plans at Dec. 31 [Abstract]
Funded status		18,000,000		24,000,000
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss		59,000,000		53,000,000
Prior service (credit) cost		0		0
Total		59,000,000		53,000,000
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates [Abstract]
Noncurrent regulatory assets		$ 58,000,000		$ 53,000,000
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Pre-65		6.50%		6.50%
Ultimate health care trend assumption rate (as a percent)		4.50%		4.50%
Period until ultimate trend rate is reached (in years)		6		7
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		$ 1,000,000		$ 1,000,000		1,000,000
Interest cost		16,000,000		10,000,000		11,000,000
Expected return on plan assets		(15,000,000)		(15,000,000)		(16,000,000)
Amortization of prior service (credit) cost		0		(2,000,000)		(4,000,000)
Amortization of net loss		1,000,000		1,000,000		3,000,000
Net periodic pension cost		$ 3,000,000		$ (5,000,000)		$ (5,000,000)
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)		5.80%		3.09%		2.65%
Expected average long-term rate of return on assets (as a percent)		5.00%		4.10%		4.10%
Liability, Defined Benefit Plan, Noncurrent		$ 0		$ 0
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position		$ 18,000,000		$ 24,000,000
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		5.54%		5.80%
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Current Regulatory Assets		$ 1,000,000		$ 0
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Net-Of-Tax Accumulated Other Comprehensive Income				0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	[3]	0		0		$ 0
Defined Benefit Plan, Costs Not Recognized Due To Regulation		0		3,000,000		2,000,000
Net benefit cost recognized for financial reporting		$ 3,000,000		$ (2,000,000)		(3,000,000)
Target pension asset allocations (as a percent)		100.00%		100.00%
Defined Benefit Plan, Expected Future Benefit Payment, Next Twelve Months		$ 31,000,000
Defined Benefit Plan, Expected Future Prescription Drug Subsidy Receipt, Next Twelve Months		2,000,000
Defined Benefit Plan Net Projected Benefit Payments In Year One		29,000,000
Defined Benefit Plan, Expected Future Benefit Payment, Year Two		30,000,000
Defined Benefit Plan, Expected Future Prescription Drug Subsidy Receipt, Year Two		2,000,000
Defined Benefit Plan Net Projected Benefit Payments In Year Two		28,000,000
Defined Benefit Plan, Expected Future Benefit Payment, Year Three		29,000,000
Defined Benefit Plan, Expected Future Prescription Drug Subsidy Receipt, Year Three		2,000,000
Defined Benefit Plan Net Projected Benefit Payments In Year Three		27,000,000
Defined Benefit Plan, Expected Future Benefit Payment, Year Four		28,000,000
Defined Benefit Plan, Expected Future Prescription Drug Subsidy Receipt, Year Four		2,000,000
Defined Benefit Plan Net Projected Benefit Payments In Year Four		26,000,000
Defined Benefit Plan, Expected Future Benefit Payment, Year Five		27,000,000
Defined Benefit Plan, Expected Future Prescription Drug Subsidy Receipt, Year Five		2,000,000
Defined Benefit Plan Net Projected Benefit Payments In Year Five		25,000,000
Defined Benefit Plan, Expected Future Benefit Payment, Five Fiscal Years Thereafter		123,000,000
Defined Benefit Plan, Expected Future Prescription Drug Subsidy Receipt, after Year Five		12,000,000
Defined Benefit Plan Net Projected Benefit Payments In Five Fiscal Years Thereafter		$ 111,000,000
Other Postretirement Benefits Plan [Member] | Domestic and international equity securities
Significant Assumptions Used to Measure Costs [Abstract]
Target pension asset allocations (as a percent)		9.00%		16.00%
Other Postretirement Benefits Plan [Member] | Long-Duration Fixed Income and Interest Rate Swap Securities [Member]
Significant Assumptions Used to Measure Costs [Abstract]
Target pension asset allocations (as a percent)		0.00%		0.00%
Other Postretirement Benefits Plan [Member] | Short-to-intermediate fixed income securities
Significant Assumptions Used to Measure Costs [Abstract]
Target pension asset allocations (as a percent)		77.00%		71.00%
Other Postretirement Benefits Plan [Member] | Alternative investments
Significant Assumptions Used to Measure Costs [Abstract]
Target pension asset allocations (as a percent)		13.00%		12.00%
Other Postretirement Benefits Plan [Member] | Cash
Defined Benefit Plan Disclosure [Line Items]
Plan assets at net asset value		$ 0	[1]	$ 0	[2]
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	[2]	28,000,000
Fair value of plan assets at Dec. 31		$ 29,000,000	[1]	$ 28,000,000	[2]
Significant Assumptions Used to Measure Costs [Abstract]
Target pension asset allocations (as a percent)		1.00%		1.00%
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan assets at net asset value		$ 464,000,000	[2]	$ 317,000,000	[1]
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1		1,032,000,000
Service cost		19,000,000		29,000,000		32,000,000
Interest cost		58,000,000		41,000,000		39,000,000
Medicare subsidy reimbursements		0		0
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant		0		0
Actuarial (gain) loss		45,000,000		(317,000,000)
Benefit payments		(83,000,000)		(84,000,000)
Obligation at Dec. 31		1,071,000,000		1,032,000,000
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		1,031,000,000	[1]	1,351,000,000
Actual return (loss) on plan assets		89,000,000		(276,000,000)
Plan participants' contributions		0		0
Employer contributions		0		40,000,000
Benefit payments		(83,000,000)		(84,000,000)
Fair value of plan assets at Dec. 31		1,037,000,000	[2]	1,031,000,000	[1]	1,351,000,000
Funded Status of Plans at Dec. 31 [Abstract]
Funded status		(34,000,000)		(1,000,000)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss		355,000,000		325,000,000
Prior service (credit) cost		1,000,000		1,000,000
Total		354,000,000		324,000,000
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates [Abstract]
Noncurrent regulatory assets		351,000,000		320,000,000
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		19,000,000		29,000,000		32,000,000
Interest cost		58,000,000		41,000,000		39,000,000
Expected return on plan assets		(76,000,000)		(78,000,000)		(73,000,000)
Amortization of prior service (credit) cost		0		0		0
Amortization of net loss		1,000,000		23,000,000		32,000,000
Net periodic pension cost		$ 2,000,000		$ 18,000,000		$ 30,000,000
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)		5.80%		3.08%		2.71%
Expected average long-term rate of return on assets (as a percent)		6.53%		6.39%		6.38%
Liability, Defined Benefit Plan, Noncurrent		$ 34,000,000		$ 9,000,000
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position		$ (34,000,000)		$ (1,000,000)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		5.49%		5.80%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase		4.25%		4.25%
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Current Regulatory Assets		$ 3,000,000		$ 3,000,000
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Net-Of-Tax Accumulated Other Comprehensive Income				1,000,000
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	[3]	0		3,000,000		$ 0
Defined Benefit Plan, Costs Not Recognized Due To Regulation		9,000,000		4,000,000		0
Net benefit cost recognized for financial reporting		$ 11,000,000		$ 22,000,000		$ 30,000,000
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		4.25%		3.75%		3.75%
Target pension asset allocations (as a percent)		100.00%		100.00%
Defined Benefit Plan, Expected Future Benefit Payment, Next Twelve Months		$ 89,000,000
Defined Benefit Plan, Expected Future Benefit Payment, Year Two		80,000,000
Defined Benefit Plan, Expected Future Benefit Payment, Year Three		80,000,000
Defined Benefit Plan, Expected Future Benefit Payment, Year Four		80,000,000
Defined Benefit Plan, Expected Future Benefit Payment, Year Five		79,000,000
Defined Benefit Plan, Expected Future Benefit Payment, Five Fiscal Years Thereafter		384,000,000
Pension Plan [Member] | Domestic and international equity securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets at net asset value		0	[2]	$ 0	[1]
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	[1]	17,000,000
Fair value of plan assets at Dec. 31		$ 12,000,000	[2]	$ 17,000,000	[1]
Significant Assumptions Used to Measure Costs [Abstract]
Target pension asset allocations (as a percent)		31.00%		33.00%
Pension Plan [Member] | Long-Duration Fixed Income and Interest Rate Swap Securities [Member]
Significant Assumptions Used to Measure Costs [Abstract]
Target pension asset allocations (as a percent)		38.00%		38.00%
Pension Plan [Member] | Short-to-intermediate fixed income securities
Significant Assumptions Used to Measure Costs [Abstract]
Target pension asset allocations (as a percent)		9.00%		9.00%
Pension Plan [Member] | Alternative investments
Significant Assumptions Used to Measure Costs [Abstract]
Target pension asset allocations (as a percent)		20.00%		18.00%
Pension Plan [Member] | Cash
Defined Benefit Plan Disclosure [Line Items]
Plan assets at net asset value		$ 0	[2]	$ 0	[1]
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	[1]	52,000,000
Fair value of plan assets at Dec. 31		$ 94,000,000	[2]	$ 52,000,000	[1]
Significant Assumptions Used to Measure Costs [Abstract]
Target pension asset allocations (as a percent)		2.00%		2.00%

[1] See Note 8 for further information on fair value measurement inputs and methods.

[2] See Note 8 for further information on fair value measurement inputs and methods.

[3] A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2022, as a result of lump-sum distributions during the plan year, PSCo recorded a total pension settlement charge of $3 million. An immaterial amount was recorded in the income statement in 2022. There were no settlement charges recorded to the qualified pension plans in 2023 or 2021

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Benefit Plans and Other Postretirement Benefits, Projected Benefit Payments (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2024	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Defined Contribution Plan, Administrative Expense			$ 13	$ 13
Other Postretirement Benefits Plan [Member]
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2022			31
2023			30
2024			29
2025			28
2026			27
2027-2031			123
Expected Medicare Part D Subsidies [Abstract]
2022			2
2023			2
2024			2
2025			2
2026			2
2027-2031			12
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
2020			29
2021			28
2022			27
2023			26
2024			25
2025-2029			111
Pension Plan [Member]
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2022			89
2023			80
2024			80
2025			80
2026			79
2027-2031			384
Pension Plan [Member] | Xcel Energy [Member]
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Total contributions to Xcel Energy's pension plans during the period			50	50	$ 131
Pension Plan [Member] | Xcel Energy [Member] | Subsequent Event
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Total contributions to Xcel Energy's pension plans during the period	$ 100
Pension Plan [Member] | PSCo [Member]
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Total contributions to Xcel Energy's pension plans during the period			0	40	46
Defined Benefit Plan, Overfunded Plan [Member] | Xcel Energy [Member]
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Total contributions to Xcel Energy's pension plans during the period		$ 11	11	13	15
Defined Benefit Plan, Overfunded Plan [Member] | PSCo [Member]
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Total contributions to Xcel Energy's pension plans during the period		$ 2	$ 3	$ 3	$ 3

XML

Benefit Plans and Other Postretirement Benefits Plan Amendments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Administrative Expense	$ 13	$ 13
plan amendments		$ 0	$ 0

XML

Commitments and Contingencies MGP Sites (Details) - Other MGP, Landfill, or Disposal Sites [Domain]	Dec. 31, 2023 USD ($) Site
Loss Contingencies [Line Items]
Number of identified MGP, landfill, or disposal sites under current investigation and/or remediation | Site	2
Cost of identified MGP, landfill, or disposal sites under current investigation and/or remediation | $	$ 6,000,000

XML

Commitments and Contingencies Environmental Requirements - Water and Waste (Details) $ in Millions	Dec. 31, 2023 USD ($) site sites
Loss Contingencies [Line Items]
Number of sites under investigation as part of federal CCR program | site	4
Accrued liability of sites under investigation as part of federal CCR program	$ 40
Number of sites that will excavate and process ash for beneficial use | sites	2
WYCO, Inc. [Member]
Loss Contingencies [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Federal Coal Ash Regulation [Domain] | Maximum | PSCo [Member]
Loss Contingencies [Line Items]
Cost of Beneficial Use Coal Ash Project	$ 45

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Commitments and Contingencies, Asset Retirement Obligations (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023		Dec. 31, 2022
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		$ 476		$ 422
Amounts Incurred	[1]			34
Accretion		21		19
Cash Flow Revisions		(114)	[2]	1	[3]
Ending balance		383		476
Electric Plant Steam and Other Production Ash Containment
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		180		152
Amounts Incurred	[1]			34
Accretion		8		6
Cash Flow Revisions		0	[2]	(12)	[3]
Ending balance		188		180
Electric Plant Wind Production
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		44		42
Amounts Incurred	[1]			0
Accretion		2		2
Cash Flow Revisions		0	[2]	0	[3]
Ending balance		46		44
Electric Plant Electric Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		17		16
Amounts Incurred	[1]			0
Accretion		0		1
Cash Flow Revisions		0	[2]	0	[3]
Ending balance		17		17
Natural Gas Plant Gas Transmission and Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		235		212
Amounts Incurred	[1]			0
Accretion		11		10
Cash Flow Revisions		(114)	[2]	13	[3]
Ending balance		$ 132		$ 235

[1] Amounts incurred related to steam production pond remediation costs.

[2] In 2023, AROs were revised for changes in timing and estimates of cash flows. Changes in gas transmission and distribution AROs were primarily the result of changes to inflation and discount rate assumptions as well as updated mileage of gas lines and number of services.

[3] In 2022, AROs were revised for changes in timing and estimates of cash flows. Revisions in steam, hydro, and other production AROs 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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Indeterminate AROs (Details) $ in Millions	Dec. 31, 2023 USD ($)
Commitments and Contingencies Disclosure [Abstract]
Indeterminate Costs Incurred, Asset Retirement Obligation Due to Asbestos	$ 0

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Commitments and Contingencies, Leases (Details) - USD ($)		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Lessee, Lease, Description [Line Items]
Maximum Length - Short-Term Leases		12 months
Operating Lease, Weighted Average Discount Rate, Percent		4.20%
Operating Lease, Assets and Liabilities, Lessee [Abstract]
Operating Lease, Right-of-Use Asset, Gross		$ 735,000,000	$ 692,000,000
Operating Lease, Right-of-Use Asset, Accumulated Depreciation		(369,000,000)	(255,000,000)
Operating lease right-of-use assets		366,000,000	437,000,000
Finance Lease, Assets and Liabilities, Lessee [Abstract]
Finance Lease, Right-of-Use Asset, Gross		181,000,000	181,000,000
Finance Lease, Right-of-Use Asset, Accumulated Depreciation		$ (67,000,000)	$ (64,000,000)
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]		Assets	Assets
Finance Lease, Right-of-Use Asset		$ 114,000,000	$ 117,000,000
Lease, Cost [Abstract]
Operating Lease, Cost	[1]	108,000,000	111,000,000	$ 118,000,000
Finance Lease, Right-of-Use Asset, Amortization		3,000,000	4,000,000	7,000,000
Finance Lease, Interest Expense		15,000,000	16,000,000	17,000,000
Finance Lease, Cost		18,000,000	20,000,000	24,000,000
Lessee, Operating Lease, Liability, Payment, Due [Abstract]
Lessee, Operating Lease, Liability, to be Paid, Year One		117,000,000
Lessee, Operating Lease, Liability, to be Paid, Year Two		109,000,000
Lessee, Operating Lease, Liability, to be Paid, Year Three		82,000,000
Lessee, Operating Lease, Liability, to be Paid, Year Four		52,000,000
2028		28,000,000
Thereafter		45,000,000
Total minimum obligation		433,000,000
Interest component of obligation		(41,000,000)
Operating lease liabilities		392,000,000
Less current portion		(102,000,000)	(80,000,000)
Operating lease liabilities		290,000,000	$ 379,000,000
Weighted Average Remaining lease term, operating		4.6
Weighted Average Remaining lease term, finance		36.8
Lessee, Finance Lease, Description [Abstract]
2024		18,000,000
2025		18,000,000
2026		18,000,000
2027		16,000,000
2028		15,000,000
Thereafter		333,000,000
Total minimum obligation		418,000,000
Interest component of obligation		(304,000,000)
Present value of minimum obligation		114,000,000
Less current portion		(3,000,000)
Noncurrent operating and finance lease liabilities		$ 111,000,000
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]		Other Liabilities, Noncurrent	Other Liabilities, Noncurrent
Finance Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]		Other Liabilities, Current	Other Liabilities, Current
WYCO, Inc. [Member]
Lessee, Finance Lease, Description [Abstract]
Equity Method Investment, Ownership Percentage		50.00%
Property, Plant and Equipment, Other Types [Member]
Operating Lease, Assets and Liabilities, Lessee [Abstract]
Operating Lease, Right-of-Use Asset, Gross		$ 112,000,000	$ 80,000,000
Lease, Cost [Abstract]
Operating Lease, Cost	[2]	19,000,000	20,000,000	16,000,000
Lessee, Operating Lease, Liability, Payment, Due [Abstract]
Lessee, Operating Lease, Liability, to be Paid, Year One		19,000,000
Lessee, Operating Lease, Liability, to be Paid, Year Two		12,000,000
Lessee, Operating Lease, Liability, to be Paid, Year Three		8,000,000
Lessee, Operating Lease, Liability, to be Paid, Year Four		8,000,000
2028		8,000,000
Thereafter		6,000,000
Total minimum obligation		61,000,000
Interest component of obligation		(6,000,000)
Operating lease liabilities		55,000,000
Gas Storage Facilities [Member]
Finance Lease, Assets and Liabilities, Lessee [Abstract]
Finance Lease, Right-of-Use Asset, Gross		160,000,000	160,000,000
Gas Pipeline
Finance Lease, Assets and Liabilities, Lessee [Abstract]
Finance Lease, Right-of-Use Asset, Gross		21,000,000	21,000,000
Purchased Power Agreements
Operating Lease, Assets and Liabilities, Lessee [Abstract]
Operating Lease, Right-of-Use Asset, Gross		623,000,000	612,000,000
Lease, Cost [Abstract]
Operating Lease, Cost		89,000,000	$ 91,000,000	$ 102,000,000
Lessee, Operating Lease, Liability, Payment, Due [Abstract]
Lessee, Operating Lease, Liability, to be Paid, Year One	[3],[4]	98,000,000
Lessee, Operating Lease, Liability, to be Paid, Year Two	[3],[4]	97,000,000
Lessee, Operating Lease, Liability, to be Paid, Year Three	[3],[4]	74,000,000
Lessee, Operating Lease, Liability, to be Paid, Year Four	[3],[4]	44,000,000
2028	[3],[4]	20,000,000
Thereafter	[3],[4]	39,000,000
Total minimum obligation	[3],[4]	372,000,000
Interest component of obligation	[3],[4]	(35,000,000)
Operating lease liabilities	[3],[4]	$ 337,000,000

[1] 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.

[2] Includes immaterial short-term lease expense of for 2023, 2022 and 2021.

[3] Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs.

[4] PPA operating leases contractually expire at various dates through 2032.

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Commitments and Contingencies, Purchased Power Agreements (Details) - Capacity - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Purchased Power Agreements (PPAs) [Abstract]
Payments for capacity	$ 3	$ 3	$ 2
Estimated Future Payments Under PPAs [Abstract]
Unrecorded Unconditional Purchase Obligation, to be Paid, Year One	3
Unrecorded Unconditional Purchase Obligation, to be Paid, Year Two	3
Unrecorded Unconditional Purchase Obligation, to be Paid, Year Three	3
Unrecorded Unconditional Purchase Obligation, to be Paid, Year Four	1
2028	0
Thereafter	0
Total	$ 10

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Commitments and Contingencies, Fuel Contracts (Details) $ in Millions	Dec. 31, 2023 USD ($)
Coal
Unrecorded Unconditional Purchase Obligation, to be Paid, Year One	$ 143
Unrecorded Unconditional Purchase Obligation, to be Paid, Year Two	74
Unrecorded Unconditional Purchase Obligation, to be Paid, Year Three	39
Unrecorded Unconditional Purchase Obligation, to be Paid, Year Four	35
2028	0
Thereafter	0
Total	291
Natural Gas Supply
Unrecorded Unconditional Purchase Obligation, to be Paid, Year One	221
Unrecorded Unconditional Purchase Obligation, to be Paid, Year Two	12
Unrecorded Unconditional Purchase Obligation, to be Paid, Year Three	0
Unrecorded Unconditional Purchase Obligation, to be Paid, Year Four	0
2028	0
Thereafter	0
Total	233
Natural Gas Storage and Transportation
Unrecorded Unconditional Purchase Obligation, to be Paid, Year One	108
Unrecorded Unconditional Purchase Obligation, to be Paid, Year Two	105
Unrecorded Unconditional Purchase Obligation, to be Paid, Year Three	105
Unrecorded Unconditional Purchase Obligation, to be Paid, Year Four	105
2028	62
Thereafter	382
Total	$ 867

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Commitments and Contingencies Comanche Unit 3 Litigation $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($)
Commitments and Contingencies Disclosure [Abstract]
CORE outcome excluding interest	$ 26
CORE outcome total	$ 34

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Commitments and Contingencies, Variable Interest Entities (Details) - MW	Dec. 31, 2023	Dec. 31, 2022
Equity Method Investment, Nonconsolidated Investee or Group of Investees [Member]
Purchased Power Agreements (PPAs) [Abstract]
Generating capacity (in MW)	1,207	1,442

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Commitments and Contingencies Marshall Wild Fire (Details) $ in Millions	Dec. 31, 2023 USD ($) complaint numberOfPlaintiffs
Commitments and Contingencies Disclosure [Abstract]
Estimated property losses caused by Marshall Wildfire	$ 2,000.0
Number of complaints related to the Marshall Wildfire | complaint	302
Number of plaintiffs related to the Marshall Wildfire | numberOfPlaintiffs	4,047
Cap of noneconomic loss in a civil action other than a medical malpractice under Colorado law	$ 0.6
Amount of insurance coverage	$ 500.0

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Other Comprehensive Income (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023		Dec. 31, 2022		Dec. 31, 2021
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period		$ 9,230
Total income tax expense		29		$ 37		$ 33
Accumulated other comprehensive loss at end of period		9,742		9,230
Gains and Losses on Cash Flow Hedges
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period		(20)		(21)
Amortization of net actuarial income (loss)		0
Net current period other comprehensive income (loss)		1		1
Accumulated other comprehensive loss at end of period		(19)		(20)		(21)
Other Comprehensive Income (Loss) before reclassifications		0		0
Gains and Losses on Cash Flow Hedges | Interest Rate Swap
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amortization of net actuarial income (loss)		(1)	[1]	(1)	[2]
Defined Benefit Pension and Postretirement Items
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period		(2)		(1)
Amortization of net actuarial income (loss)	[3]	(1)
Net current period other comprehensive income (loss)		1		(1)
Accumulated other comprehensive loss at end of period		(1)		(2)		(1)
Other Comprehensive Income (Loss) before reclassifications		0		(1)
Defined Benefit Pension and Postretirement Items | Interest Rate Swap
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amortization of net actuarial income (loss)		0		0
Total
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period		(22)		(22)
Amortization of net actuarial income (loss)		(1)
Net current period other comprehensive income (loss)		2		0
Accumulated other comprehensive loss at end of period		(20)		(22)		$ (22)
Other Comprehensive Income (Loss) before reclassifications		0		(1)
Total | Interest Rate Swap
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amortization of net actuarial income (loss)		$ (1)		$ (1)

[1] Included in interest charges.

[2] Included in interest charges

[3] Included in the computation of net periodic pension and postretirement benefit costs. See Note 9 for further information.

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Segments and Related Information (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information [Line Items]
Operating revenue, Regulated Natural Gas		$ 1,734	$ 1,860	$ 1,355
Unregulated Operating Revenue		54	53	47
Regulated and Unregulated Operating Revenue		5,519	5,708	4,815
Depreciation and amortization		924	848	744
Interest charges and financing costs		292	260	234
Total income tax expense		29	37	33
Net income (loss)		695	727	660
Intercompany Revenue		5	5	5
Regulated Electric
Segment Reporting Information [Line Items]
Revenues Including Intersegment Revenues		3,732	3,796	3,414
Depreciation and amortization		692	650	566
Interest charges and financing costs		224	200	179
Total income tax expense		(2)	(11)	(16)
Net income (loss)		529	550	495
Regulated Natural Gas
Segment Reporting Information [Line Items]
Revenues Including Intersegment Revenues		1,734	1,860	1,355
Depreciation and amortization		224	190	171
Interest charges and financing costs		67	59	53
Total income tax expense		37	49	45
Net income (loss)		149	180	168
All Other
Segment Reporting Information [Line Items]
Depreciation and amortization		8	8	7
Interest charges and financing costs		1	1	2
Total income tax expense		(6)	(1)	4
Net income (loss)		17	(3)	(3)
Total revenues
Segment Reporting Information [Line Items]
Regulated and Unregulated Operating Revenue	[1]	5,520	5,709	4,816
Total revenues | Regulated Electric
Segment Reporting Information [Line Items]
Electric		3,731	3,795	3,413
Total revenues | All Other
Segment Reporting Information [Line Items]
Unregulated Operating Revenue	[1]	54	53	47
Intersegment Eliminations
Segment Reporting Information [Line Items]
Regulated and Unregulated Operating Revenue		(1)	(1)	(1)
Intersegment Eliminations | Regulated Electric
Segment Reporting Information [Line Items]
Electric		$ 1	$ 1	$ 1

[1] Operating revenues include $5 million of other affiliate revenue for the years ended Dec. 31, 2023, 2022 and 2021, respectively. See Note 13 for further information.

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Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
NSP-Minnesota
Operating expenses
Other Receivables	$ 0	$ 2
Accounts Payable, Other	5	0
NSP-Wisconsin
Operating expenses
Other Receivables	0	0
Accounts Payable, Other	1	2
SPS
Operating expenses
Other Receivables	0	0
Accounts Payable, Other	11	11
Other subsidiaries of Xcel Energy Inc.
Operating expenses
Other Receivables	28	9
Accounts Payable, Other	66	62
Xcel Energy [Member]
Operating expenses
Other Receivables	28	11
Accounts Payable, Other	83	75
Other Expense
Operating expenses
Costs and Expenses, Related Party	679	670	$ 617
Interest Expense
Operating expenses
Costs and Expenses, Related Party	5	2	0
Other Revenue | Xcel Energy [Member]
Operating expenses
Total revenues	5	5	5
Electricity, US Regulated | Xcel Energy [Member]
Operating expenses
Interest and Other Income	$ 2	$ 0	$ 0

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Compensation Related Costs, Postemployment Benefits (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) Employees
Xcel Energy [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Other Postretirement Benefits Cost (Reversal of Cost) | $	$ 72
PSCo [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Other Postretirement Benefits Cost (Reversal of Cost) | $	$ 20
Voluntary Retirement Program | Xcel Energy [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Entity Number of Employees | Employees	400
Employee Severance | Xcel Energy [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Entity Number of Employees | Employees	150

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Schedule II, Valuation and Qualifying Accounts (Details) - Allowance for Bad Debts - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Jan. 1		$ 54	$ 40	$ 29
Charged to costs and expenses		34	38	26
Charged to other accounts	[1]	5	18	4
Deductions from reserves	[2]	(37)	(42)	(19)
Balance at Dec. 31		$ 56	$ 54	$ 40

[1] Recovery of amounts previously written-off.

[2] Deductions related primarily to bad debt write-offs