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, 2020 or

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

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)			(I.R.S. 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	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. ☐

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. 17, 2021, 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 2021 Annual Meeting of Shareholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 6, 2021. 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 reduced disclosure format permitted by General Instruction I(2).

1

TABLE OF CONTENTS

PART I
Item 1 —	Business	3
	Definition of Abbreviations	3
	Forward-Looking Statements	3
	Where to Find More Information	4
	Overview	4
	Electric Operations	4
	Natural Gas Operations	7
	General	7
	Environmental	8
	Employees	8
Item 1A —	Risk Factors	8
Item 1B —	Unresolved Staff Comments	14
Item 2 —	Properties	14
Item 3 —	Legal Proceedings	15
Item 4 —	Mine Safety Disclosures	15
PART II
Item 5 —	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	15
Item 6 —	Selected Financial Data	15
Item 7 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	15
Item 7A —	Quantitative and Qualitative Disclosures About Market Risk	18
Item 8 —	Financial Statements and Supplementary Data	20
Item 9 —	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	47
Item 9A —	Controls and Procedures	47
Item 9B —	Other Information	48
PART III
Item 10 —	Directors, Executive Officers and Corporate Governance	48
Item 11 —	Executive Compensation	48
Item 12 —	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	48
Item 13 —	Certain Relationships and Related Transactions, and Director Independence	48
Item 14 —	Principal Accountant Fees and Services	48
PART IV
Item 15 —	Exhibit and Financial Statement Schedules	48
Item 16 —	Form 10-K Summary	50
Signatures		51

This Form 10-K is filed by Public Service Company of Colorado (PSCo). PSCo is a wholly owned subsidiary of Xcel Energy Inc. Additional information on Xcel Energy is available in various filings with the Securities and Exchange Commission. This report should be read in its entirety.

2

PART I

ITEM 1 — BUSINESS

Definitions of Abbreviations

Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
e prime	e prime inc.
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 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
CEPA	Colorado Energy Plan Adjustment
DSM	Demand side management
DSMCA	DSM cost adjustment
ECA	Retail electric commodity adjustment
FCA	Fuel clause adjustment
GCA	Gas cost adjustment
PCCA	Purchased capacity cost adjustment
PSIA	Pipeline system integrity adjustment
RES	Renewable energy standard
RESA	RES adjustment
SCA	Steam cost adjustment
TCA	Transmission cost adjustment
WCA	Wind cost adjustment

Other
ADIT	Accumulated deferred income taxes
AFUDC	Allowance for funds used during construction
ARO	Asset retirement obligation
ASC	FASB Accounting Standards Codification
ASU	FASB Accounting Standards Update
Boulder	City of Boulder, CO
C&I	Commercial and Industrial
CACJA	Clean Air Clean Jobs Act
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
COVID-19	Novel coronavirus
CWA	Clean Water Act
CWIP	Construction work in progress
ELG	Effluent limitations guidelines
ETR	Effective tax rate
FASB	Financial Accounting Standards Board
GAAP	Generally accepted accounting principles
GHG	Greenhouse gas
IPP	Independent power producing entity
ITC	Investment tax credit
MDL	Multi-district litigation
MGP	Manufactured gas plant
Moody’s	Moody’s Investor Services
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
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
SERP	Supplemental executive retirement plan
SPP	Southwest Power Pool, Inc.
S&P	Standard & Poor’s Global Ratings
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
WOTUS	Waters of the U.S.

Measurements
Bcf	Billion cubic feet
KV	Kilovolts
KWh	Kilowatt hours
MMBtu	Million British thermal units
MW	Megawatts
MWh	Megawatt hours

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 future sales, future bad debt expense, future operating performance, estimated base capital expenditures and financing plans, projected capital additions and forecasted annual revenue requirements with respect to rider filings and expectations regarding regulatory proceedings, 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.

3

The following factors, in addition to those discussed elsewhere in this Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2020 (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 hereto), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: uncertainty around the impacts and duration of the COVID-19 pandemic; operational safety; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices and fuel costs; qualified employee work force and third-party contractor factors; ability to recover costs; changes in regulation; reductions in our credit ratings and the cost of maintaining certain contractual relationships; general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of PSCo and its subsidiaries to obtain financing on favorable terms; availability or cost of capital; our customers’ and counterparties’ ability to pay their debts to us; assumptions and costs relating to funding our employee benefit plans and health care benefits; tax laws; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; seasonal weather patterns; changes in environmental laws and regulations; climate change and other weather; natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; and costs of potential regulatory penalties.

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.

Overview

Electric customers	1.5 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	1.4 million
Total assets	$20.4 billion
Rate Base (estimated)	$13.3 billion
ROE (net income / average stockholder's equity)	8.06%
Electric generating capacity	6,223 MW
Gas storage capacity	32.5 Bcf
Electric transmission lines (conductor miles)	24,386 miles
Electric distribution lines (conductor miles)	78,483 miles
Natural gas transmission lines	2,058 miles
Natural gas distribution lines	22,815 miles

Electric Operations

Electric operations consist of energy supply, generation, transmission and distribution activities. PSCo had electric sales volume of 33,301 (millions of KWh), 1.5 million customers and electric revenues of $3,116 (millions of dollars) for 2020.

4

Sales/Revenue Statistics (a)

	2020			2019
KWH sales per retail customer	18,919			19,335
Revenue per retail customer	$	1,839		$	1,812
Residential revenue per KWh	11.46		¢	11.09		¢
Large C&I revenue per KWh	6.51		¢	6.43		¢
Small C&I revenue per KWh	9.71		¢	9.38		¢
Total retail revenue per KWh	9.72		¢	9.37		¢

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

Owned and Purchased Energy Generation — 2020

Electric Energy Sources

Total electric generation by source (including energy market purchases) for the year ended Dec. 31, 2020:

*Distributed generation from the Solar*Rewards® program is not included (approximately 618 million KWh for 2020).

Carbon–Free Energy

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, weather, system demand and transmission constraints.

See Item 2 — Properties for further information.

Carbon–free energy as a percentage of total energy for 2020:

* Includes biomass and hydroelectric.

Wind

Owned — Owned and operated wind farms with corresponding capacity:

2020		2019
Wind Farms	Capacity (a)	Wind Farms	Capacity (b)
2	1,059 MW	1	582 MW

(a)Summer 2020 net dependable capacity.

(b)Summer 2019 net dependable capacity.

PPAs — Number of PPAs with capacity range:

2020		2019
PPAs	Range	PPAs	Range
17	23 MW — 301 MW	20	2 MW — 301 MW

Capacity — Wind capacity:

2020	2019
4,085 MW	3,145 MW

Average Cost (Owned) — Average cost per MWh of wind energy from owned generation:

2020	2019
$35	$47

Average Cost (PPAs) — Average cost per MWh of wind energy under existing PPAs:

2020	2019
$40	$41

Wind Development

PSCo placed approximately 500 MW of owned wind and approximately 500 MW of PPAs into service during 2020:

Project	Capacity
Cheyenne Ridge	477 MW (a)(b)
Various PPAs	~500 MW (c)

(a)Summer 2020 net dependable capacity.

(b)Values disclosed are the maximum generation levels for these wind units. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero).

(c)Based on contracted capacity.

Solar

Solar energy PPAs:

Type	Capacity
Distributed Generation	643 MW
Utility-Scale	306 MW
Total	949 MW

Average Cost (PPAs) — Average cost per MWh of solar energy under existing PPAs:

2020	2019
$89	$89

Other Carbon-Free Energy

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

See Item 2 — Properties for further information.

5

Fossil Fuel Energy

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 2,000 MW of total 2020 net summer dependable capacity.

The following are PSCo’s approved coal plant retirements. In addition, PSCo plans to continue to evaluate its coal fleet for other potential early coal plant retirements as part of state resource plans or other regulatory proceedings.

Approved / Authorized
Year	Plant Unit	Capacity
2022	Comanche 1	325 MW
2025	Comanche 2	335 MW
2025	Craig 1	42 MW (a)
2028	Craig 2	40 MW (a)

(a)Based on PSCo’s ownership interest.

Proposed
Year	Plant Unit	Capacity
2027	Hayden 2	98 MW (a)
2028	Hayden 1	135 MW (b)

(a)Based on PSCo’s ownership of 37% of Unit 2.

(b)Based on PSCo’s ownership of 76% of Unit 1.

Coal Fuel Cost

Delivered cost per MMBtu of coal consumed for owned electric generation and the percentage of total fuel requirements:

	Coal
	Cost		Percent
2020	$	1.41	51	%
2019	1.45		55

Plans for our remaining Colorado coal fleet will be outlined when PSCo submits its 2021 resource plan, which is expected to be filed in March 2021.

Natural Gas

PSCo has six natural gas plants with approximately 2,900 MW of total 2020 net summer dependable capacity.

See item 2 - Properties for further detail.

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:

	Natural Gas
	Cost	Percent
2020	3.01	49
2019	3.27	45

Capacity and Demand

Uninterrupted system peak demand and occurrence date:

System Peak Demand (in MW)
2020		2019
6,899	Aug. 17	7,111	July 19

Transmission

Transmission lines deliver electricity over long distances from power sources to transmission substations closer to homes and businesses. 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.

During 2020, PSCo completed the following transmission projects:

Project	Miles	Size
Pawnee-Daniels Park	113	345 KV
Cheyenne Ridge	73	345 KV

Distribution

Distribution lines allow electricity to travel at lower voltages from substations directly to homes and businesses. PSCo has a vast distribution network, owning and operating approximately 79,000 conductor miles of distribution lines across our service territory, both above ground and underground. To continue providing reliable, affordable electric service and enable more flexibility for customers, we are working to digitize the distribution grid, while at the same time keeping it secure.

See Item 2 - Properties for further information.

6

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 324,533 (thousands of MMBtu), 1.4 million customers and natural gas revenues of $1,024 (millions of dollars) for 2020.

Sales/Revenue Statistics (a)

	2020		2019
MMBtu sales per retail customer	101.10		109.80
Revenue per retail customer	$	632.11	$	748.34
Residential revenue per MMBtu	6.47		7.02
C&I revenue per MMBtu	5.70		6.33
Transportation and other revenue per MMBtu	0.65		0.56

(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:

2020		2019
MMBtu	Date	MMBtu	Date
1,931,888	Feb. 4	2,139,420	March 3

Natural Gas Supply and Costs

PSCo seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio, which increase flexibility, decreases interruption and 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:

2020		2019
$	2.52	$	2.95

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 milder in the winter and cooler in the summer.

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.

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

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 their output from generation resources of competing suppliers or non-contracted quantities and use the transmission system of PSCo on a comparable basis to serve their native load.

FERC Order No. 1000 established competition for construction and operation of certain new electric transmission facilities. State utility commissions have also created resource planning programs that promote competition for electric generation resources used to provide service to retail customers.

7

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.

While facing these challenges, PSCo believes its rates and services are competitive with alternatives currently available.

Public Utility Regulation

See Item 7 for discussion of public utility regulation.

Environmental

Environmental Regulation

Our facilities are regulated by federal and state agencies that have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous 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 operate in compliance with applicable environmental standards and related monitoring and reporting requirements. However, it is not possible to determine when or to what extent additional facilities or modifications of 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 MGP and other sites if it is determined that prior compliance efforts are not sufficient.

The Denver North Front Range Non-attainment Area does not meet either the 2008 or 2015 ozone National Ambient Air Quality Standard. Colorado will continue to consider further reductions available in the non-attainment area as it develops plans to meet ozone standards. Gas plants which operate in PSCo’s non-attainment area may be required to improve or add controls, implement further work practices and/or enhanced emissions monitoring as part of future Colorado state plans.

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.

In July 2019, the EPA adopted the Affordable Clean Energy rule, which required states to develop plans by 2022 for GHG reductions from coal-fired power plants. In a Jan. 19, 2021 decision, the U.S. Court of Appeals for the D.C. Circuit issued a decision vacating and remanding the Affordable Clean Energy rule. That decision, if not successfully appealed or reconsidered, would allow the EPA to proceed with alternate regulation of coal-fired power plants, either reviving the Clean Power Plan or proposing additional regulation. It is too early to predict an outcome, but new rules could require substantial additional investment, even in plants slated for retirement. PSCo believes, based on prior state commission practices, the cost of these initiatives or replacement generation would be recoverable through rates.

PSCo seeks to address climate change and potential climate change regulation through efforts to reduce its GHG emissions in a balanced, cost-effective manner.

Employees

As of Dec. 31, 2020, PSCo had 2,378 full-time employees and no part-time employees, of which 1,882 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. 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.

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’ committees have responsibility for overseeing the identification and mitigation of key risks.

At a threshold level, 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 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 ensure appropriate risk oversight, as well as identification and consideration of new risks.

8

Risks Associated with Our Business

Operational Risks

Our natural gas and electric 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.

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.

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 necessary supplies.

•The impact of unusual or adverse weather conditions and natural disasters, including, but not limited to, tornadoes, icing events, floods and droughts.

•Performance below expected or contracted levels of output or efficiency (e.g., performance guarantees).

•Availability of replacement equipment.

•Availability of adequate water resources and ability to satisfy water intake and discharge requirements.

•Inability to identify, manage properly or mitigate equipment defects.

•Use of new or unproven technology.

•Risks associated with dependence on a specific type of fuel or fuel source, such as commodity price risk, availability of adequate fuel supply and transportation and lack of available alternative fuel sources.

•Increased competition due to, among other factors, new facilities, excess supply, shifting demand and regulatory changes.

Additionally, compliance with existing and potential new regulations related to the operation and maintenance of our natural gas infrastructure could result in significant costs. The PHMSA is responsible for administering the DOT’s national regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipelines. The PHMSA continues to develop regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance and emergency response of natural gas pipeline infrastructure. We have programs in place to comply with these regulations and systematically monitor and renew infrastructure over time; however, a significant incident or material finding of non-compliance could result in penalties and higher costs of operations.

Our natural gas and electric transmission and distribution operations are dependent upon complex information technology systems and network infrastructure, the failure of which could disrupt our normal business operations, which could have a material adverse effect on our ability to process transactions and provide services.

Our utility operations are subject to long-term planning and project risks.

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

In addition, the long-term nature of both our planning and our asset lives are subject to risk. The electric utility sector is undergoing significant change (e.g, increases in energy efficiency, wider adoption of distributed generation and shifts away from fossil fuel generation to renewable generation). Customer adoption of these technologies and increased energy efficiency could result in excess transmission and generation resources, downward pressure on sales growth, and potentially stranded costs if we are not able to fully recover costs and investments.

Changing customer expectations and technologies are requiring significant investments in advanced grid infrastructure, which increases exposure to technology obsolescence. Additionally, evolving stakeholder preference for lower emissions from generation sources and end-uses, like heating, may put pressure on our ability to recover capital investments in natural gas generation and delivery.

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. Additionally, 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 are subject to longer-term availability of inputs such as coal, natural gas, uranium and water to cool our facilities. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate.

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

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

A significant disruption in supply could cause us to seek alternative supply services at potentially higher costs and supply shortages may not be fully resolved, which could cause disruptions in 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 could negatively impact our cash flows and results of operations.

9

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.

Due to the inherent 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, including, without limitation, employee misconduct. If such controls are not effective, PSCo’s results of operations, financial condition or cash flows could be materially impacted.

Failure to attract and retain a qualified workforce could have an adverse effect on operations.

Specialized knowledge is required of our technical employees for construction and operation of transmission, generation and distribution assets. Our business strategy is dependent on our ability to recruit, retain and motivate employees. There is competition and a tightening market for skilled employees. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to new employees or future availability and cost of contract labor may adversely affect the ability to manage and operate our business. Inability to attract and retain these employees could adversely impact our results of operations, financial condition or cash flows.

Our operations use third-party contractors in addition to employees to perform periodic and ongoing work.

We rely on third-party contractors to perform operations, maintenance and construction work. Our contractual arrangements with these contractors typically include performance standards, progress payments, insurance requirements and security for performance.

Poor vendor performance could impact ongoing operations, restoration operations, our reputation and could introduce financial risk or risks of fines.

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. In 2020, 2019 and 2018 we paid $831 million, $457 million and $375 million of dividends to Xcel Energy Inc., respectively. 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 from our customers 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 our capital investment. Our rates are generally regulated and based on an analysis of our costs incurred in a test year. We are subject to both future and historical test years depending upon the regulatory jurisdiction. Thus, the rates we are allowed to charge may or may not match our costs at any given time. Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital.

There can also be no assurance that our regulatory commissions will judge all our costs to be prudent, which could result in disallowances, or that the regulatory process will always result in rates that will produce full recovery. Overall, management believes prudently incurred costs are recoverable given the existing regulatory framework. However, there may be changes in the regulatory environment that could impair our ability to recover costs historically collected from customers, or we could exceed caps on capital costs required by commissions and result in less than full recovery.

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

In a continued low interest rate environment there has been increased downward pressure on allowed ROE. Conversely, 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 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.

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

We cannot be assured that our current credit ratings will remain in effect, or that a rating will not be lowered or withdrawn by a rating agency. Significant events including disallowance of costs, lower returns on equity, changes to equity ratios and impacts of tax policy may impact our cash flows and credit metrics, potentially resulting in a change in our credit ratings. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies.

Any credit ratings downgrade could lead to higher borrowing costs and could 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.

10

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 short-term commercial paper, issuing new securities or cause us to issue securities with unfavorable terms and conditions, such as higher interest rates. 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 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., the California Independent System Operator, SPP, PJM Interconnection, LLC, Midcontinent Independent System Operator, Inc. and the Electric Reliability Council of Texas), in which any credit losses are socialized to all market participants.

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

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

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

As of Dec. 31, 2020, Xcel Energy Inc. and its utility subsidiaries had approximately $19.6 billion of long-term debt and $1.0 billion of short-term debt and current maturities. Xcel Energy Inc. provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries for specified agreements or transactions.

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

As of Dec. 31, 2020, Xcel Energy had guarantees outstanding with a $2 million maximum stated amount and immaterial exposure. Xcel Energy also had additional guarantees of $60 million at Dec. 31, 2020 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 regulated rates. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Tax depreciable lives and the value of various tax credits or the timeliness of their utilization may impact the economics or selection of resources.If tax rates are increased, there could be timing delays before regulated rates provide for recovery of such tax increases in revenues. In addition, certain IRS tax policies such as tax normalization may impact our ability to economically deliver certain types of resources relative to market prices.

Macroeconomic Risks

Economic conditions impact our business.

Our operations are affected by local, national and worldwide economic conditions, which correlates to customers/sales growth (decline). Economic conditions may be impacted by 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.

11

Additionally, 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.

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.

The global outbreak of COVID-19 is impacting countries, communities, supply chains and markets. A high degree of uncertainty continues to exist regarding the pandemic, the duration and magnitude of business restrictions, re-shut downs, if any, and the level and pace of economic recovery. While we are implementing contingency plans, there are no guarantees these plans will be sufficient to offset the impact of COVID-19.

Although the impact of the pandemic to the 2020 results was largely mitigated due to management’s actions, we cannot ultimately predict whether it will have a material impact on our future liquidity, financial condition or results of operations. Nor can we predict the impact of the virus on the health of our employees, our supply chain or our ability to recover higher costs associated with managing through the pandemic. The impact of COVID-19 may exacerbate other risks discussed herein, which could have a material effect on us. The situation is evolving and additional impacts may arise.

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 already 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, severe 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. Xcel Energy participates in a global supply chain, which includes materials and components that are globally sourced. A prolonged disruption could result in the delay of equipment and materials that may impact our ability to reliably serve our customers.

A major disruption could result in a significant decrease in revenues and additional costs to repair assets, which could have a material impact on our results of operations, financial condition or cash flows.

PSCo participates in grid security and emergency response exercises (GridEx). These efforts, led by the NERC, test and further develop the coordination, threat sharing and interaction between utilities and various government agencies relative to potential cyber and physical threats against the nation’s electric grid.

A cyber incident or security breach could have a material effect on our business.

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

Our generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets, as well as information processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cyber security incidents, including those caused by human error. Our industry has been the target of several attacks on operational systems and has seen an increased volume and sophistication of cyber security incidents from international activist organizations, Nation States and individuals.

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

Our generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cyber security incident of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third-party service providers’ operations, could also negatively impact our business.

Our supply chain for procurement of digital equipment and services may expose software or hardware to these risks and could result in a breach or significant costs of remediation. We are unable to quantify the potential impact of cyber security threats or subsequent related actions. Cyber security incidents and regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third-party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.

We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cyber security incidents, including asset failure or unauthorized access to assets or information. A failure or breach of our technology systems or those of our third-party service providers could disrupt critical business functions and may negatively impact our business, our brand, and our reputation. The cyber security threat is dynamic and evolves continually, and our efforts to prioritize network protection may not be effective given the constant changes to threat vulnerability.

12

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

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.

The Biden Administration will establish a new nationally determined contribution for the United States. The Paris Agreement could result in future additional GHG reductions in the United States. In addition, the Biden Administration has announced plans to implement new climate change programs, including potential regulation of GHG emissions targeting the utility industry.

The Biden Administration has also announced a one year suspension of new oil and natural gas drilling on federal lands to allow for a review of oil and gas leasing regulations. The form of these regulations is uncertain, but, depending on the requirements imposed in the short and long term, they could impose substantial costs on our oil and gas customers or result in substantial increases to the cost of fuel we use in our electricity and gas businesses.

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 or 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.

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. The FERC can impose penalties of up to $1.3 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Also, the PHMSA, Occupational Safety and Health Administration and other federal agencies have the authority to assess penalties.

In the event of serious incidents, these agencies may pursue penalties. In addition, certain states have the authority to impose substantial penalties. If a serious reliability, cyber or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows.

Environmental Risks

We are subject to environmental laws and regulations, with which compliance could be difficult and costly.

We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. Laws and regulations require us to obtain permits, licenses, and approvals and to comply with a variety of environmental requirements.

Environmental laws and regulations can also require us to restrict or limit the output of facilities or the use of certain fuels, shift generation to lower-emitting facilities, install pollution control equipment, clean up spills and other contamination and correct environmental hazards. Failure to meet requirements of environmental mandates may result in fines or penalties. We may be required to pay all or a portion of the cost to remediate sites where our past activities, or the activities of other parties, caused environmental contamination.

Changes in environmental policies and regulations or regulatory decisions may result in early retirements of our generation facilities. While regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs.

We are subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. It could have a material effect on our results of operations, financial condition or cash flows if our regulators do not allow us to recover the cost of capital investment or O&M costs incurred to comply with the requirements.

In addition, existing environmental laws or regulations may be revised, and new laws or regulations may be adopted. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.

We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.

Climate change can create physical and financial risk. Physical risks include changes in weather conditions and extreme weather events.

13

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.

Severe weather impacts our service territories, primarily when thunderstorms, flooding, tornadoes, wildfires and snow or ice storms 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. Periods of extreme temperatures could impact our ability to meet demand. Changes in precipitation resulting in droughts or water shortages could adversely affect our operations. Drought conditions also contribute to the increase in wildfire risk from our electric generation facilities.

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. We may not recover all costs related to mitigating these physical and financial risks.

ITEM 1B — UNRESOLVED STAFF COMMENTS

None.

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	Fuel	Installed	MW (a)
Steam:
Comanche-Pueblo, CO (b)
Unit 1	Coal	1973	325
Unit 2	Coal	1975	335
Unit 3	Coal	2010	500	(c)
Craig-Craig, CO, 2 Units (d)	Coal	1979 - 1980	82	(e)
Hayden-Hayden, CO, 2 Units (h)	Coal	1965 - 1976	233	(f)
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	968
Rocky Mountain-Keenesburg, CO, 3 Units	Natural Gas	2004	580
Various locations, 8 Units	Natural Gas	Various	251
Hydro:
Cabin Creek-Georgetown, CO
Pumped Storage, 2 Units	Hydro	1967	210
Various locations, 8 Units	Hydro	Various	25
Wind:
Rush Creek, CO, 300 units	Wind	2018	582	(g)
Cheyenne Ridge, CO, 229 units	Wind	2020	477	(g)
		Total	6,223

(a)    Summer 2020 net dependable capacity.

(b)    In 2018, the CPUC approved early retirement of PSCo’s Comanche Units 1 and 2 in 2022 and 2025, respectively.

(c)    Based on PSCo’s ownership of 67%.

(d)    Craig Unit 1 and 2 are expected to be retired early in 2025 and 2028, respectively.

(e)    Based on PSCo’s ownership of 10%.

(f)    Based on PSCo’s ownership of 76% of Unit 1 and 37% of Unit 2.

(g)    Values disclosed are the generation levels at the point-of-interconnection. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero).

(h)    Hayden Unit 1 and 2 are expected to be retired in 2028 and 2027, respectively.

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2020:

Conductor Miles
Transmission
345 KV	5,389
230 KV	12,131
138 KV	92
115 KV	5,092
Less than 115 KV	1,682
Total Transmission	24,386
Distribution
Less than 115 KV	78,483
Total	102,869

14

PSCo had 236 electric utility transmission and distribution substations at Dec. 31, 2020.

Natural gas utility mains at Dec. 31, 2020:

Miles
Transmission	2,058
Distribution	22,815

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 financial statements. Unless otherwise required by GAAP, legal fees are 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 2020 and 2019 were as follows:

(Millions of Dollars)	2020		2019
First quarter	$	103	$	99
Second quarter	465		105
Third quarter	128		97
Fourth quarter	128		177

ITEM 6 — SELECTED FINANCIAL DATA

Omitted per conditions set forth in general instructions I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

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 electric margin, natural gas margin and ongoing earnings. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are 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.

Electric and Natural Gas Margins

Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Natural gas margin is presented as natural gas revenues less the cost of natural gas sold and transported. Expenses incurred for electric fuel and purchased power and the cost of natural gas are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues.Management believes electric and natural gas margins provide the most meaningful basis for evaluating our operations because they exclude the revenue impact of fluctuations in these expenses.

These margins can be reconciled to operating income, a GAAP measure, by including other operating revenues, cost of sales-other, O&M expenses, conservation and DSM expenses, depreciation and amortization and taxes (other than income taxes).

Earnings Adjusted for Certain Items (Ongoing Earnings)

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

Management uses these non-GAAP financial measures to evaluate and provide details of PSCo’s core earnings and underlying performance. Management believes these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of PSCo. For the years ended Dec. 31, 2020 and 2019, there were no adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings.

15

Results of Operations

2020 Comparison to 2019

PSCo’s net income was $588 million for 2020, compared with $578 million for 2019. The increase reflected higher electric margin (wholesale transmission revenue and regulatory outcomes offset lower sales due to COVID-19), increased AFUDC and higher natural gas margin, offset by additional depreciation and taxes (other than income taxes).

Electric Margin

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 and Margin:

(Millions of Dollars)	2020		2019
Electric revenues	$	3,116	$	3,033
Electric fuel and purchased power	(1,132)		(1,083)
Electric margin	$	1,984	$	1,950

Changes in Electric Margin:

(Millions of Dollars)	2020 vs. 2019
Regulatory rate outcomes	$	73
Non-fuel riders	16
Wholesale transmission revenue (net)	12
Conservation incentive	3
Estimated impact of weather (net of decoupling)	(2)
PTCs flowed back to customers (offset by lower ETR)	(17)
Sales and demand (a)	(49)
Other (net)	(2)
Total increase in electric margin	$	34

(a)Sales excludes weather impact, net of decoupling, and demand revenue is not impacted by decoupling.

Natural Gas Margin

Natural gas expense varies with changing sales and cost of natural gas. However, fluctuations in the cost of natural gas has minimal impact on margin due to cost recovery mechanisms.

Natural Gas Revenues and Margin:

(Millions of Dollars)	2020		2019
Natural gas revenues	$	1,024	$	1,161
Cost of natural gas sold and transported	(374)		(526)
Natural gas margin	$	650	$	635

Changes in Natural Gas Margin:

(Millions of Dollars)	2020 vs. 2019
Regulatory rate outcomes	$	19
Infrastructure and integrity riders	11
Conservation incentive	1
Estimated impact of weather	(11)
Transport sales	(2)
Sales decline	(2)
Other	(1)
Total increase in natural gas margin	$	15

Non-Fuel Operating Expenses and Other Items

Taxes (Other than Income Taxes) — Taxes (other than income taxes) increased $28 million, or 14%, year-to-date, primarily due to higher property taxes.

Depreciation and Amortization — Depreciation and amortization increased $53 million, or 9%, year-to-date, primarily driven by normal system expansion, new depreciation rates implemented in March 2020 and the Cheyenne Ridge wind farm going into service. The increase in depreciation was partially offset by a decrease in amortization of the pension regulatory asset.

AFUDC, Equity and Debt — AFUDC increased by $16 million year-to-date, primarily due to the Cheyenne Ridge wind farm.

Income Taxes — Income tax expense decreased $35 million for 2020, primarily driven by an increase in wind PTCs and an increase in plant-related regulatory differences. Wind PTCs are credited to customers (recorded as a reduction to revenue) and do not have a material impact on net income. The ETR was 7.1% for 2020 compared with 12.2% for 2019, largely due to the adjustments referenced above.

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. Our utility subsidiaries request changes in rates for utility services through filings with governing commissions. Changes in operating costs can affect PSCo’s financial results, depending on the timing of rate case filings 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.

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. Pipeline safety compliance.
FERC	Wholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce. Wholesale electric sales at cost-based prices to customers inside PSCo’s balancing authority area and at market-based prices to customers outside PSCo’s balancing authority area. PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction.
RTO	PSCo is not presently a member of an RTO and does not operate within an RTO energy market. However, PSCo does make certain sales to other RTO’s, including SPP and participates in a joint dispatch agreement with neighboring utilities.
DOT	Pipeline safety compliance.

16

Recovery Mechanisms

Mechanism	Additional Information
ECA	Recovers fuel and purchased energy costs. Short-term sales margins are shared with customers through the ECA. The ECA is revised quarterly.
PCCA	Recovers purchased capacity payments.
SCA	Recovers fuel costs to operate the steam system. The SCA rate is revised quarterly.
DSMCA	Recovers electric and gas DSM, interruptible service costs and performance initiatives for achieving energy savings goals.
RESA	Recovers the incremental costs of compliance with the RES with a maximum of 1% of the customer’s bill.
CEPA	Recovers the early retirement costs of Comanche units 1 and 2 to a maximum of 1% of the customer’s bill.
WCA	Recovers costs for customers who choose renewable resources.
TCA	Recovers costs for transmission investment between rate cases.
CACJA	Recovers costs associated with the CACJA.
FCA	PSCo recovers fuel and purchased energy costs from wholesale electric customers through a fuel cost adjustment clause approved by the FERC. Wholesale customers pay production costs through a forecasted formula rate subject to true-up.
GCA	Recovers costs of purchased natural gas and transportation and is revised quarterly to allow for changes in natural gas rates.
PSIA	Recovers costs for transmission and distribution pipeline integrity management programs.
Decoupling	Mechanism to true-up revenue to a baseline amount for residential (excluding lighting and demand) and metered non-demand small C&I classes. Represents approximately $51M for differences in sales to the baseline amount. Amounts refunded or surcharged to customers may be limited to a refund cap.

Pending and Recently Concluded Regulatory Proceedings

Proceeding	Amount (in millions)	Filing Date	Approval
2020 Natural Gas Rate Case	$77	February 2020	Received
2019 Electric Rate Case	108	May 2019	Received
2019 Natural Gas Rate Case Appeal	N/A	April 2019	Pending
Wildfire Protection Rider	325	July 2020	Pending
Transportation Electrification Plan Rider	110 - 138	May 2020	Received

Additional Information:

2020 Natural Gas Rate Case — In October 2020, the CPUC approved a settlement resulting in a net increase of $77 million. This increase reflects a $94 million increase in base rate revenue, partially offset by $17 million of costs previously recovered through the Pipeline Integrity rider. Rates will be implemented on April 1, 2021 (retroactive to November 2020).

2019 Electric Rate Case — In 2019, PSCo filed a request with the CPUC seeking a net rate increase of approximately $108 million. In February 2020, the CPUC issued an initial decision for a net rate increase of $35 million. In July 2020, the CPUC’s final written decision on rehearing was received and resulted in an additional increase of approximately $12 million annually.

In December 2020, the CPUC denied PSCo’s request of a $5 million surcharge for changes to the revenue increase from the effective date of rates, based on the CPUC’s decision on rehearing. PSCo has appealed this decision with the District Court of Denver County.

2019 Phase I Electric Rate Case Appeal — In August 2020, PSCo filed an appeal with the Denver District Court seeking a review of CPUC decisions on gain on sales and losses of assets, oil and gas royalty revenues and Board of Director’s equity compensation. PSCo plans to seek consolidation of this appeal with the appeal of the surcharge decision in this same proceeding.

2019 Natural Gas Rate Case Appeal — In April 2019, PSCo filed an appeal seeking judicial review of the CPUC’s prior ruling regarding PSCo’s natural gas rate case (filed in June 2017 and approved in December 2018). The appeal requested review of the following: denial of a return on the prepaid pension and retiree medical assets; the use of a capital structure not based on the actual historical test year; and use of an average rate base methodology rather than a year-end rate base methodology.

In March 2020, The District Court of Denver County ruled in favor of allowing the prepaid pension assets to be included in rate base; but upheld the CPUC’s treatment of the retiree medical assets and capital structure methodology. In March 2021, PSCo expects to file a motion to implement the District Court’s decision on treatment of the prepaid pension asset for the applicable period of Jan. 1, 2018 through Oct. 31, 2020.

Wildfire Protection Rider — In 2020, PSCo requested to establish a rider to recover incremental costs associated with system investments to reduce wildfire risk. The rider would be effective in June 2021 and continue through 2025. The Office of Consumer Counsel and CPUC Staff are supportive of the wildfire mitigation program as proposed, but oppose rider recovery and instead recommend deferral of certain costs with recovery in a future rate case. A CPUC decision is expected in the second quarter of 2021.

Wildfire Protection capital investment is projected to be approximately $325 million. Forecasted annual revenue requirements from 2021 through 2025:

(Millions of Dollars)	2021		2022		2023		2024		2025
Forecasted annual revenue requirement	$	17	$	24	$	29	$	32	$	34

Transportation Electrification Plan — In January 2021, the CPUC approved PSCo's Transportation Electrification Plan, which authorizes rider recovery of new electric vehicle utility programs for the residential, commercial, multi-family and public charging sectors. The approval establishes utility-owned charging infrastructure and chargers and amortization of rebates for electric vehicles. The Transportation Electrification Plan approval authorizes approximately $110 million in spending with flexibility up to approximately $138 million over three years.

Advanced Grid Rider

In 2020, PSCo requested to establish a rider to recover incremental costs associated with the Advanced Grid Intelligence and Security initiative. The rider would be effective in May 2021 and continue through 2025. In October 2020, an Administrative Law Judge issued The Recommended Decision granting the Office of Consumer Counsel motion to dismiss the Advanced Grid Rider. PSCo has chosen not to appeal the Administrative Law Judge’s Recommended Decision.

The PSCo portion of the Advanced Grid Intelligence and Security capital investment is projected to be approximately $850 million. Forecasted annual revenue requirements from 2021 through 2025 are as follows:

(Millions of Dollars)	2021		2022		2023		2024		2025
Forecasted annual revenue requirement	$	53	$	69	$	83	$	89	$	99

17

PSCo KEPCO Filing

In September 2020, PSCo filed with the CPUC for approval to terminate a solar PPA with KEPCO Solar of Alamosa, Inc. and establish a regulatory asset to recover transaction costs of approximately $41 million. By terminating the PPA, customers would save approximately $38 million over an 11-year period. A CPUC decision is expected in the second quarter of 2021.

Natural Gas LDC and Emission Reductions

In October 2020, the CPUC opened a docket to investigate topics related to natural gas emissions in relation to statewide emission reduction goals. The first meeting was held in November 2020, in which subject matter experts discussed greenhouse emission reductions required from the natural gas industry in regard to the statewide goals.

Resource Plan

PSCo is expected to file its next Electric Resource Plan on March 31, 2021. The filing will propose the future of the remaining coal plants in Colorado and PSCo’s plan to achieve it’s 80% carbon emissions reduction target by 2030. A CPUC decision is expected in 2022.

PSCo — Comanche Unit 3

PSCo is part owner and operator of Comanche Unit 3, a 750 MW, coal-fueled electric generating unit. In January 2020, the unit experienced a turbine failure causing the unit to be taken offline for repairs, which were completed in June 2020. During start-up the unit experienced a loss of turbine oil, which damaged the plant. Comanche Unit 3 recommenced operations in January 2021. Replacement and repair of damaged systems in excess of a $2 million deductible are expected to be recovered through insurance policies. PSCo obtained replacement power costs of approximately $16 million during the outage. In October 2020, the CPUC initiated a non-adjudicatory review of Comanche Unit 3’s performance. A report on performance is expected to be issued in March 2021. At this stage of the regulatory review, the resulting recommendations of the CPUC’s staff cannot be determined.

Boulder Municipalization

In 2011, Boulder passed a ballot measure authorizing the formation of an electric municipal utility. Subsequently, there have been various legal proceedings in multiple venues.

In September 2020, the City Council voted to approve a settlement between PSCo and Boulder officials to end the city’s municipalization effort. The settlement resulted in a 20-year franchise arrangement (with multiple opt-out conditions), an energy partnership and an undergrounding agreement. It also established the municipalization process if Boulder exercised an opt-out. In December 2020, PSCo filed the franchise agreement with the CPUC and is currently awaiting a decision.

Purchased Power and Transmission Service Providers

PSCo expects to meet its system capacity requirements through electric generating stations, power purchases, new generation facilities, DSM options and expansion of generation plants.

Purchased Power — PSCo purchases power from other utilities and IPPs. Long-term purchased power contracts for dispatchable resources typically require capacity and energy charges. It also contracts to purchase power for both wind and solar resources. PSCo makes short-term purchases to meet system load and energy requirements, replace owned generation, meet operating reserve obligations, or obtain energy at a lower cost.

Energy Markets — PSCo is working towards joining the Western Energy Imbalance Market in 2022. This market was developed by the California ISO and allows PSCo access to a real-time energy market. The Western Energy Imbalance Market allows 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 and credit risk and hedge sales and purchases. PSCo also engages in trading activity unrelated to hedging. Sharing of any margin is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement.

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 of a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk.

See Note 8 to the consolidated financial statements for further information.

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 under the contracts underlying its derivatives, the contracts expose PSCo to certain credit and non-performance risk.

Distress in the financial markets may impact counterparty risk, the fair value of the securities in the pension fund and PSCo’s ability to earn a return on short-term investments.

Commodity Price Risk — PSCo is exposed to commodity price risk in its 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. PSCo’s risk management policy allows it 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.

18

Fair value of net commodity trading contracts as of Dec. 31, 2020:

	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	$	—	$	—	$	1
PSCo (b)		(25)		(39)		(13)		—		(77)
		$	(25)	$	(38)	$	(13)	$	—	$	(76)

	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)		$	13	$	16	$	1	$	—	$	30

(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)	2020		2019
Fair value of commodity trading net contracts outstanding at Jan. 1	$	(57)	$	1
Contracts realized or settled during the period	2		(11)
Commodity trading contract additions and changes during the period	9		(47)
Fair value of commodity trading net contracts outstanding at Dec.31	$	(46)	$	(57)

At Dec. 31, 2020, a 10% increase in market prices for commodity trading contracts through the forward curve would increase pretax income from continuing operations by approximately $7 million, whereas a 10% decrease would decrease pretax income from continuing operations by approximately $7 million. At Dec. 31, 2019, a 10% increase in market prices for commodity trading contracts would increase pretax income from continuing operations by approximately $3 million, whereas a 10% decrease would decrease pretax income from continuing operations by approximately $3 million. Market price movements can exceed 10% under abnormal circumstances.

PSCo’s commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations that have been entered into, but not closed, using an industry standard methodology known as VaR. VaR expresses the potential change in fair value on 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 purchase, 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		VaR Limit		Average		High		Low
2020	$	1	$	3	$	1	$	2	$	1
2019	< 1		3		1		1		< 1

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 such as swaps, caps, collars and put or call options.

A 100 basis point change in the benchmark rate on PSCo’s variable rate debt would impact pretax interest expense annually by an immaterial amount in 2020 and 2019, respectively.

See Note 8 to the consolidated financial statements for further information.

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 monitor these policies to reflect changes and scope of operations.

At Dec. 31, 2020, a 10% increase in commodity prices would have resulted in an immaterial increase in credit exposure, while a decrease in prices of 10% would have resulted in an immaterial decrease in credit exposure. At Dec. 31, 2019, a 10% increase in commodity prices would have resulted in a decrease in credit exposure of $3 million, while a decrease in prices of 10% would have resulted in an increase in credit exposure of $7 million.

PSCo conducts credit reviews for all 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

PSCo uses derivative contracts such as futures, forwards, interest rate swaps, options and FTRs to manage commodity price and interest rate risk. Derivative contracts, with the exception of those designated as normal purchase-normal sale contracts, are reported at fair value.

PSCo’s investments held in rabbi trusts, pension and other postretirement funds are also subject to fair value accounting.

Commodity Derivatives — PSCo continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions. The impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets at Dec. 31, 2020. 

Adjustments to fair value for credit risk of commodity trading instruments are recorded in electric revenues. Credit risk adjustments for other commodity derivative instruments are recorded as other comprehensive income or deferred as regulatory assets and liabilities. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. The impact of discounting commodity derivative liabilities for credit risk was immaterial at Dec. 31, 2020.

See Notes 8 and 9 to the consolidated financial statements for further information.

19

Natural Gas Fuel and Electricity Purchases

In February 2021, the United States experienced winter storm Uri and extreme cold temperatures in the central United States. This severe weather event increased the demand for natural gas used in our electric and natural gas businesses. Certain operational assets were impacted by extreme cold temperatures and the cold further impacted the availability of renewable generation across the region (which typically acts as a hedge against commodity prices) contributing to extremely high market prices for natural gas and electricity. As a result, electric and natural gas fuel costs increased approximately $650 million. These amounts are preliminary estimates through Feb. 16, 2021 and are subject to final settlement.

PSCo has fuel recovery mechanisms to recover the increased cost of natural gas and electricity. However, given the impact of these higher costs to our customers during a pandemic, we expect our regulator to undertake a heightened review and we intend to work with our commission to recover these costs over time to help mitigate the impacts on customer bills. PSCo is taking action to increase planned debt issuances to ensure adequate liquidity for the timing difference between fuel payments and revenue collection from customers and to address any potential need to post collateral.

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.

20

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, 2020. 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, 2020, PSCo’s internal control over financial reporting is effective at the reasonable assurance level based on those criteria.

/s/ BEN FOWKE	/s/ BRIAN J. VAN ABEL
Ben Fowke	Brian J. Van Abel
Chairman, Chief Executive Officer and Director	Executive Vice President, Chief Financial Officer and Director
Feb. 17, 2021	Feb. 17, 2021

21

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholder and 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, 2020 and 2019, the related consolidated statements of income, comprehensive income, cash flows and common stockholder's equity, for each of the three years in the period ended December 31, 2020, 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, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, 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.

22

We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant, and 3) a refund due to customers. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:

•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the recognition of regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

•We read relevant regulatory orders issued by the Commissions for the Company, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We also evaluated regulatory filings for any evidence that intervenors are challenging full recovery of the cost of any capital projects. If the full recovery of project costs is being challenged by intervenors, we evaluated management’s assessment of the probability of a disallowance. We evaluated the external information and compared to the Company’s recorded regulatory assets and liabilities for completeness.

•We obtained management’s analysis and correspondence from counsel, as appropriate, regarding regulatory assets or liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 17, 2021

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

23

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(amounts in millions)

	Year Ended Dec. 31
	2020		2019		2018
Operating revenues
Electric	$	3,116	$	3,033	$	3,031
Natural gas	1,024		1,161		1,015
Other	43		43		40
Total operating revenues	4,183		4,237		4,086
Operating expenses
Electric fuel and purchased power	1,132		1,083		1,157
Cost of natural gas sold and transported	374		526		428
Cost of sales — steam and other	13		17		15
Operating and maintenance expenses	811		810		788
Demand side management expenses	141		136		142
Depreciation and amortization	655		602		561
Taxes (other than income taxes)	234		206		202
Total operating expenses	3,360		3,380		3,293
Operating income	823		857		793
Other (expense) income, net	(1)		3		2
Allowance for funds used during construction — equity	35		22		56
Interest charges and financing costs
Interest charges — includes other financing costs of $7, $7 and $7, respectively	238		235		208
Allowance for funds used during construction — debt	(14)		(11)		(22)
Total interest charges and financing costs	224		224		186
Income before income taxes	633		658		665
Income tax expense	45		80		113
Net income	$	588	$	578	$	552

See Notes to Consolidated Financial Statements

24

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(amounts in millions)

	Year Ended Dec. 31
	2020		2019		2018
Net income	$	588	$	578	$	552
Other comprehensive income (loss)
Pension and retiree medical benefits:
Reclassification of loss (gain) to net income, net of tax of $1, $(1) and $—, respectively	2		(3)		—
Derivative instruments:
Reclassification of loss to net income, net of tax of $—, $— and $—, respectively	1		2		1
Total other comprehensive income (loss)	3		(1)		1
Total comprehensive income	$	591	$	577	$	553

See Notes to Consolidated Financial Statements

25

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(amounts in millions)

	Year Ended Dec. 31
	2020		2019		2018
Operating activities
Net income	$	588	$	578	$	552
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	656		607		566
Deferred income taxes	2		97		24
Allowance for equity funds used during construction	(35)		(22)		(56)
Provision for bad debts	24		17		16
Net realized and unrealized hedging and derivative transactions	(14)		62		(6)
Changes in operating assets and liabilities:
Accounts receivable	(51)		(22)		(43)
Accrued unbilled revenues	(5)		20		(18)
Inventories	(27)		(27)		(20)
Prepayments and other	(8)		(29)		13
Accounts payable	(14)		(44)		69
Net regulatory assets and liabilities	58		35		(15)
Other current liabilities	45		—		(13)
Pension and other employee benefit obligations	(41)		(47)		(44)
Other, net	(4)		3		(17)
Net cash provided by operating activities	1,174		1,228		1,008
Investing activities
Utility capital/construction expenditures	(1,671)		(1,691)		(1,577)
Investments in utility money pool arrangement	(122)		(641)		(634)
Repayments from utility money pool arrangement	122		641		654
Net cash used in investing activities	(1,671)		(1,691)		(1,557)
Financing activities
Proceeds from (repayments of) short-term borrowings, net	136		(307)		307
Borrowings under utility money pool arrangement	1,189		100		780
Repayments under utility money pool arrangement	(1,171)		(61)		(780)
Proceeds from issuance of long-term debt	735		928		691
Repayments of long-term debt	(400)		(400)		(300)
Capital contributions from parent	856		638		252
Dividends paid to parent	(831)		(457)		(375)
Net cash provided by financing activities	514		441		575
Net change in cash and cash equivalents	17		(22)		26
Cash and cash equivalents at beginning of period	11		33		7
Cash and cash equivalents at end of period	$	28	$	11	$	33
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(211)	$	(209)	$	(187)
Cash paid for income taxes, net	(23)		(5)		(116)
Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions	$	197	$	234	$	142
Inventory transfers to property, plant and equipment	35		32		37
Operating lease right-of-use assets	14		654		—
Allowance for equity funds used during construction	35		22		56

See Notes to Consolidated Financial Statements

26

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(amounts in millions, except share and per share)

	Dec. 31
	2020		2019
Assets
Current assets
Cash and cash equivalents	$	28	$	11
Accounts receivable, net	342		304
Accounts receivable from affiliates	8		53
Accrued unbilled revenues	298		294
Inventories	189		192
Regulatory assets	121		64
Derivative instruments	21		7
Prepayments and other	82		56
Total current assets	1,089		981
Property, plant and equipment, net	17,470		16,155
Other assets
Regulatory assets	1,059		1,038
Derivative instruments	16		—
Operating lease right-of-use assets	500		574
Other	231		260
Total other assets	1,806		1,872
Total assets	$	20,365	$	19,008
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	—	$	400
Borrowings under utility money pool arrangement	57		39
Short-term debt	136		—
Accounts payable	452		573
Accounts payable to affiliates	58		44
Regulatory liabilities	100		69
Taxes accrued	251		202
Accrued interest	61		53
Dividends payable to parent	105		112
Derivative instruments	27		9
Operating lease liabilities	97		86
Other	84		99
Total current liabilities	1,428		1,686
Deferred credits and other liabilities
Deferred income taxes	1,897		1,851
Deferred investment tax credits	20		23
Regulatory liabilities	2,337		2,037
Asset retirement obligations	399		324
Derivative instruments	51		53
Customer advances	168		173
Pension and employee benefit obligations	161		212
Operating lease liabilities	432		518
Other	156		150
Total deferred credits and other liabilities	5,621		5,341
Commitments and contingencies
Capitalization
Long-term debt	5,724		4,985
Common stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2020 and Dec. 31, 2019, respectively	—		—
Additional paid in capital	5,770		4,940
Retained earnings	1,846		2,083
Accumulated other comprehensive loss	(24)		(27)
Total common stockholder's equity	7,592		6,996
Total liabilities and stockholder's equity	$	20,365	$	19,008
See Notes to Consolidated Financial Statements

27

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, 2017	100	$	—	$	4,033	$	1,822	$	(27)	$	5,828
Net income						552				552
Other comprehensive income								1		1
Common dividends declared to parent						(391)				(391)
Contribution of capital by parent				308						308
Balance at Dec. 31, 2018	100	$	—	$	4,341	$	1,983	$	(26)	$	6,298
Net income						578				578
Other comprehensive income								(1)		(1)
Common dividends declared to parent						(478)				(478)
Contribution of capital by parent				599						599
Balance at Dec. 31, 2019	100	$	—	$	4,940	$	2,083	$	(27)	$	6,996
Net income						588				588
Other comprehensive income								3		3
Common dividends declared to parent						(824)				(824)
Contribution of capital by parent				830						830
Adoption of ASC Topic 326						(1)				(1)
Balance at Dec. 31, 2020	100	$	—	$	5,770	$	1,846	$	(24)	$	7,592
See Notes to Consolidated Financial Statements

28

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 in 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 the 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 various state regulatory commissions. Certain amounts in the consolidated financial statements or notes have been reclassified for comparative purposes; however, such reclassifications did not affect net income, total assets, liabilities, equity or cash flows.

PSCo has evaluated events occurring after Dec. 31, 2020 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 in recording transactions and balances resulting from business operations. Estimates are used on 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 of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. 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 from its balance sheet. 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 financial statements. PSCo defers income taxes for all temporary differences between pretax financial and taxable income and between the book and tax bases of assets and liabilities. PSCo uses rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the period that includes the enactment date.

The effects of 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, which would be refundable to utility customers over the remaining life of the related assets. PSCo anticipates that a tax rate increase would result in the establishment of a regulatory asset, subject to regulatory approval.

Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of regulatory assets and liabilities related to income taxes. 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.

PSCo follows the applicable accounting guidance to measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns. PSCo recognizes a tax position in its 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.

PSCo reports interest and penalties related to income taxes within other (expense) income 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 are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property.

29

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.

PSCo records depreciation expense using the straight-line method over the plant’s 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 recovered in rates as authorized by the appropriate regulatory entities. The amount of removal costs are based on current factors used in existing depreciation rates. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.1% in 2020, 2.9% in 2019 and 2.6% in 2018.

See Note 3 for further information.

AROs — PSCo accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement 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 depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount 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 liability 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. If an environmental expense is related to facilities currently in use, such as 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 proceeds. 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. 

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

See Note 10 for further information.

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

PSCo does not recognize a separate financing component of its collections from customers as contract terms are short-term in nature. PSCo presents its revenues net of any excise or sales taxes or fees.

See Note 6 for further information.

Cash and Cash Equivalents — PSCo considers investments in instruments with a remaining maturity of three 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, 2020 and 2019, the allowance for bad debts was $29 million and $21 million, respectively.

Inventory — Inventory is recorded at average cost and consisted of the following:

(Millions of Dollars)	Dec. 31, 2020		Dec. 31, 2019
Inventories
Materials and supplies	$	63	$	63
Fuel	73		77
Natural gas	53		52
Total inventories	$	189	$	192

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

Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted NAVs. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used to establish 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, PSCo may use quoted prices for similar contracts or internally prepared valuation models to determine fair value. 

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

See Notes 8 and 9 for further information.

30

Derivative Instruments — PSCo uses derivative instruments in connection with its interest rate, utility commodity price and commodity trading activities, including forward contracts, futures, swaps and options. Any derivative instruments not qualifying for the normal purchases and normal sales exception are recorded on the consolidated balance sheets at fair value as derivative instruments. Classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues and interest rate hedging transactions are recorded as a component of interest expense. 

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 a derivative exists and/or whether an instrument may be exempted from derivative accounting if designated as a normal purchase or normal sale.

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. AFUDC 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 for establishing utility rates.

Alternative Revenue — Certain rate rider mechanisms (including decoupling and DSM programs) qualify as alternative revenue programs. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate. When certain criteria are met, including expected collection within 24 months, revenue is recognized equal to the revenue requirement, which may include incentives and return on rate base items. Billing amounts are revised periodically for differences between total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers.

See Note 6 for further information.

Conservation Programs — 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 annual period 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 — Emission allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emission allowances and sales of these allowances are included in electric revenues.

RECs — Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. PSCo records that cost as a regulatory asset when the amount is recoverable in future rates.

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

2. Accounting Pronouncements

Recently Adopted

Credit Losses — In 2016, the FASB issued Financial Instruments - Credit Losses, Topic 326 (ASC Topic 326), which changes how entities account for losses on receivables and certain other assets. The guidance requires use of a current expected credit loss model, which may result in earlier recognition of credit losses than under previous accounting standards.

PSCo implemented the guidance using a modified-retrospective approach, recognizing a cumulative effect charge of $1 million (after tax) to retained earnings on Jan. 1, 2020. Other than first-time recognition of an allowance for bad debts on accrued unbilled revenues, the Jan. 1, 2020, adoption of ASC Topic 326 did not have a significant impact on PSCo’s consolidated financial statements.

31

3. Plant, Property and Equipment

Major classes of property, plant and equipment

(Millions of Dollars)	Dec. 31, 2020		Dec. 31, 2019
Property, plant and equipment, net
Electric plant	$	15,736	$	14,362
Natural gas plant	5,037		4,631
Common and other property	1,191		1,113
Plant to be retired (a)	225		260
CWIP	510		913
Total property, plant and equipment	22,699		21,279
Less accumulated depreciation	(5,229)		(5,124)
Property, plant and equipment, net	$	17,470	$	16,155

(a)Includes regulator-approved retirements of Comanche Units 1 and 2 and jointly owned Craig Unit 1. Also includes PSCo’s planned retirement of jointly owned Craig Unit 2.

Joint Ownership of Generation, Transmission and Gas Facilities

Jointly owned assets as of Dec. 31, 2020:

(Millions of Dollars, Except Percent Owned)	Plant in Service		Accumulated Depreciation		CWIP		Percent Owned
Electric generation:
Hayden Unit 1	$	153	$	92	$	—	76	%
Hayden Unit 2	150		73		—		37
Hayden common facilities	42		25		—		53
Craig Units 1 and 2	81		44		—		10
Craig common facilities	39		24		—		7
Comanche Unit 3	899		137		16		67
Comanche common facilities	25		2		—		82
Electric transmission:
Transmission and other facilities	176		59		2		Various
Gas transmission:
Rifle, CO to Avon, CO	22		8		—		60
Gas transmission compressor	8		1		—		50
Total	$	1,595	$	465	$	18

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, 2020				Dec. 31, 2019
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Pension and retiree medical obligations	9	Various	$	28	$	478	$	23	$	494
Depreciation differences		One to 11 years	16		154		15		140
Net AROs (a)	1, 10	Various	—		132		—		119
Recoverable deferred taxes on AFUDC		Plant lives	—		110		—		105
Excess deferred taxes — TCJA	7	Various	3		56		3		55
Purchased power contract costs		Term of related contract	3		22		2		24
Property tax		Various	16		21		1		30
Conservation programs (b)	1	One to two years	11		11		8		11
Gas pipeline inspection costs		One to two years	—		9		—		8
Losses on reacquired debt		Term of related debt	1		3		1		4
Contract valuation adjustments (c)	1, 8	Term of related contract	6		—		3		—
Recoverable purchased natural gas and electric energy costs		Less than one year	6		—		—		—
Other		Various	31		63		8		48
Total regulatory assets			$	121	$	1,059	$	64	$	1,038

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

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

(c)Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.

32

Components of regulatory liabilities:

(Millions of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2020				Dec. 31, 2019
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Deferred income tax adjustments and TCJA refunds (a)	7	Various	$	5	$	1,368	$	5	$	1,403
Plant removal costs	1, 10	Various	—		615		—		351
Effects of regulation on employee benefit costs (b)		Various	—		203		—		183
Renewable resources and environmental initiatives		Various	—		59		—		45
Revenue decoupling		One to two years	10		41		—		—
ITC deferrals	1	Various	—		40		—		26
Conservation programs (c)	1	Less than one year	39		—		30		—
Deferred electric, natural gas and steam production costs		Less than one year	17		—		8		—
Other		Various	29		11		26		29
Total regulatory liabilities			$	100	$	2,337	$	69	$	2,037

(a)Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA.

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

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

At Dec. 31, 2020 and 2019, PSCo’s regulatory assets not earning a return primarily included the unfunded portion of pension and retiree medical obligations and net AROs. In addition, PSCo’s regulatory assets included $195 million and $160 million at Dec. 31, 2020 and 2019, respectively, of past expenditures not earning a return. Amounts are related to funded pension obligations, property taxes, various renewable resources and certain environmental initiatives.

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 for PSCo were as follows:

(Millions of Dollars, Except Interest Rates)	Three Months Ended Dec. 31, 2020			Year Ended Dec. 31
				2020			2019			2018
Borrowing limit	$	250		$	250		$	250		$	250
Amount outstanding at period end	57			57			39			—
Average amount outstanding	104			59			7			25
Maximum amount outstanding	218			250			50			156
Weighted average interest rate, computed on a daily basis	0.08		%	0.60		%	2.29		%	1.93		%
Weighted average interest rate at end of period	0.07			0.07			1.63			N/A

Commercial Paper — Commercial paper borrowings for PSCo were as follows:

(Millions of Dollars, Except Interest Rates)	Three Months Ended Dec. 31, 2020			Year Ended Dec. 31
				2020			2019			2018
Borrowing limit	$	700		$	700		$	700		$	700
Amount outstanding at period end	136			136			—			307
Average amount outstanding	8			30			154			55
Maximum amount outstanding	136			230			432			309
Weighted average interest rate, computed on a daily basis	0.19		%	1.59		%	2.67		%	2.28		%
Weighted average interest rate at end of period	0.20			0.20			N/A			2.95

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, 2020 and 2019, there were $8 million and $9 million of letters of credit outstanding under the credit facility, respectively. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

Credit Facility — In order to use 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.

Amended Credit Agreement — In June 2019, PSCo entered into an amended five-year credit agreement with a syndicate of banks. The amended credit agreement has substantially the same terms and conditions as the prior credit agreement with the exception of the maturity, which is June 2024.

Features of PSCo’s credit facility:

Debt-to-Total Capitalization Ratio (a)				Amount Facility May Be Increased (millions)		Additional Periods for Which a One-Year Extension May Be Requested (b)
2020		2019
44	%	44	%	$	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.

33

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, 2020, PSCo was in compliance with all financial covenants.

PSCO had the following committed credit facility available as of Dec. 31, 2020 (millions):

Credit Facility (a)		Drawn (b)		Available
$	700	$	144	$	556

(a)This credit facility matures in June 2024.

(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, 2020 and 2019.

Long-Term Borrowings and Other Financing Instruments

Generally, property of PSCo is subject to the liens of its first mortgage indenture. 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 (millions of dollars):

Financing Instrument	Interest Rate	Maturity Date	2020		2019
First mortgage bonds	3.20	Nov. 15, 2020	—		400
First mortgage bonds	2.25	Sept. 15, 2022	300		300
First mortgage bonds	2.50	March 15, 2023	250		250
First mortgage bonds	2.90	May 15, 2025	250		250
First mortgage bonds	3.70	June 15, 2028	350		350
First mortgage bonds (a)	1.90	Jan. 15, 2031	375		—
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 (b)	4.05	Sept. 15, 2049	400		400
First mortgage bonds (b)	3.20	March 1, 2050	550		550
First mortgage bonds (a)	2.70	Jan. 15, 2051	375		—
Unamortized discount			(30)		(24)
Unamortized debt issuance cost			(46)		(41)
Current maturities			—		(400)
Total long-term debt			$	5,724	$	4,985

(a)2020 financing.

(b)2019 financing.

Maturities of long-term debt:

(Millions of Dollars)
2021	$	—
2022	300
2023	250
2024	—
2025	250

Deferred Financing Costs — Deferred financing costs of approximately $46 million and $41 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt as of Dec. 31, 2020 and 2019, respectively. PSCo is amortizing these financing costs over the remaining maturity periods of the related debt.

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

Preferred Stock Authorized (Shares)	Par Value of Preferred Stock		Preferred Stock Outstanding (Shares) 2020 and 2019
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, 2020
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	1,073	$	650	$	12	$	1,735
C&I	1,512		225		27		1,764
Other	48		—		—		48
Total retail	2,633		875		39		3,547
Wholesale	212		—		—		212
Transmission	62		—		—		62
Other	56		125		—		181
Total revenue from contracts with customers	2,963		1,000		39		4,002
Alternative revenue and other	153		24		4		181
Total revenues	$	3,116	$	1,024	$	43	$	4,183

	Year Ended Dec. 31, 2019
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	1,006	$	750	$	11	$	1,767
C&I	1,579		281		28		1,888
Other	50		—		—		50
Total retail	2,635		1,031		39		3,705
Wholesale	166		—		—		166
Transmission	52		—		—		52
Other	32		107		—		139
Total revenue from contracts with customers	2,885		1,138		39		4,062
Alternative revenue and other	148		23		4		175
Total revenues	$	3,033	$	1,161	$	43	$	4,237

34

	Year Ended Dec. 31, 2018
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	991	$	606	$	11	$	1,608
C&I	1,560		224		25		1,809
Other	48		—		—		48
Total retail	2,599		830		36		3,465
Wholesale	175		—		—		175
Transmission	54		—		—		54
Other	55		84		—		139
Total revenue from contracts with customers	2,883		914		36		3,833
Alternative revenue and other	148		101		4		253
Total revenues	$	3,031	$	1,015	$	40	$	4,086

7. Income Taxes

Federal Tax Loss Carryback Claims — In 2020, Xcel Energy identified certain expenses related to tax years 2009 - 2011 that qualify for an extended carryback claim. PSCo is not expected to accrue any income tax expense related to this adjustment.

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

Tax Year(s)	Expiration
2014 - 2016	July 2021

Additionally, the statute of limitations related to the federal tax loss carryback claim referenced above has been extended. Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is unknown.

In 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s NOL and ETR. Xcel Energy filed a protest with the IRS. In April 2020, Xcel Energy and Appeals reached an agreement and no material adjustments were required.

In 2018, the IRS began an audit of tax years 2014 - 2016. In July 2020, Xcel Energy and the IRS reached an agreement and the related benefit was recognized.

State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2020, PSCo’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. There are currently no state income tax audits in progress.

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

Unrecognized tax benefits - permanent vs temporary:

(Millions of Dollars)	Dec. 31, 2020		Dec. 31, 2019
Unrecognized tax benefit — Permanent tax positions	$	7	$	7
Unrecognized tax benefit — Temporary tax positions	2		5
Total unrecognized tax benefit	$	9	$	12

Changes in unrecognized tax benefits:

(Millions of Dollars)	2020		2019		2018
Balance at Jan. 1	$	12	$	10	$	10
Additions based on tax positions related to the current year	2		1		1
Additions for tax positions of prior years	6		1		—
Reductions for tax positions of prior years	(11)		—		—
Settlements with taxing authorities	—		—		(1)
Balance at Dec. 31	$	9	$	12	$	10

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

(Millions of Dollars)	Dec. 31, 2020		Dec. 31, 2019
NOL and tax credit carryforwards	$	(8)	$	(8)

Net deferred tax liability associated with the unrecognized tax benefit amounts and related NOLs and tax credits carryforwards were $6 million and $5 million for Dec. 31, 2020 and Dec. 31, 2019, respectively.

As the IRS and state audits resume, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $3 million in the next 12 months.

Payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards.

Interest payable related to unrecognized tax benefits:

(Millions of Dollars)	2020		2019		2018
Payable for interest related to unrecognized tax benefits at Jan. 1	$	(1)	$	(1)	$	—
Interest income (expense) related to unrecognized tax benefits	1		—		(1)
Payable for interest related to unrecognized tax benefits at Dec. 31	$	—	$	(1)	$	(1)

No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2020, 2019 or 2018.

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)	2020		2019
Federal tax credit carryforwards	$	143	$	83
State NOL carryforwards	190		388
State tax credit carryforwards, net of federal detriment (a)	18		18
Valuation allowances for state credit carryforwards, net of federal benefit (b)	(8)		(8)

(a)State tax credit carryforwards are net of federal detriment of $5 million as of both Dec. 31, 2020 and 2019.

(b)Valuation allowances for state tax credit carryforwards were net of federal benefit of $2 million as of both Dec. 31, 2020 and 2019.

Federal carryforward periods expire between 2031 and 2040 and state carryforward periods expire between 2021 and 2033.

35

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:

	2020		2019		2018
Federal statutory rate	21.0	%	21.0	%	21.0	%
State income tax on pretax income, net of federal tax effect	3.6		3.6		3.7
Increases (decreases) in tax from:
Wind PTCs	(10.3)		(7.5)		(0.6)
Plant regulatory differences (a)	(5.0)		(3.3)		(4.5)
Other tax credits, net NOL & tax credit allowances	(1.1)		(1.3)		(0.6)
Amortization of excess nonplant deferred taxes	(0.2)		(0.2)		(1.4)
Change in unrecognized tax benefits	(0.2)		0.3		0.1
Other, net	(0.7)		(0.4)		(0.7)
Effective income tax rate	7.1	%	12.2	%	17.0	%

.(a) Regulatory differences for income tax primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit of excess deferred credits are offset by corresponding revenue reductions and additional prepaid pension asset amortization.

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

(Millions of Dollars)	2020		2019		2018
Current federal tax expense (benefit)	$	44	$	(9)	$	79
Current state tax expense (benefit)	4		(5)		14
Current change in unrecognized tax benefit	(3)		(1)		(1)
Deferred federal tax (benefit) expense	(26)		61		5
Deferred state tax expense	26		33		17
Deferred change in unrecognized tax expense	2		3		2
Deferred ITCs	(2)		(2)		(3)
Total income tax expense	$	45	$	80	$	113

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

(Millions of Dollars)	2020		2019		2018
Deferred tax expense excluding items below	$	46	$	132	$	75
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(43)		(35)		(51)
Tax expense allocated to other comprehensive income, adoption of ASC Topic 326, adoption of ASU No. 2018-02, and other	(1)		—		—
Deferred tax expense	$	2	$	97	$	24

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

(Millions of Dollars)	2020		2019 (a)
Deferred tax liabilities:
Differences between book and tax bases of property	$	2,132	$	2,039
Regulatory assets	257		253
Operating lease assets	129		148
Pension expense and other employee benefits	19		22
Other	6		7
Total deferred tax liabilities	$	2,543	$	2,469
Deferred tax assets:
Regulatory liabilities	$	319	$	327
Tax credit carryforward	161		101
Operating lease liabilities	129		148
Bad debts	8		5
NOL carryforward	7		14
Deferred ITCs	5		6
Tax credit valuation allowances	(8)		(8)
Other	25		25
Total deferred tax assets	$	646	$	618
Net deferred tax liability	$	1,897	$	1,851

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

8. Fair Value of Financial Assets and Liabilities

Fair Value Measurements

Accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. 

•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 highly liquid and actively traded instruments with quoted prices.

•Level 2 — Pricing inputs are other than quoted 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 are those valued with models requiring significant management judgment or estimation.

Specific valuation methods include:

Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted net asset value.

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

36

Commodity derivatives — The 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 contractual settlements relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of forward prices and volatilities on a valuation is evaluated and may result in Level 3 classification.

Derivative Instruments 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, utility commodity prices and vehicle fuel prices.

Interest Rate Derivatives — PSCo enters into various instruments that effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes, with changes in fair value prior to settlement recorded as other comprehensive income.

As of Dec. 31, 2020, accumulated other comprehensive loss related to settled 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, including forecasted amounts for unsettled hedges, as applicable.

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 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 activities governed by this policy.

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, as well as for trading purposes. 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.

PSCo enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but may not be designated as qualifying hedging transactions. The classification as a regulatory asset or liability, if applicable, is based on approved regulatory recovery mechanisms.

As of Dec. 31, 2020, PSCo had no commodity contracts designated as cash flow hedges.

PSCo enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of amounts credited to customers under margin-sharing mechanisms.

Gross notional amounts of commodity forwards and options:

(Amounts in Millions) (a)(b)	Dec. 31, 2020	Dec. 31, 2019
MWh of electricity	17	9
MMBtu of natural gas	93	32

(a)Not reflective of net positions in the underlying commodities.

(b)Notional amounts for options included on a gross basis, but are weighted for the probability of exercise.

Consideration of Credit Risk and Concentrations — PSCo continuously monitors the creditworthiness of the 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. The 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. At Dec. 31, 2020, four of PSCo’s 10 most significant counterparties for these activities, comprising $99 million or 66% of this credit exposure, had investment grade credit ratings from S&P, Moody’s or Fitch Ratings. Four of the 10 most significant counterparties, comprising $19 million or 13% of this credit exposure, were not rated by these external agencies, but based on PSCo’s internal analysis, had credit quality consistent with investment grade. Two of these significant counterparties, comprising $19 million, or 13%, of this credit exposure, had credit quality less than investment grade, based on external and internal analysis. Seven of these significant counterparties are independent system operators, municipal, cooperative electric entities, Regional Transmission Organizations or other utilities.

Qualifying Cash Flow Hedges — Financial impact of qualifying interest rate and vehicle fuel cash flow hedges on PSCo’s accumulated other comprehensive loss, included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income:

(Millions of Dollars)	2020		2019		2018
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(24)	$	(26)	$	(27)
After-tax net realized losses on derivative transactions reclassified into earnings	1		2		1
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(23)	$	(24)	$	(26)

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, 2020
Other derivative instruments
Natural gas commodity	$	—	$	(10)
Total	$	—	$	(10)
Year Ended Dec. 31, 2019
Other derivative instruments
Natural gas commodity	$	—	$	(5)
Total	$	—	$	(5)
Year Ended Dec. 31, 2018
Other derivative instruments
Natural gas commodity	$	—	$	8
Total	$	—	$	8

37

	Pre-Tax (Gains) Losses Reclassified into Income During the Period from:
(Millions of Dollars)	Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)			Pre-Tax Gains (Losses) Recognized During the Period in Income
Year Ended Dec. 31, 2020
Derivatives designated as cash flow hedges
Interest rate	$	1	(a)	$	—		$	—
Total	$	1		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	3	(b)
Natural gas commodity	—			8		(c)	(8)		(c)
Total	$	—		$	8		$	(5)

(a)    Recorded to interest charges.

(b)    Recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.

(c)    Amounts for the year ended Dec. 31, 2020, included no settlement gains or losses on derivatives entered to mitigate natural gas price risk for electric generation recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset or liability, as appropriate. Remaining settlement losses for the years ended Dec. 31, 2020, relate to natural gas operations and are 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 or liability, as appropriate.

	Pre-Tax (Gains) Losses Reclassified into Income During the Period from:
(Millions of Dollars)	Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)			Pre-Tax Gains (Losses) Recognized During the Period in Income
Year Ended Dec. 31, 2019
Derivatives designated as cash flow hedges
Interest rate	$	2	(a)	$	—		$	—
Total	$	2		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	3	(b)
Natural gas commodity	—			1		(c)	(4)		(c)
Total	$	—		$	1		$	(1)

(a)    Recorded to interest charges.

(b)    Recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.

(c)    Amounts for the year ended Dec. 31, 2019, included no settlement gains or losses on derivatives entered to mitigate natural gas price risk for electric generation recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset or liability, as appropriate. Remaining settlement losses for the years ended Dec. 31, 2019, relate to natural gas operations and are 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 or liability, as appropriate.

	Pre-Tax (Gains) Losses Reclassified into Income During the Period from:
(Millions of Dollars)	Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)			Pre-Tax Gains (Losses) Recognized During the Period in Income
Year Ended Dec. 31, 2018
Derivatives designated as cash flow hedges
Interest rate	$	1	(a)	$	—		$	—
Total	$	1		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	3	(b)
Natural gas commodity	—			(4)		(c)	(3)		(c)
Total	$	—		$	(4)		$	—

(a)    Recorded to interest charges.

(b)    Recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.

(c)    Amounts for the year ended Dec. 31, 2018, included $1 million of settlement losses on derivatives entered to mitigate natural gas price risk for electric generation recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset or liability, as appropriate. Remaining settlement losses for the years ended Dec. 31, 2018, relate to natural gas operations and are 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 or liability, as appropriate.

PSCo had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2020, 2019 and 2018. 

Credit Related Contingent Features — Contract provisions for derivative instruments that PSCo enters into, including those accounted for as normal purchase-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. At Dec. 31, 2020 and 2019, there were no derivative instruments in a liability position with such underlying contract provisions. Certain contracts also contain cross default provisions that may require the posting of collateral or settlement of the contracts if there was a failure under the other financing arrangements related to payment terms or other covenants. As of Dec. 31, 2020, there were approximately $46 million of derivative instruments 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, 2020 and 2019.

38

Recurring Fair Value Measurements — PSCo’s derivative assets and liabilities measured at fair value on a recurring basis were as follows:

	Dec. 31, 2020												Dec. 31, 2019
	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	$	41	$	1	$	43	$	(28)	$	15	$	2	$	11	$	1	$	14	$	(10)	$	4
Natural gas commodity	—		6		—		6		—		6		—		3		—		3		—		3
Total current derivative assets	$	1	$	47	$	1	$	49	$	(28)	$	21	$	2	$	14	$	1	$	17	$	(10)	$	7
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	1	$	27	$	8	$	36	$	(20)	$	16	$	1	$	8	$	1	$	10	$	(10)	$	—
Total noncurrent derivative assets	$	1	$	27	$	8	$	36	$	(20)	16		$	1	$	8	$	1	$	10	$	(10)	$	—
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	1	$	46	$	7	$	54	$	(33)	$	21	$	2	$	17	$	—	$	19	$	(13)	$	6
Natural gas commodity	—		6		—		6		—		6		—		3		—		3		—		3
Total current derivative liabilities	$	1	$	52	$	7	$	60	$	(33)	$	27	$	2	$	20	$	—	$	22	$	(13)	$	9
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	1	$	24	$	46	$	71	$	(20)	$	51	$	1	$	47	$	15	$	63	$	(10)	$	53
Total noncurrent derivative liabilities	$	1	$	24	$	46	$	71	$	(20)	$	51	$	1	$	47	$	15	$	63	$	(10)	$	53

(a)PSCo nets derivative instruments and related collateral on its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2020 and 2019. At Dec. 31, 2020 and 2019, derivative assets and liabilities include no obligations to return cash collateral, respectively. At Dec. 31, 2020 and 2019, derivative assets and liabilities include rights to reclaim cash collateral of $5 million and $3 million, respectively. The 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 for the years ended Dec. 31, 2020, 2019 and 2018:

	Year Ended Dec. 31
(Millions of Dollars)	2020		2019		2018
Balance at Jan. 1	$	(13)	$	—	$	—
Settlements	—		(2)		—
Net transactions recorded during the period:
Losses recognized in earnings (a)	(31)		(11)		—
Balance at Dec. 31	$	(44)	$	(13)	$	—

(a)Level 3 losses recognized in earnings are subject to offsetting gains of derivative instruments categorized as levels 1 and 2 in the income statement.

PSCo recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the years ended Dec. 31, 2020, 2019 and 2018.

Fair Value of Long-Term Debt

As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value:

	2020				2019
(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	5,724	$	7,040	$	5,385	$	6,039

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, 2020 and 2019, 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 2.24, 3.11 and 3.86 percent in 2020, 2019, and 2018, 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, 2020 and 2019 were $43 million and $39 million, respectively, of which $2 million and $3 million was attributable to PSCo in 2020 and 2019, respectively. Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $6 million in 2020 and $4 million in 2019, respectively, of which immaterial amounts were attributable to PSCo.

39

Xcel Energy, which includes PSCo, bases the investment-return assumption on expected long-term performance for each of the asset classes in its pension and postretirement health care portfolios. For pension assets, Xcel Energy considers the historical returns achieved by its asset portfolio over the past 20-years or longer period, as well as the long-term return levels projected and recommended by 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 2020 were above the assumed level of 6.84%.

•Investment returns in 2019 were above the assumed level of 6.84%.

•Investment returns in 2018 were below the assumed level of 6.84%.

•In 2021, PSCo’s expected investment-return assumption is 6.38%.

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. PSCo is required to fund postretirement benefit costs in irrevocable external trusts that are dedicated to the payment of these postretirement benefits. These assets are invested in a manner consistent with the investment strategy for the pension plan.

Xcel Energy’s ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios.

Plan Assets

For each of the fair value hierarchy levels, PSCo’s pension plan assets measured at fair value:

	Dec. 31, 2020 (a)										Dec. 31, 2019 (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	$	75	$	—	$	—	$	—	$	75	$	46	$	—	$	—	$	—	$	46
Commingled funds	518		—		—		388		906		497		—		—		355		852
Debt securities	—		270		1		—		271		—		241		2		—		243
Equity securities	27		—		—		—		27		30		—		—		—		30
Other	2		2		—		—		4		(41)		1		—		(7)		(47)
Total	$	622	$	272	$	1	$	388	$	1,283	$	532	$	242	$	2	$	348	$	1,124

(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, 2020 (a)										Dec. 31, 2019 (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	$	24	$	—	$	—	$	—	$	24	$	20	$	—	$	—	$	—	$	20
Insurance contracts	—		45		—		—		45		—		45		—		—		45
Commingled funds	64		—		—		61		125		62		—		—		68		130
Debt securities	—		207		—		—		207		—		203		1		—		204
Other	—		3		—		—		3		—		2		—		—		2
Total	$	88	$	255	$	—	$	61	$	404	$	82	$	250	$	1	$	68	$	401

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

No assets were transferred in or out of Level 3 for 2020. Immaterial assets were transferred in or out of Level 3 for 2019.

40

Funded Status — Benefit obligations for both pension and postretirement plans increased from Dec. 31, 2019 to Dec. 31, 2020, due primarily to decreases in discount rates used in actuarial valuations. Comparisons of the actuarially computed benefit obligation, changes in plan assets and funded status of the pension and postretirement health care plans for PSCo are as follows:

	Pension Benefits				Postretirement Benefits
(Millions of Dollars)	2020		2019		2020		2019
Change in Benefit Obligation:
Obligation at Jan. 1	$	1,330	$	1,229	$	380	$	377
Service cost	30		26		1		1
Interest cost	46		52		13		16
Plan amendments	—		—		—		—
Actuarial loss	102		108		52		12
Plan participants’ contributions	—		—		6		7
Medicare subsidy reimbursements	—		—		1		1
Benefit payments	(80)		(85)		(38)		(34)
Obligation at Dec. 31	$	1,428	$	1,330	$	415	$	380
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	1,124	$	966	$	401	$	372
Actual return on plan assets	189		197		32		52
Employer contributions	50		46		3		4
Plan participants’ contributions	—		—		6		7
Benefit payments	(80)		(85)		(38)		(34)
Fair value of plan assets at Dec. 31	$	1,283	$	1,124	$	404	$	401
Funded status of plans at Dec. 31	$	(145)	$	(206)	$	(11)	$	21
Amounts recognized in the Consolidated Balance Sheet at Dec. 31:
Noncurrent liabilities	(145)		(206)		(11)		21
Net amounts recognized	$	(145)	$	(206)	$	(11)	$	21

Accumulated benefit obligation for the pension plan was $1,353 million and $1,267 million as of Dec. 31, 2020 and 2019, respectively.

	Pension Benefits				Postretirement Benefits
Significant Assumptions Used to Measure Benefit Obligations:	2020		2019		2020		2019
Discount rate for year-end valuation	2.71	%	3.49	%	2.65	%	3.47	%
Expected average long-term increase in compensation level	3.75	%	3.75	%	N/A		N/A
Mortality table	Pri-2012		Pri-2012		Pri-2012		Pri-2012
Health care costs trend rate — initial: Pre-65	N/A		N/A		5.50	%	6.00	%
Health care costs trend rate — initial: Post-65	N/A		N/A		5.00	%	5.10	%
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		5		3

41

Net Periodic Benefit Cost (Credit) — Net periodic benefit cost (credit), other than the service cost component, is included in other (expense) income 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)	2020			2019			2018			2020			2019			2018
Service cost	$	30		$	26		$	29		$	—		$	1		$	1
Interest cost	46			52			47			13			15			15
Expected return on plan assets	(70)			(69)			(69)			(17)			(19)			(23)
Amortization of prior service credit	(3)			(3)			(3)			(4)			(5)			(6)
Amortization of net loss	30			25			31			1			3			4
Settlement charge (a)	—			3			5			—			—			—
Net periodic pension cost (credit)	33			34			40			(7)			(5)			(9)
Effects of regulation	4			4			(4)			3			1			2
Net benefit cost (credit) recognized for financial reporting	$	37		$	38		$	36		$	(4)		$	(4)		$	(7)
Significant Assumptions Used to Measure Costs:
Discount rate	3.49		%	4.31		%	3.63		%	3.47		%	4.32		%	3.62		%
Expected average long-term increase in compensation level	3.75			3.75			3.75			N/A			N/A			N/A
Expected average long-term rate of return on assets	6.84			6.84			6.84			4.50			4.50			5.30

(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 2019 and 2018, as a result of lump-sum distributions during each plan year, PSCo recorded a total pension settlement charge of $3 million and $5 million, respectively. An immaterial amount was recorded in the income statement in 2019 and 2018. There were no settlement charges recorded to the qualified pension plans in 2020.

	Pension Benefits				Postretirement Benefits
(Millions of Dollars)	2020		2019		2020		2019
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	432	$	482	$	81	$	45
Prior service credit	(1)		(4)		(6)		(10)
Total	$	431	$	478	$	75	$	35
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	$	25	$	22	$	—	$	—
Noncurrent regulatory assets	404		452		75		35
Deferred income taxes	1		1		—		—
Net-of-tax accumulated other comprehensive income	1		3		—		—
Total	$	431	$	478	$	75	$	35

Measurement date Dec. 31, 2020 Dec. 31, 2019 Dec. 31, 2020 Dec. 31, 2019

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 2018 — 2021 to meet minimum funding requirements. Total voluntary and required pension funding contributions across all four of Xcel Energy’s pension plans were as follows:

•$125 million in January 2021, of which $45 million was attributable to PSCo.

•$150 million in 2020, of which $50 million was attributable to PSCo.

•$154 million in 2019, of which $46 million was attributable to PSCo.

•$150 million in 2018, of which $22 million was attributable to PSCo.

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:

•$10 million in January 2021, of which an immaterial amount is attributable to PSCo.

•$11 million during 2020, of which $3 million was attributable to PSCo.

•$15 million during 2019, of which $4 million was attributable to PSCo.

•$11 million during 2018, of which $5 million was attributable to PSCo.

42

Targeted asset allocations:

	Pension Benefits				Postretirement Benefits
	2020		2019		2020		2019
Domestic and international equity securities	35	%	37	%	15	%	15	%
Long-duration fixed income securities	35		30		—		—
Short-to-intermediate fixed income securities	13		14		72		72
Alternative investments	15		17		9		9
Cash	2		2		4		4
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 2018, the PSCo postretirement plan was amended to add the 5% cash balance formula.

In 2020 and 2019, there were no significant plan amendments made which affected the projected benefit obligation.

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
2021	$	83	$	31	$	2	$	29
2022	83		31		2		29
2023	82		30		2		28
2024	82		30		2		28
2025	82		29		2		27
2026-2030	393		130		12		118

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 $12 million in 2020 and $11 million in 2019 and 2018.

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 of such matters, including a possible eventual loss. For current proceedings not specifically reported, management does not anticipate that the ultimate liabilities, if any, would have a material effect on PSCo’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.

Gas Trading Litigation — e prime is a wholly owned subsidiary of Xcel Energy. e prime was in the business of natural gas trading and marketing but has not engaged in natural gas trading or marketing activities since 2003. Multiple lawsuits involving multiple plaintiffs seeking monetary damages were commenced against e prime and its affiliates, including Xcel Energy, between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. Cases were all consolidated in the U.S. District Court in Nevada.

Two cases remain active which include an MDL matter consisting of a Colorado purported class (Breckenridge) and a Wisconsin purported class (Arandell Corp.).

Breckenridge/Colorado — In February 2019, the MDL panel remanded Breckenridge back to the U.S. District Court in Colorado. In December 2020, a settlement in principle was reached for approximately $3 million. The parties have sought and are awaiting court approval of settlement.

Arandell Corp. — In February 2019, the case was remanded back to the U.S. District Court in Wisconsin.

Xcel Energy has concluded that a loss is remote for the remaining lawsuit.

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 three MGP, landfill or other disposal sites across its service territory.

PSCo has recognized its best estimate of costs/liabilities that will result from final resolution of these issues, however, the outcome and timing is 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 CCR landfills and surface impoundments. Currently, PSCo has six regulated ash units in operation.

PSCo is conducting groundwater sampling and monitoring and implementing assessment of corrective measures at certain CCR landfills and surface impoundments. Increases above background concentrations were detected at four locations.

43

Subsequently, assessment monitoring samples were collected at these locations. As a result, PSCo is evaluating options for corrective action at two locations, one of which indicates potential offsite impacts to groundwater. Until PSCo completes its assessments, it is uncertain what impact, if any, there will be on the operations, financial condition or cash flows.

In August 2020, the EPA published its final rule to implement a cease receipt and initiate a closure date of April 2021 for all CCR impoundments affected by the August 2018 D.C. Circuit ruling. The D.C. Circuit concluded that the EPA cannot allow utilities to continue to use unlined impoundments (including clay lined impoundments) for the storage or disposal of coal ash. This final rule required Xcel Energy to expedite closure plans for one impoundment.

PSCo is pursuing options to build an alternative bottom ash collection system that will be constructed and in service in advance of the April 11, 2021 deadline. Once the alternative bottom ash system is operational, the existing impoundment will initiate closure per the CCR Rule.

Closure costs for existing impoundments are included in the calculation of the ARO.

Federal CWA WOTUS Rule — In April 2020, the EPA and U.S. Army Corps of Engineers (“Agencies”) replaced the 2015 WOTUS rule and narrowed the definition of WOTUS (“2020 WOTUS Rule”). The new definition simplifies the process whether waters are subject to CWA jurisdiction and streamlines the permitting process.

In June 2020, the U.S. District Court for the District of Colorado stayed the effective date of the 2020 WOTUS Rule in Colorado, where the pre-2015 definition of WOTUS is now in effect. Regardless of which definition is applicable in the states in which we operate, PSCo does not anticipate that compliance costs will be material.

Federal CWA ELG — In 2015, the EPA issued a final ELG rule for power plants that discharge treated effluent to surface waters as well as utility-owned landfills that receive CCRs. In October 2020, the EPA published a final rule revising the regulations.

The retirement of units affected by the final ELG rule is subject to regulatory approval. The exact total cost of ELG compliance is therefore uncertain but PSCo does not anticipate that compliance costs will be material.

Federal CWA Section 316(b) — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing impingement and entrainment of aquatic species. PSCo estimates the likely cost for complying with impingement and entrainment requirements is immaterial. PSCo anticipates these costs will be fully recoverable through regulatory mechanisms.

Environmental Requirements — Air

Regional Haze Rules — The regional haze program requires sulfur dioxide, nitrogen oxide and particulate matter emission controls at power plants to reduce visibility impairment in national parks and wilderness areas. The program includes best available retrofit technology and reasonable further progress. The regional haze first planning period requirements were approved by the EPA and implemented by 2016.

All states are now subject to a second round of regional haze planning/rulemaking, focusing on additional reductions to meet reasonable progress requirements. Any additional impacts to PSCo facilities are expected to be minimal.

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

PSCo’s AROs were as follows:

	2020
(Millions  of Dollars)	Jan. 1, 2020		Amounts Incurred (a)		Amounts Settled (b)		Accretion		Cash Flow Revisions (c)		Dec. 31, 2020
Electric
Steam, hydro and other production	$	100	$	—	$	—	$	4	$	33	$	137
Wind	16		26		(3)		1		—		40
Distribution	14		—		—		1		—		15
Natural gas
Transmission and distribution	190		—		—		8		5		203
Miscellaneous	3		—		—		—		—		3
Common
Miscellaneous	1		—		—		—		—		1
Total liability	$	324	$	26	$	(3)	$	14	$	38	$	399

(a)Amounts incurred related to the Cheyenne Ridge wind farm placed in service in 2020.

(b)Amounts settled related to removal of wind facilities.

(c)In 2020, 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 ash containment facilities.

	2019
(Millions  of Dollars)	Jan. 1, 2019		Accretion		Cash Flow Revisions (a)		Dec. 31, 2019 (b)
Electric
Steam, hydro and other production	$	102	$	5	$	(7)	$	100
Wind	14		1		1		16
Distribution	13		1		—		14
Miscellaneous	3		—		(3)		—
Natural gas
Transmission and distribution	201		9		(20)		190
Miscellaneous	4		—		(1)		3
Common
Miscellaneous	1		—		—		1
Total liability	$	338	$	16	$	(30)	$	324

(a)In 2019, AROs were revised for changes in timing and estimates of cash flows. Changes in gas transmission and distribution AROs were primarily related to increased gas line mileage and number of services, which were more than offset by decreased inflation rates. Revisions in steam, hydro, and other production AROs primarily related to changes in cost estimates for pond remediation.

(b)There were no ARO amounts incurred or settled in 2019.

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, 2020. 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.

44

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 3.9%). 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 minimum lease payments for the purposes of lease accounting and disclosure.

Leases with an initial term of 12 months or less are classified as short-term leases and are not recognized on the consolidated balance sheet.

Operating lease ROU assets:

(Millions of Dollars)	Dec. 31, 2020		Dec. 31, 2019
PPAs	$	591	$	585
Other	68		69
Gross operating lease ROU assets	659		654
Accumulated amortization	(159)		(80)
Net operating lease ROU assets	$	500	$	574

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, 2020		Dec. 31, 2019
Gas storage facilities	$	201	$	200
Gas pipeline	21		21
Gross finance lease ROU assets	222		221
Accumulated amortization	(90)		(82)
Net finance lease ROU assets	$	132	$	139

Components of lease expense:

(Millions of Dollars)	2020		2019		2018
Operating leases
PPA capacity payments	$	100	$	98	$	97
Other operating leases (a)	13		14		14
Total operating lease expense (b)	$	113	$	112	$	111
Finance leases
Amortization of ROU assets	$	7	$	6	$	6
Interest expense on lease liability	18		19		19
Total finance lease expense	$	25	$	25	$	25

(a)Includes short-term lease expense of $1 million, $2 million and $1 million for 2020, 2019 and 2018, respectively.

(b)PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income. Expense for other operating leases is included in O&M expense and electric fuel and purchased power.

Commitments under operating and finance leases as of Dec. 31, 2020:

(Millions of Dollars)	PPA (a) (b) Operating Leases		Other Operating Leases		Total Operating Leases		Finance Leases
2021	$	101	$	15	$	116	$	24
2022	84		15		99		21
2023	70		10		80		20
2024	63		10		73		20
2025	63		5		68		19
Thereafter	163		12		175		381
Total minimum obligation	544		67		611		485
Interest component of obligation	(74)		(8)		(82)		(352)
Present value of minimum obligation	$	470	$	59	529		133
Less current portion					(97)		(7)
Noncurrent operating and finance lease liabilities					$	432	$	126
Weighted-average remaining lease term in years					7.1		38.0

(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 with various expiration dates through 2033 for purchased power to meet system load and energy requirements and operating reserve obligations. In general, these agreements provide for energy payments, based on actual energy delivered and capacity payments. Certain PPAs accounted for as executory contracts contain minimum energy purchase commitments.

Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $10 million, $12 million and $21 million in 2020, 2019 and 2018, 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, 2020, 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
2021	$	3
2022	3
2023	3
2024	3
2025	3
Thereafter	5
Total	$	20

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 2021 and 2060. PSCo is required to pay additional amounts depending on actual quantities shipped under these agreements.

45

Estimated minimum purchases under these contracts as of Dec. 31, 2020:

(Millions of Dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2021	$	132	$	354	$	116
2022	61		119		115
2023	22		54		67
2024	22		3		37
2025	23		—		36
Thereafter	47		—		475
Total	$	307	$	530	$	846

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. 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 it does not have the power to direct the activities that most significantly impact the entities’ economic performance. PSCo had approximately 1,518 MW and 1,442 MW of capacity under long-term PPAs at Dec. 31, 2020 and 2019, 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:

	2020
(Millions of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(24)		$	(3)		$	(27)
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $— and $—, respectively)	1		(a)	—			1
Amortization of net actuarial loss (net of taxes of $— and $1, respectively)	—			2		(b)	2
Net current period other comprehensive income (loss)	1			2			3
Accumulated other comprehensive loss at Dec. 31	$	(23)		$	(1)		$	(24)

(a)Included in interest charges.

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

	2019
(Millions of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(26)		$	—		$	(26)
Losses (gains) reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $— and $—, respectively)	2		(a)	—			2
Amortization of net actuarial gains (net of taxes of $— and $(1), respectively)	—			(3)		(b)	(3)
Net current period other comprehensive income	2			(3)			(1)
Accumulated other comprehensive loss at Dec. 31	$	(24)		$	(3)		$	(27)

(a)Included in interest charges.

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

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 electricity which is transmitted and distributed in Colorado. This segment includes sales for resale and provides wholesale transmission service to various entities in the United States. Regulated electric utility also includes PSCo’s wholesale commodity and trading operations.

•Regulated Natural Gas — The regulated natural gas utility segment transports, stores and distributes 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, and 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.

To report income from operations for regulated electric and regulated natural gas utility segments, the majority of costs are directly assigned to each segment. However, some costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators. A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.

46

PSCo’s segment information:

(Millions of Dollars)	2020		2019		2018
Regulated Electric
Operating revenues - external	$	3,116	$	3,033	$	3,031
Intersegment revenue	1		1		—
Total revenues	$	3,117	$	3,034	$	3,031
Depreciation and amortization	497		455		416
Interest charges and financing costs	173		173		142
Income tax expense	13		45		103
Net income	460		465		429
Regulated Natural Gas
Operating revenues - external	$	1,024	$	1,161	$	1,015
Intersegment revenue	—		—		1
Total revenues	$	1,024	$	1,161	$	1,016
Depreciation and amortization	152		141		140
Interest charges and financing costs	50		50		43
Income tax expense	29		33		13
Net income	126		119		121
All Other
Total revenues (a)	$	43	$	43	$	40
Depreciation and amortization	6		6		5
Interest charges and financing costs	1		1		1
Income tax expense (benefit)	3		2		(3)
Net income (loss)	2		(6)		2
Consolidated Total
Total revenues (a)	$	4,184	$	4,238	$	4,087
Reconciling eliminations	(1)		(1)		(1)
Total operating revenues	$	4,183	$	4,237	$	4,086
Depreciation and amortization	655		602		561
Interest charges and financing costs	224		224		186
Income tax expense	45		80		113
Net income	588		578		552

(a)    Operating revenues include $5 million, $5 million and $4 million of intercompany revenue for the years ended Dec. 31, 2020, 2019 and 2018, 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)	2020		2019		2018
Operating revenues:
Other	$	5	$	5	$	4
Operating expenses:
Other operating expenses — paid to Xcel Energy Services Inc.	571		532		519

Accounts receivable and payable with affiliates at Dec. 31:

	2020				2019
(Millions of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Minnesota	$	—	$	1	$	19	$	—
NSP-Wisconsin	—		1		—		—
SPS	—		6		—		—
Other subsidiaries of Xcel Energy Inc.	8		50		34		44
	$	8	$	58	$	53	$	44

14. Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended
(Millions of Dollars)	March 31, 2020		June 30, 2020		Sept. 30, 2020		Dec. 31, 2020
Operating revenues	$	1,057	$	911	$	1,081	$	1,134
Operating income	196		161		290		176
Net income	129		108		218		133

	Quarter Ended
(Millions of Dollars)	March 31, 2019		June 30, 2019		Sept. 30, 2019		Dec. 31, 2019
Operating revenues	$	1,223	$	910	$	1,044	$	1,060
Operating income	210		163		284		200
Net income	139		102		204		133

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 the 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, 2020, 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.

47

Internal Control Over Financial Reporting

No changes in PSCo’s internal control over financial reporting occurred during the most recent fiscal quarter 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, 2020 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.

PART III

Items 10, 11, 12 and 13 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 2021 Annual Meeting of Shareholders, which is incorporated by reference.

ITEM 14 — PRINCIPAL ACCOUNTANT FEES AND SERVICES

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 Proxy Statement for the 2021 Annual Meeting of Shareholders which is expected to be filed with the SEC on or about April 6, 2021. Such information set forth under such heading is incorporated herein by this reference hereto.

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, 2020.
	Report of Independent Registered Public Accounting Firm — Financial Statements
	Consolidated Statements of Income — For each of the three years ended Dec. 31, 2020, 2019 and 2018.
	Consolidated Statements of Comprehensive Income — For each of the three years ended Dec. 31, 2020, 2019 and 2018.
	Consolidated Statements of Cash Flows — For each of the three years ended Dec. 31, 2020, 2019 and 2018.
	Consolidated Balance Sheets — As of Dec. 31, 2020 and 2019.
	Consolidated Statements of Common Stockholder’s Equity — For each of the three years ended Dec. 31, 2020, 2019 and 2018.
2	Schedule II — Valuation and Qualifying Accounts and Reserves for each of the years ended Dec. 31, 2020, 2019 and 2018.
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 between PSCo and 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)
4.02*	Supplemental Indenture, dated Aug. 1, 2007 between PSCo and U.S. Bank Trust National Association, as successor Trustee, creating $350 million principal amount of 6.25% First Mortgage Bonds, Series due 2037	PSCo Form 8-K dated Aug. 8, 2007	4.01
4.03*	Supplemental Indenture dated as of Aug. 1, 2008 between PSCo and U.S. Bank Trust National Association, as successor Trustee, creating $300 million principal amount of 5.80% First Mortgage Bonds, Series due 2018 and $300 million principal amount of 6.50% First Mortgage Bonds, Series due 2038	PSCo Form 8-K dated Aug. 6, 2008	4.01
4.04*	Supplemental Indenture dated as of Aug. 1, 2011 between PSCo and U.S. Bank National Association, as successor Trustee, creating $250 million principal amount of 4.75% First Mortgage Bonds, Series due 2041	PSCo Form 8-K dated Aug. 9, 2011	4.01
4.05*	Supplemental Indenture dated as of Sept. 1, 2012 between PSCo and U.S. Bank National Association, as successor Trustee, creating $300 million principal amount of 2.25% First Mortgage Bonds, Series due 2022 and $500 million principal amount of 3.60% First Mortgage Bonds, Series due 2042	PSCo Form 8-K dated Sept. 11, 2012	4.01

48

4.06*	Supplemental Indenture dated as of March 1, 2013 between PSCo and U.S. Bank National Association, as successor Trustee, creating $250 million principal amount of 2.50% First Mortgage Bonds, Series due 2023 and $250 million principal amount of 3.95% First Mortgage Bonds, Series due 2043	PSCo Form 8-K dated March 26, 2013	4.01
4.07*	Supplemental Indenture dated as of March 1, 2014 between PSCo and U.S. Bank National Association, as successor Trustee, creating $300 million principal amount of 4.30% First Mortgage Bonds, Series due 2044	PSCo Form 8-K dated March 10, 2014	4.01
4.08*	Supplemental Indenture dated as of May 1, 2015 between PSCo and U.S. Bank National Association, as successor Trustee, creating $250 million principal amount of 2.90% First Mortgage Bonds, Series due 2025	PSCo Form 8-K dated May 12, 2015	4.01
4.09*	Supplemental Indenture dated as of June 1, 2016 between PSCo and U.S. Bank National Association, as successor Trustee, creating $250 million principal amount of 3.55% First Mortgage Bonds, Series due 2046	PSCo Form 8-K dated June 13, 2016	4.01
4.10*	Supplemental Indenture dated as of June 1, 2017 between PSCo and U.S. Bank National Association, as successor Trustee, creating $400 million principal amount of 3.80% First Mortgage Bonds, Series due 2047	PSCo Form 8-K dated June 19, 2017	4.01
4.11*	Supplemental Indenture dated as of June 1, 2018 between PSCo and U.S. Bank National Association, as successor Trustee, creating $350 million principal amount of 3.70% First Mortgage Bonds, Series due 2028, and $350 million principal amount of 4.10% First Mortgage Bonds, Series due 2048	PSCo Form 8-K dated June 21, 2018	4.01
4.12*	Supplemental Indenture dated as of March 1, 2019 between PSCo and U.S. Bank National Association, as successor Trustee, creating $400 million principal amount of 4.05% First Mortgage Bonds, Series due 2049	PSCo Form 8-K dated March 13, 2019	4.01
4.13*	Supplemental Indenture dated as of August 1, 2019 between PSCo and U.S. Bank National Association, as successor Trustee, creating $550 million principal amount of 3.20% First Mortgage Bonds, Series due 2050	PSCo Form 8-K dated August 13, 2019	4.01
4.14*	Supplemental Indenture dated as of May 1, 2020 between PSCo and U.S. Bank National Association, as successor Trustee, creating $375 million principal of 2.70% First Mortgage Bonds, Series No. 35 due 2051 and $375 million principal amount of 1.90% First Mortgage Bonds, Series No. 36 due 2031	PSCo Form 8-K dated May 15, 2020	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. Executive Annual Incentive Plan (as amended and restated effective Feb. 17, 2010)	Xcel Energy Inc. Definitive Proxy Statement dated April 6, 2010	Appendix A
10.10*+	First Amendment to Exhibit 10.09 dated Feb. 20, 2013	Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2013	10.01
10.11*+	Xcel Energy Inc. Executive Annual Incentive Award Plan Form of Restricted Stock Agreement	Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2009	10.08
10.12*+	Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement)	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008	10.07
10.13*+	First Amendment to Exhibit 10.12 effective Nov. 29, 2011	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011	10.17
10.14*+	Second Amendment to Exhibit 10.12 dated May 21, 2013	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2013	10.22
10.15*+	Third Amendment to Exhibit 10.12 dated Sept. 30, 2016	Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2016	10.01
10.16*+	Fourth Amendment to Exhibit 10.12 dated Oct. 23, 2017	Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2017	10.01
10.17*+	Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018	10.34
10.18*+	Form of Terms and Conditions under the Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan for Awards of Restricted Stock Units and/or Performance Share Units	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018	10.35
10.19*+	Form of Xcel Energy Inc. 2015 Omnibus Incentive Award Agreement Terms and Conditions under the Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2019	10.33
10.20*+	Stock Equivalent Plan for Non-Employee Directors of Xcel Energy Inc. as amended and restated effective Feb. 23, 2011	Xcel Energy Inc. Definitive Proxy Statement dated April 5, 2011	Appendix A
10.21*+	Stock Equivalent Program for Non-Employee Directors of Xcel Energy Inc. under the Xcel Energy Inc. 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 8-K dated May 20, 2015	10.02
10.22*+	Summary of Non-Employee Director Compensation, effective as of Sept. 1, 2019	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2020	10.22
10.23*+	Stock Program for Non-Employee Directors of Xcel Energy Inc. as Amended and Restated on Dec. 12, 2017 under the 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018	10.36
10.24*+	Form of Services Agreement between Xcel Energy Services Inc. and utility companies	Xcel Energy Inc. Form U5B dated Nov. 16, 2000	H-1
10.25*	Proposed Settlement Agreement, excerpts, as filed with the CPUC	Xcel Energy Inc. Form 8-K dated Dec. 3, 2004	99.02

49

10.26*	Third Amended and Restated Credit Agreement, dated as of June 7, 2019 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, Wells Fargo Bank, National Association, MUFG Bank, Ltd., and Citibank, N.A., as Documentation Agents	Xcel Energy Inc. Form 8-K dated June 7, 2019	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)	2020		2019		2018
Balance at Jan. 1	$	21	$	21	$	20
Additions charged to costs and expenses	24		17		16
Additions charged to other accounts (a)	4		6		5
Deductions from reserves (b)	(20)		(23)		(20)
Balance at Dec. 31	$	29	$	21	$	21

(a)Recovery of amounts previously written-off.

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

Item 16 — Form 10-K Summary

None.

50

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. 17, 2021	/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/ BEN FOWKE	/s/ ALICE K. JACKSON
Ben Fowke	Alice K. Jackson
Chairman, Chief Executive Officer and Director	President and Director
(Principal Executive Officer)
/s/ BRIAN J. VAN ABEL	/s/ JEFFREY S. SAVAGE
Brian J. Van Abel	Jeffrey S. Savage
Executive Vice President, Chief Financial Officer and Director	Senior Vice President, Controller
(Principal Financial Officer)	(Principal Accounting Officer)
/s/ ROBERT C. FRENZEL
Robert C. Frenzel
Executive Vice President, Chief Operating Officer and Director

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.

51

EX-23.01

Exhibit 23.01

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-224333-02 on Form S-3 of our report dated February 17, 2021, relating to the consolidated 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, 2020.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 17, 2021

EX-31.01

Exhibit 31.01

CERTIFICATION

I, Ben Fowke, 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. 17, 2021

/s/ BEN FOWKE

Ben Fowke

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. 17, 2021

/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, 2020, 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. 17, 2021

/s/ BEN FOWKE

Ben Fowke

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, 2020	Feb. 17, 2021	Jun. 30, 2020
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2020
Document Transition Report	false
Entity File Number	001-03280
Entity Registrant Name	Public Service Company 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	2020
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Public Float			$ 0

XML

Accounting Pronouncements

12 Months Ended

Dec. 31, 2020

Accounting Standards Update and Change in Accounting Principle [Abstract]

Accounting Pronouncements

Recently Adopted

Credit Losses — In 2016, the FASB issued Financial Instruments - Credit Losses, Topic 326 (ASC Topic 326), which changes how entities account for losses on receivables and certain other assets. The guidance requires use of a current expected credit loss model, which may result in earlier recognition of credit losses than under previous accounting standards.

PSCo implemented the guidance using a modified-retrospective approach, recognizing a cumulative effect charge of $1 million (after tax) to retained earnings on Jan. 1, 2020. Other than first-time recognition of an allowance for bad debts on accrued unbilled revenues, the Jan. 1, 2020, adoption of ASC Topic 326 did not have a significant impact on PSCo’s consolidated financial statements.

XML

CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Operating revenues
Electric	$ 3,116	$ 3,033	$ 3,031
Natural gas	1,024	1,161	1,015
Other	43	43	40
Total operating revenues	4,183	4,237	4,086
Operating expenses
Electric fuel and purchased power	1,132	1,083	1,157
Cost of natural gas sold and transported	374	526	428
Cost of sales — steam and other	13	17	15
Operating and maintenance expenses	811	810	788
Demand side management expenses	141	136	142
Depreciation and amortization	655	602	561
Taxes (other than income taxes)	234	206	202
Total operating expenses	3,360	3,380	3,293
Operating income	823	857	793
Other (expense) income, net	(1)	3	2
Allowance for funds used during construction — equity	35	22	56
Interest charges and financing costs
Interest charges — includes other financing costs of $7, $7 and $7, respectively	(238)	(235)	(208)
Allowance for funds used during construction — debt	(14)	(11)	(22)
Total interest charges and financing costs	224	224	186
Income before income taxes	633	658	665
Income tax expense	45	80	113
Net income	$ 588	$ 578	$ 552

XML

CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Other financing costs	$ 7	$ 7	$ 7

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Comprehensive income:
Net income	$ 588	$ 578	$ 552
Pension and retiree medical benefits:
Reclassification of loss (gain) to net income, net of tax of $1, $(1) and $—, respectively	2	(3)	0
Derivative instruments:
Reclassification of loss to net income, net of tax of $—, $— and $—, respectively	1	2	1
Total other comprehensive income (loss)	3	(1)	1
Total comprehensive income	$ 591	$ 577	$ 553

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Statement of Comprehensive Income [Abstract]
Defined Benefit Plan Reclassification Adjustment from AOCI, Tax	$ 1	$ (1)	$ 0
Reclassification Adjustment from AOCI on Derivatives, Tax	$ 0	$ 0	$ 0

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Operating activities
Net income	$ 588.0	$ 578.0	$ 552.0
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	656.0	607.0	566.0
Deferred income taxes	2.0	97.0	24.0
Allowance for equity funds used during construction	(35.0)	(22.0)	(56.0)
Provision for bad debts	24.0	17.0	16.0
Net realized and unrealized hedging and derivative transactions	(14.0)	62.0	(6.0)
Changes in operating assets and liabilities:
Accounts receivable	(51.0)	(22.0)	(43.0)
Accrued unbilled revenues	(5.0)	20.0	(18.0)
Inventories	(27.0)	(27.0)	(20.0)
Prepayments and other	(8.0)	(29.0)	13.0
Accounts payable	(14.0)	(44.0)	69.0
Net regulatory assets and liabilities	58.0	35.0	(15.0)
Other current liabilities	45.0	0.0	(13.0)
Pension and other employee benefit obligations	(41.0)	(47.0)	(44.0)
Other, net	(4.0)	3.0	(17.0)
Net cash provided by operating activities	1,174.0	1,228.0	1,008.0
Investing activities
Utility capital/construction expenditures	(1,671.0)	(1,691.0)	(1,577.0)
Investments in utility money pool arrangement	(122.0)	(641.0)	(634.0)
Repayments from utility money pool arrangement	122.0	641.0	654.0
Net cash used in investing activities	(1,671.0)	(1,691.0)	(1,557.0)
Financing activities
Proceeds from (repayments of) short-term borrowings, net	136.0	(307.0)	307.0
Borrowings under utility money pool arrangement	1,189.0	100.0	780.0
Repayments under utility money pool arrangement	(1,171.0)	(61.0)	(780.0)
Proceeds from issuance of long-term debt	735.0	928.0	691.0
Repayments of long-term debt	(400.0)	(400.0)	(300.0)
Capital contributions from parent	856.0	638.0	252.0
Dividends paid to parent	(831.0)	(457.0)	(375.0)
Net cash provided by financing activities	514.0	441.0	575.0
Net change in cash and cash equivalents	17.0	(22.0)	26.0
Cash and cash equivalents at beginning of period	11.0	33.0	7.0
Cash and cash equivalents at end of period	28.0	11.0	33.0
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(211.0)	(209.0)	(187.0)
Cash paid for income taxes, net	(23.0)	(5.0)	(116.0)
Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions	197.0	234.0	142.0
Inventory transfers to property, plant and equipment	35.0	32.0	37.0
Operating lease right-of-use assets	14.0	654.0	0.0
Allowance for equity funds used during construction	$ 35.0	$ 22.0	$ 56.0

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Current assets
Cash and cash equivalents	$ 28
Accounts receivable, net	342	$ 304
Accounts receivable from affiliates	8	53
Accrued unbilled revenues	298	294
Inventories	189	192
Regulatory assets	121	64
Derivative instruments	21	7
Prepayments and other	82	56
Total current assets	1,089	981
Property, plant and equipment, net	17,470	16,155
Other assets
Regulatory assets	1,059	1,038
Derivative instruments	16	0
Operating lease right-of-use assets	500	574
Other	231	260
Total other assets	1,806	1,872
Total assets	20,365	19,008
Current liabilities
Current portion of long-term debt	0	400
Borrowings under utility money pool arrangement	57	39
Short-term debt	136	0
Accounts payable	452	573
Accounts payable to affiliates	58	44
Regulatory liabilities	100	69
Taxes accrued	251	202
Accrued interest	61	53
Dividends payable to parent	105	112
Derivative instruments	27	9
Operating lease liabilities	97	86
Other	84	99
Total current liabilities	1,428	1,686
Deferred credits and other liabilities
Deferred income taxes	1,897	1,851
Deferred investment tax credits	20	23
Regulatory liabilities	2,337	2,037
Asset retirement obligations	399	324
Derivative instruments	51	53
Customer advances	168	173
Pension and employee benefit obligations	161	212
Operating lease liabilities	432	518
Other	156	150
Total deferred credits and other liabilities	5,621	5,341
Commitments and contingencies
Capitalization
Long-term debt	5,724	4,985
Common stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2020 and Dec. 31, 2019, 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	$ 5,770	$ 4,940
Retained earnings	1,846	2,083
Accumulated other comprehensive loss	(24)	(27)
Total common stockholder's equity	7,592	6,996
Total liabilities and stockholder's equity	$ 20,365	$ 19,008

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, 2017		100
Beginning Balance at Dec. 31, 2017	$ 5,828	$ 0	$ 4,033	$ 1,822	$ (27)
Increase (Decrease) in Stockholder's Equity
Net income	552			552
Total other comprehensive income (loss)	1				1
Common dividends declared to parent	(391)			(391)
Contribution of capital by parent	308		308
Balance (in shares) at Dec. 31, 2018		100
Ending Balance at Dec. 31, 2018	6,298	$ 0	4,341	1,983	(26)
Increase (Decrease) in Stockholder's Equity
Net income	578			578
Total other comprehensive income (loss)	(1)				(1)
Common dividends declared to parent	(478)			(478)
Contribution of capital by parent	$ 599		599
Balance (in shares) at Dec. 31, 2019	100	100
Ending Balance at Dec. 31, 2019	$ 6,996	$ 0	4,940	2,083	(27)
Increase (Decrease) in Stockholder's Equity
Net income	588			588
Total other comprehensive income (loss)	3				3
Common dividends declared to parent	(824)			(824)
Contribution of capital by parent	830		830
Adoption of ASC Topic 326	$ (1)			(1)
Balance (in shares) at Dec. 31, 2020	100	100
Ending Balance at Dec. 31, 2020	$ 7,592	$ 0	$ 5,770	$ 1,846	$ (24)

XML

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2020

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

General — PSCo is engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and in 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 the 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 various state regulatory commissions. Certain amounts in the consolidated financial statements or notes have been reclassified for comparative purposes; however, such reclassifications did not affect net income, total assets, liabilities, equity or cash flows.

PSCo has evaluated events occurring after Dec. 31, 2020 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 in recording transactions and balances resulting from business operations. Estimates are used on 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 of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. 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 from its balance sheet. 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 financial statements. PSCo defers income taxes for all temporary differences between pretax financial and taxable income and between the book and tax bases of assets and liabilities. PSCo uses rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the period that includes the enactment date.

The effects of 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, which would be refundable to utility customers over the remaining life of the related assets. PSCo anticipates that a tax rate increase would result in the establishment of a regulatory asset, subject to regulatory approval.

Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of regulatory assets and liabilities related to income taxes. 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.

PSCo follows the applicable accounting guidance to measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns. PSCo recognizes a tax position in its 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.

PSCo reports interest and penalties related to income taxes within other (expense) income 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 are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property.

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.

PSCo records depreciation expense using the straight-line method over the plant’s 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 recovered in rates as authorized by the appropriate regulatory entities. The amount of removal costs are based on current factors used in existing depreciation rates. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.1% in 2020, 2.9% in 2019 and 2.6% in 2018.

See Note 3 for further information.

AROs — PSCo accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement 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 depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount 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 liability 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. If an environmental expense is related to facilities currently in use, such as 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 proceeds. 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. 

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

See Note 10 for further information.

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

PSCo does not recognize a separate financing component of its collections from customers as contract terms are short-term in nature. PSCo presents its revenues net of any excise or sales taxes or fees.

See Note 6 for further information.

Cash and Cash Equivalents — PSCo considers investments in instruments with a remaining maturity of three 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, 2020 and 2019, the allowance for bad debts was $29 million and $21 million, respectively.

Inventory — Inventory is recorded at average cost and consisted of the following:

(Millions of Dollars)	Dec. 31, 2020		Dec. 31, 2019
Inventories
Materials and supplies	$	63	$	63
Fuel	73		77
Natural gas	53		52
Total inventories	$	189	$	192

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

Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted NAVs. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used to establish 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, PSCo may use quoted prices for similar contracts or internally prepared valuation models to determine fair value. 

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

See Notes 8 and 9 for further information.

Derivative Instruments — PSCo uses derivative instruments in connection with its interest rate, utility commodity price and commodity trading activities, including forward contracts, futures, swaps and options. Any derivative instruments not qualifying for the normal purchases and normal sales exception are recorded on the consolidated balance sheets at fair value as derivative instruments. Classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues and interest rate hedging transactions are recorded as a component of interest expense. 

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 a derivative exists and/or whether an instrument may be exempted from derivative accounting if designated as a normal purchase or normal sale.

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. AFUDC 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 for establishing utility rates.

Alternative Revenue — Certain rate rider mechanisms (including decoupling and DSM programs) qualify as alternative revenue programs. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate. When certain criteria are met, including expected collection within 24 months, revenue is recognized equal to the revenue requirement, which may include incentives and return on rate base items. Billing amounts are revised periodically for differences between total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers.

See Note 6 for further information.

Conservation Programs — 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 annual period 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 — Emission allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emission allowances and sales of these allowances are included in electric revenues.

RECs — Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. PSCo records that cost as a regulatory asset when the amount is recoverable in future rates.

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

XML

Property Plant and Equipment Property Plant and Equipment

12 Months Ended

Dec. 31, 2020

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment Disclosure

Major classes of property, plant and equipment

(Millions of Dollars)	Dec. 31, 2020		Dec. 31, 2019
Property, plant and equipment, net
Electric plant	$	15,736	$	14,362
Natural gas plant	5,037		4,631
Common and other property	1,191		1,113
Plant to be retired (a)	225		260
CWIP	510		913
Total property, plant and equipment	22,699		21,279
Less accumulated depreciation	(5,229)		(5,124)
Property, plant and equipment, net	$	17,470	$	16,155

(a)Includes regulator-approved retirements of Comanche Units 1 and 2 and jointly owned Craig Unit 1. Also includes PSCo’s planned retirement of jointly owned Craig Unit 2.

Joint Ownership of Generation, Transmission and Gas Facilities

Jointly owned assets as of Dec. 31, 2020:

(Millions of Dollars, Except Percent Owned)	Plant in Service		Accumulated Depreciation		CWIP		Percent Owned
Electric generation:
Hayden Unit 1	$	153	$	92	$	—	76	%
Hayden Unit 2	150		73		—		37
Hayden common facilities	42		25		—		53
Craig Units 1 and 2	81		44		—		10
Craig common facilities	39		24		—		7
Comanche Unit 3	899		137		16		67
Comanche common facilities	25		2		—		82
Electric transmission:
Transmission and other facilities	176		59		2		Various
Gas transmission:
Rifle, CO to Avon, CO	22		8		—		60
Gas transmission compressor	8		1		—		50
Total	$	1,595	$	465	$	18

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.

XML

Regulatory Assets and Liabilities

12 Months Ended

Dec. 31, 2020

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, 2020				Dec. 31, 2019
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Pension and retiree medical obligations	9	Various	$	28	$	478	$	23	$	494
Depreciation differences		One to 11 years	16		154		15		140
Net AROs (a)	1, 10	Various	—		132		—		119
Recoverable deferred taxes on AFUDC		Plant lives	—		110		—		105
Excess deferred taxes — TCJA	7	Various	3		56		3		55
Purchased power contract costs		Term of related contract	3		22		2		24
Property tax		Various	16		21		1		30
Conservation programs (b)	1	One to two years	11		11		8		11
Gas pipeline inspection costs		One to two years	—		9		—		8
Losses on reacquired debt		Term of related debt	1		3		1		4
Contract valuation adjustments (c)	1, 8	Term of related contract	6		—		3		—
Recoverable purchased natural gas and electric energy costs		Less than one year	6		—		—		—
Other		Various	31		63		8		48
Total regulatory assets			$	121	$	1,059	$	64	$	1,038

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

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

(c)Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.

Components of regulatory liabilities:

(Millions of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2020				Dec. 31, 2019
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Deferred income tax adjustments and TCJA refunds (a)	7	Various	$	5	$	1,368	$	5	$	1,403
Plant removal costs	1, 10	Various	—		615		—		351
Effects of regulation on employee benefit costs (b)		Various	—		203		—		183
Renewable resources and environmental initiatives		Various	—		59		—		45
Revenue decoupling		One to two years	10		41		—		—
ITC deferrals	1	Various	—		40		—		26
Conservation programs (c)	1	Less than one year	39		—		30		—
Deferred electric, natural gas and steam production costs		Less than one year	17		—		8		—
Other		Various	29		11		26		29
Total regulatory liabilities			$	100	$	2,337	$	69	$	2,037

(a)Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA.

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

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

At Dec. 31, 2020 and 2019, PSCo’s regulatory assets not earning a return primarily included the unfunded portion of pension and retiree medical obligations and net AROs. In addition, PSCo’s regulatory assets included $195 million and $160 million at Dec. 31, 2020 and 2019, respectively, of past expenditures not earning a return. Amounts are related to funded pension obligations, property taxes, various renewable resources and certain environmental initiatives.

XML

Borrowings and Other Financing Instruments

12 Months Ended

Dec. 31, 2020

Debt Disclosure [Abstract]

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 for PSCo were as follows:

(Millions of Dollars, Except Interest Rates)	Three Months Ended Dec. 31, 2020			Year Ended Dec. 31
				2020			2019			2018
Borrowing limit	$	250		$	250		$	250		$	250
Amount outstanding at period end	57			57			39			—
Average amount outstanding	104			59			7			25
Maximum amount outstanding	218			250			50			156
Weighted average interest rate, computed on a daily basis	0.08		%	0.60		%	2.29		%	1.93		%
Weighted average interest rate at end of period	0.07			0.07			1.63			N/A

Commercial Paper — Commercial paper borrowings for PSCo were as follows:

(Millions of Dollars, Except Interest Rates)	Three Months Ended Dec. 31, 2020			Year Ended Dec. 31
				2020			2019			2018
Borrowing limit	$	700		$	700		$	700		$	700
Amount outstanding at period end	136			136			—			307
Average amount outstanding	8			30			154			55
Maximum amount outstanding	136			230			432			309
Weighted average interest rate, computed on a daily basis	0.19		%	1.59		%	2.67		%	2.28		%
Weighted average interest rate at end of period	0.20			0.20			N/A			2.95

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, 2020 and 2019, there were $8 million and $9 million of letters of credit outstanding under the credit facility, respectively. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

Credit Facility — In order to use 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.

Amended Credit Agreement — In June 2019, PSCo entered into an amended five-year credit agreement with a syndicate of banks. The amended credit agreement has substantially the same terms and conditions as the prior credit agreement with the exception of the maturity, which is June 2024.

Features of PSCo’s credit facility:

Debt-to-Total Capitalization Ratio (a)				Amount Facility May Be Increased (millions)		Additional Periods for Which a One-Year Extension May Be Requested (b)
2020		2019
44	%	44	%	$	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, 2020, PSCo was in compliance with all financial covenants.

PSCO had the following committed credit facility available as of Dec. 31, 2020 (millions):

Credit Facility (a)		Drawn (b)		Available
$	700	$	144	$	556

(a)This credit facility matures in June 2024.

(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, 2020 and 2019.

Long-Term Borrowings and Other Financing Instruments

Generally, property of PSCo is subject to the liens of its first mortgage indenture. 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 (millions of dollars):

Financing Instrument	Interest Rate	Maturity Date	2020		2019
First mortgage bonds	3.20	Nov. 15, 2020	—		400
First mortgage bonds	2.25	Sept. 15, 2022	300		300
First mortgage bonds	2.50	March 15, 2023	250		250
First mortgage bonds	2.90	May 15, 2025	250		250
First mortgage bonds	3.70	June 15, 2028	350		350
First mortgage bonds (a)	1.90	Jan. 15, 2031	375		—
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 (b)	4.05	Sept. 15, 2049	400		400
First mortgage bonds (b)	3.20	March 1, 2050	550		550
First mortgage bonds (a)	2.70	Jan. 15, 2051	375		—
Unamortized discount			(30)		(24)
Unamortized debt issuance cost			(46)		(41)
Current maturities			—		(400)
Total long-term debt			$	5,724	$	4,985

(a)2020 financing.

(b)2019 financing.

Maturities of long-term debt:

(Millions of Dollars)
2021	$	—
2022	300
2023	250
2024	—
2025	250

Deferred Financing Costs — Deferred financing costs of approximately $46 million and $41 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt as of Dec. 31, 2020 and 2019, respectively. PSCo is amortizing these financing costs over the remaining maturity periods of the related debt.

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

Preferred Stock Authorized (Shares)	Par Value of Preferred Stock		Preferred Stock Outstanding (Shares) 2020 and 2019
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.

XML

Revenues

12 Months Ended

Dec. 31, 2020

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, 2020
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	1,073	$	650	$	12	$	1,735
C&I	1,512		225		27		1,764
Other	48		—		—		48
Total retail	2,633		875		39		3,547
Wholesale	212		—		—		212
Transmission	62		—		—		62
Other	56		125		—		181
Total revenue from contracts with customers	2,963		1,000		39		4,002
Alternative revenue and other	153		24		4		181
Total revenues	$	3,116	$	1,024	$	43	$	4,183

	Year Ended Dec. 31, 2019
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	1,006	$	750	$	11	$	1,767
C&I	1,579		281		28		1,888
Other	50		—		—		50
Total retail	2,635		1,031		39		3,705
Wholesale	166		—		—		166
Transmission	52		—		—		52
Other	32		107		—		139
Total revenue from contracts with customers	2,885		1,138		39		4,062
Alternative revenue and other	148		23		4		175
Total revenues	$	3,033	$	1,161	$	43	$	4,237

	Year Ended Dec. 31, 2018
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	991	$	606	$	11	$	1,608
C&I	1,560		224		25		1,809
Other	48		—		—		48
Total retail	2,599		830		36		3,465
Wholesale	175		—		—		175
Transmission	54		—		—		54
Other	55		84		—		139
Total revenue from contracts with customers	2,883		914		36		3,833
Alternative revenue and other	148		101		4		253
Total revenues	$	3,031	$	1,015	$	40	$	4,086

XML

Income Taxes Income Taxes

12 Months Ended

Dec. 31, 2020

Income Tax Disclosure [Abstract]

Income Taxes

Federal Tax Loss Carryback Claims — In 2020, Xcel Energy identified certain expenses related to tax years 2009 - 2011 that qualify for an extended carryback claim. PSCo is not expected to accrue any income tax expense related to this adjustment.

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

Tax Year(s)	Expiration
2014 - 2016	July 2021

Additionally, the statute of limitations related to the federal tax loss carryback claim referenced above has been extended. Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is unknown.

In 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s NOL and ETR. Xcel Energy filed a protest with the IRS. In April 2020, Xcel Energy and Appeals reached an agreement and no material adjustments were required.

In 2018, the IRS began an audit of tax years 2014 - 2016. In July 2020, Xcel Energy and the IRS reached an agreement and the related benefit was recognized.

State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2020, PSCo’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. There are currently no state income tax audits in progress.

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

Unrecognized tax benefits - permanent vs temporary:

(Millions of Dollars)	Dec. 31, 2020		Dec. 31, 2019
Unrecognized tax benefit — Permanent tax positions	$	7	$	7
Unrecognized tax benefit — Temporary tax positions	2		5
Total unrecognized tax benefit	$	9	$	12

Changes in unrecognized tax benefits:

(Millions of Dollars)	2020		2019		2018
Balance at Jan. 1	$	12	$	10	$	10
Additions based on tax positions related to the current year	2		1		1
Additions for tax positions of prior years	6		1		—
Reductions for tax positions of prior years	(11)		—		—
Settlements with taxing authorities	—		—		(1)
Balance at Dec. 31	$	9	$	12	$	10

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

(Millions of Dollars)	Dec. 31, 2020		Dec. 31, 2019
NOL and tax credit carryforwards	$	(8)	$	(8)

Net deferred tax liability associated with the unrecognized tax benefit amounts and related NOLs and tax credits carryforwards were $6 million and $5 million for Dec. 31, 2020 and Dec. 31, 2019, respectively.

As the IRS and state audits resume, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $3 million in the next 12 months.

Payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards.

Interest payable related to unrecognized tax benefits:

(Millions of Dollars)	2020		2019		2018
Payable for interest related to unrecognized tax benefits at Jan. 1	$	(1)	$	(1)	$	—
Interest income (expense) related to unrecognized tax benefits	1		—		(1)
Payable for interest related to unrecognized tax benefits at Dec. 31	$	—	$	(1)	$	(1)

No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2020, 2019 or 2018.

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)	2020		2019
Federal tax credit carryforwards	$	143	$	83
State NOL carryforwards	190		388
State tax credit carryforwards, net of federal detriment (a)	18		18
Valuation allowances for state credit carryforwards, net of federal benefit (b)	(8)		(8)

(a)State tax credit carryforwards are net of federal detriment of $5 million as of both Dec. 31, 2020 and 2019.

(b)Valuation allowances for state tax credit carryforwards were net of federal benefit of $2 million as of both Dec. 31, 2020 and 2019.

Federal carryforward periods expire between 2031 and 2040 and state carryforward periods expire between 2021 and 2033.

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:

	2020		2019		2018
Federal statutory rate	21.0	%	21.0	%	21.0	%
State income tax on pretax income, net of federal tax effect	3.6		3.6		3.7
Increases (decreases) in tax from:
Wind PTCs	(10.3)		(7.5)		(0.6)
Plant regulatory differences (a)	(5.0)		(3.3)		(4.5)
Other tax credits, net NOL & tax credit allowances	(1.1)		(1.3)		(0.6)
Amortization of excess nonplant deferred taxes	(0.2)		(0.2)		(1.4)
Change in unrecognized tax benefits	(0.2)		0.3		0.1
Other, net	(0.7)		(0.4)		(0.7)
Effective income tax rate	7.1	%	12.2	%	17.0	%

.(a) Regulatory differences for income tax primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit of excess deferred credits are offset by corresponding revenue reductions and additional prepaid pension asset amortization.

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

(Millions of Dollars)	2020		2019		2018
Current federal tax expense (benefit)	$	44	$	(9)	$	79
Current state tax expense (benefit)	4		(5)		14
Current change in unrecognized tax benefit	(3)		(1)		(1)
Deferred federal tax (benefit) expense	(26)		61		5
Deferred state tax expense	26		33		17
Deferred change in unrecognized tax expense	2		3		2
Deferred ITCs	(2)		(2)		(3)
Total income tax expense	$	45	$	80	$	113

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

(Millions of Dollars)	2020		2019		2018
Deferred tax expense excluding items below	$	46	$	132	$	75
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(43)		(35)		(51)
Tax expense allocated to other comprehensive income, adoption of ASC Topic 326, adoption of ASU No. 2018-02, and other	(1)		—		—
Deferred tax expense	$	2	$	97	$	24

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

(Millions of Dollars)	2020		2019 (a)
Deferred tax liabilities:
Differences between book and tax bases of property	$	2,132	$	2,039
Regulatory assets	257		253
Operating lease assets	129		148
Pension expense and other employee benefits	19		22
Other	6		7
Total deferred tax liabilities	$	2,543	$	2,469
Deferred tax assets:
Regulatory liabilities	$	319	$	327
Tax credit carryforward	161		101
Operating lease liabilities	129		148
Bad debts	8		5
NOL carryforward	7		14
Deferred ITCs	5		6
Tax credit valuation allowances	(8)		(8)
Other	25		25
Total deferred tax assets	$	646	$	618
Net deferred tax liability	$	1,897	$	1,851

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

XML

Fair Value of Financial Assets and Liabilities

12 Months Ended

Dec. 31, 2020

Fair Value Disclosures [Abstract]

Fair Value of Financial Assets and Liabilities

Fair Value Measurements

Accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. 

•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 highly liquid and actively traded instruments with quoted prices.

•Level 2 — Pricing inputs are other than quoted 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 are those valued with models requiring significant management judgment or estimation.

Specific valuation methods include:

Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted net asset value.

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

Commodity derivatives — The 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 contractual settlements relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of forward prices and volatilities on a valuation is evaluated and may result in Level 3 classification.

Derivative Instruments 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, utility commodity prices and vehicle fuel prices.

Interest Rate Derivatives — PSCo enters into various instruments that effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes, with changes in fair value prior to settlement recorded as other comprehensive income.

As of Dec. 31, 2020, accumulated other comprehensive loss related to settled 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, including forecasted amounts for unsettled hedges, as applicable.

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 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 activities governed by this policy.

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, as well as for trading purposes. 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.

PSCo enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but may not be designated as qualifying hedging transactions. The classification as a regulatory asset or liability, if applicable, is based on approved regulatory recovery mechanisms.

As of Dec. 31, 2020, PSCo had no commodity contracts designated as cash flow hedges.

PSCo enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of amounts credited to customers under margin-sharing mechanisms.

Gross notional amounts of commodity forwards and options:

(Amounts in Millions) (a)(b)	Dec. 31, 2020	Dec. 31, 2019
MWh of electricity	17	9
MMBtu of natural gas	93	32

(a)Not reflective of net positions in the underlying commodities.

(b)Notional amounts for options included on a gross basis, but are weighted for the probability of exercise.

Consideration of Credit Risk and Concentrations — PSCo continuously monitors the creditworthiness of the 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. The 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. At Dec. 31, 2020, four of PSCo’s 10 most significant counterparties for these activities, comprising $99 million or 66% of this credit exposure, had investment grade credit ratings from S&P, Moody’s or Fitch Ratings. Four of the 10 most significant counterparties, comprising $19 million or 13% of this credit exposure, were not rated by these external agencies, but based on PSCo’s internal analysis, had credit quality consistent with investment grade. Two of these significant counterparties, comprising $19 million, or 13%, of this credit exposure, had credit quality less than investment grade, based on external and internal analysis. Seven of these significant counterparties are independent system operators, municipal, cooperative electric entities, Regional Transmission Organizations or other utilities.

Qualifying Cash Flow Hedges — Financial impact of qualifying interest rate and vehicle fuel cash flow hedges on PSCo’s accumulated other comprehensive loss, included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income:

(Millions of Dollars)	2020		2019		2018
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(24)	$	(26)	$	(27)
After-tax net realized losses on derivative transactions reclassified into earnings	1		2		1
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(23)	$	(24)	$	(26)

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, 2020
Other derivative instruments
Natural gas commodity	$	—	$	(10)
Total	$	—	$	(10)
Year Ended Dec. 31, 2019
Other derivative instruments
Natural gas commodity	$	—	$	(5)
Total	$	—	$	(5)
Year Ended Dec. 31, 2018
Other derivative instruments
Natural gas commodity	$	—	$	8
Total	$	—	$	8

	Pre-Tax (Gains) Losses Reclassified into Income During the Period from:
(Millions of Dollars)	Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)			Pre-Tax Gains (Losses) Recognized During the Period in Income
Year Ended Dec. 31, 2020
Derivatives designated as cash flow hedges
Interest rate	$	1	(a)	$	—		$	—
Total	$	1		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	3	(b)
Natural gas commodity	—			8		(c)	(8)		(c)
Total	$	—		$	8		$	(5)

(a)    Recorded to interest charges.

(b)    Recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.

(c)    Amounts for the year ended Dec. 31, 2020, included no settlement gains or losses on derivatives entered to mitigate natural gas price risk for electric generation recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset or liability, as appropriate. Remaining settlement losses for the years ended Dec. 31, 2020, relate to natural gas operations and are 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 or liability, as appropriate.

	Pre-Tax (Gains) Losses Reclassified into Income During the Period from:
(Millions of Dollars)	Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)			Pre-Tax Gains (Losses) Recognized During the Period in Income
Year Ended Dec. 31, 2019
Derivatives designated as cash flow hedges
Interest rate	$	2	(a)	$	—		$	—
Total	$	2		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	3	(b)
Natural gas commodity	—			1		(c)	(4)		(c)
Total	$	—		$	1		$	(1)

(a)    Recorded to interest charges.

(b)    Recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.

(c)    Amounts for the year ended Dec. 31, 2019, included no settlement gains or losses on derivatives entered to mitigate natural gas price risk for electric generation recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset or liability, as appropriate. Remaining settlement losses for the years ended Dec. 31, 2019, relate to natural gas operations and are 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 or liability, as appropriate.

	Pre-Tax (Gains) Losses Reclassified into Income During the Period from:
(Millions of Dollars)	Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)			Pre-Tax Gains (Losses) Recognized During the Period in Income
Year Ended Dec. 31, 2018
Derivatives designated as cash flow hedges
Interest rate	$	1	(a)	$	—		$	—
Total	$	1		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	3	(b)
Natural gas commodity	—			(4)		(c)	(3)		(c)
Total	$	—		$	(4)		$	—

(a)    Recorded to interest charges.

(b)    Recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.

(c)    Amounts for the year ended Dec. 31, 2018, included $1 million of settlement losses on derivatives entered to mitigate natural gas price risk for electric generation recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset or liability, as appropriate. Remaining settlement losses for the years ended Dec. 31, 2018, relate to natural gas operations and are 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 or liability, as appropriate.

PSCo had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2020, 2019 and 2018. 

Credit Related Contingent Features — Contract provisions for derivative instruments that PSCo enters into, including those accounted for as normal purchase-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. At Dec. 31, 2020 and 2019, there were no derivative instruments in a liability position with such underlying contract provisions. Certain contracts also contain cross default provisions that may require the posting of collateral or settlement of the contracts if there was a failure under the other financing arrangements related to payment terms or other covenants. As of Dec. 31, 2020, there were approximately $46 million of derivative instruments 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, 2020 and 2019.

Recurring Fair Value Measurements — PSCo’s derivative assets and liabilities measured at fair value on a recurring basis were as follows:

	Dec. 31, 2020												Dec. 31, 2019
	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	$	41	$	1	$	43	$	(28)	$	15	$	2	$	11	$	1	$	14	$	(10)	$	4
Natural gas commodity	—		6		—		6		—		6		—		3		—		3		—		3
Total current derivative assets	$	1	$	47	$	1	$	49	$	(28)	$	21	$	2	$	14	$	1	$	17	$	(10)	$	7
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	1	$	27	$	8	$	36	$	(20)	$	16	$	1	$	8	$	1	$	10	$	(10)	$	—
Total noncurrent derivative assets	$	1	$	27	$	8	$	36	$	(20)	16		$	1	$	8	$	1	$	10	$	(10)	$	—
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	1	$	46	$	7	$	54	$	(33)	$	21	$	2	$	17	$	—	$	19	$	(13)	$	6
Natural gas commodity	—		6		—		6		—		6		—		3		—		3		—		3
Total current derivative liabilities	$	1	$	52	$	7	$	60	$	(33)	$	27	$	2	$	20	$	—	$	22	$	(13)	$	9
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	1	$	24	$	46	$	71	$	(20)	$	51	$	1	$	47	$	15	$	63	$	(10)	$	53
Total noncurrent derivative liabilities	$	1	$	24	$	46	$	71	$	(20)	$	51	$	1	$	47	$	15	$	63	$	(10)	$	53

(a)PSCo nets derivative instruments and related collateral on its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2020 and 2019. At Dec. 31, 2020 and 2019, derivative assets and liabilities include no obligations to return cash collateral, respectively. At Dec. 31, 2020 and 2019, derivative assets and liabilities include rights to reclaim cash collateral of $5 million and $3 million, respectively. The 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 for the years ended Dec. 31, 2020, 2019 and 2018:

	Year Ended Dec. 31
(Millions of Dollars)	2020		2019		2018
Balance at Jan. 1	$	(13)	$	—	$	—
Settlements	—		(2)		—
Net transactions recorded during the period:
Losses recognized in earnings (a)	(31)		(11)		—
Balance at Dec. 31	$	(44)	$	(13)	$	—

(a)Level 3 losses recognized in earnings are subject to offsetting gains of derivative instruments categorized as levels 1 and 2 in the income statement.

PSCo recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the years ended Dec. 31, 2020, 2019 and 2018.

Fair Value of Long-Term Debt

As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value:

	2020				2019
(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	5,724	$	7,040	$	5,385	$	6,039

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, 2020 and 2019, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.

XML

Benefit Plans and Other Postretirement Benefits

12 Months Ended

Dec. 31, 2020

Retirement Benefits [Abstract]

Benefit Plans and Other Postretirement Benefits

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 2.24, 3.11 and 3.86 percent in 2020, 2019, and 2018, 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, 2020 and 2019 were $43 million and $39 million, respectively, of which $2 million and $3 million was attributable to PSCo in 2020 and 2019, respectively. Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $6 million in 2020 and $4 million in 2019, respectively, of which immaterial amounts were attributable to PSCo.

Xcel Energy, which includes PSCo, bases the investment-return assumption on expected long-term performance for each of the asset classes in its pension and postretirement health care portfolios. For pension assets, Xcel Energy considers the historical returns achieved by its asset portfolio over the past 20-years or longer period, as well as the long-term return levels projected and recommended by 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 2020 were above the assumed level of 6.84%.

•Investment returns in 2019 were above the assumed level of 6.84%.

•Investment returns in 2018 were below the assumed level of 6.84%.

•In 2021, PSCo’s expected investment-return assumption is 6.38%.

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. PSCo is required to fund postretirement benefit costs in irrevocable external trusts that are dedicated to the payment of these postretirement benefits. These assets are invested in a manner consistent with the investment strategy for the pension plan.

Xcel Energy’s ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios.

Plan Assets

For each of the fair value hierarchy levels, PSCo’s pension plan assets measured at fair value:

	Dec. 31, 2020 (a)										Dec. 31, 2019 (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	$	75	$	—	$	—	$	—	$	75	$	46	$	—	$	—	$	—	$	46
Commingled funds	518		—		—		388		906		497		—		—		355		852
Debt securities	—		270		1		—		271		—		241		2		—		243
Equity securities	27		—		—		—		27		30		—		—		—		30
Other	2		2		—		—		4		(41)		1		—		(7)		(47)
Total	$	622	$	272	$	1	$	388	$	1,283	$	532	$	242	$	2	$	348	$	1,124

(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, 2020 (a)										Dec. 31, 2019 (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	$	24	$	—	$	—	$	—	$	24	$	20	$	—	$	—	$	—	$	20
Insurance contracts	—		45		—		—		45		—		45		—		—		45
Commingled funds	64		—		—		61		125		62		—		—		68		130
Debt securities	—		207		—		—		207		—		203		1		—		204
Other	—		3		—		—		3		—		2		—		—		2
Total	$	88	$	255	$	—	$	61	$	404	$	82	$	250	$	1	$	68	$	401

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

No assets were transferred in or out of Level 3 for 2020. Immaterial assets were transferred in or out of Level 3 for 2019.

Funded Status — Benefit obligations for both pension and postretirement plans increased from Dec. 31, 2019 to Dec. 31, 2020, due primarily to decreases in discount rates used in actuarial valuations. Comparisons of the actuarially computed benefit obligation, changes in plan assets and funded status of the pension and postretirement health care plans for PSCo are as follows:

	Pension Benefits				Postretirement Benefits
(Millions of Dollars)	2020		2019		2020		2019
Change in Benefit Obligation:
Obligation at Jan. 1	$	1,330	$	1,229	$	380	$	377
Service cost	30		26		1		1
Interest cost	46		52		13		16
Plan amendments	—		—		—		—
Actuarial loss	102		108		52		12
Plan participants’ contributions	—		—		6		7
Medicare subsidy reimbursements	—		—		1		1
Benefit payments	(80)		(85)		(38)		(34)
Obligation at Dec. 31	$	1,428	$	1,330	$	415	$	380
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	1,124	$	966	$	401	$	372
Actual return on plan assets	189		197		32		52
Employer contributions	50		46		3		4
Plan participants’ contributions	—		—		6		7
Benefit payments	(80)		(85)		(38)		(34)
Fair value of plan assets at Dec. 31	$	1,283	$	1,124	$	404	$	401
Funded status of plans at Dec. 31	$	(145)	$	(206)	$	(11)	$	21
Amounts recognized in the Consolidated Balance Sheet at Dec. 31:
Noncurrent liabilities	(145)		(206)		(11)		21
Net amounts recognized	$	(145)	$	(206)	$	(11)	$	21

Accumulated benefit obligation for the pension plan was $1,353 million and $1,267 million as of Dec. 31, 2020 and 2019, respectively.

	Pension Benefits				Postretirement Benefits
Significant Assumptions Used to Measure Benefit Obligations:	2020		2019		2020		2019
Discount rate for year-end valuation	2.71	%	3.49	%	2.65	%	3.47	%
Expected average long-term increase in compensation level	3.75	%	3.75	%	N/A		N/A
Mortality table	Pri-2012		Pri-2012		Pri-2012		Pri-2012
Health care costs trend rate — initial: Pre-65	N/A		N/A		5.50	%	6.00	%
Health care costs trend rate — initial: Post-65	N/A		N/A		5.00	%	5.10	%
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		5		3

Net Periodic Benefit Cost (Credit) — Net periodic benefit cost (credit), other than the service cost component, is included in other (expense) income 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)	2020			2019			2018			2020			2019			2018
Service cost	$	30		$	26		$	29		$	—		$	1		$	1
Interest cost	46			52			47			13			15			15
Expected return on plan assets	(70)			(69)			(69)			(17)			(19)			(23)
Amortization of prior service credit	(3)			(3)			(3)			(4)			(5)			(6)
Amortization of net loss	30			25			31			1			3			4
Settlement charge (a)	—			3			5			—			—			—
Net periodic pension cost (credit)	33			34			40			(7)			(5)			(9)
Effects of regulation	4			4			(4)			3			1			2
Net benefit cost (credit) recognized for financial reporting	$	37		$	38		$	36		$	(4)		$	(4)		$	(7)
Significant Assumptions Used to Measure Costs:
Discount rate	3.49		%	4.31		%	3.63		%	3.47		%	4.32		%	3.62		%
Expected average long-term increase in compensation level	3.75			3.75			3.75			N/A			N/A			N/A
Expected average long-term rate of return on assets	6.84			6.84			6.84			4.50			4.50			5.30

(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 2019 and 2018, as a result of lump-sum distributions during each plan year, PSCo recorded a total pension settlement charge of $3 million and $5 million, respectively. An immaterial amount was recorded in the income statement in 2019 and 2018. There were no settlement charges recorded to the qualified pension plans in 2020.

	Pension Benefits				Postretirement Benefits
(Millions of Dollars)	2020		2019		2020		2019
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	432	$	482	$	81	$	45
Prior service credit	(1)		(4)		(6)		(10)
Total	$	431	$	478	$	75	$	35
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	$	25	$	22	$	—	$	—
Noncurrent regulatory assets	404		452		75		35
Deferred income taxes	1		1		—		—
Net-of-tax accumulated other comprehensive income	1		3		—		—
Total	$	431	$	478	$	75	$	35

Measurement date Dec. 31, 2020 Dec. 31, 2019 Dec. 31, 2020 Dec. 31, 2019

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 2018 — 2021 to meet minimum funding requirements. Total voluntary and required pension funding contributions across all four of Xcel Energy’s pension plans were as follows:

•$125 million in January 2021, of which $45 million was attributable to PSCo.

•$150 million in 2020, of which $50 million was attributable to PSCo.

•$154 million in 2019, of which $46 million was attributable to PSCo.

•$150 million in 2018, of which $22 million was attributable to PSCo.

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:

•$10 million in January 2021, of which an immaterial amount is attributable to PSCo.

•$11 million during 2020, of which $3 million was attributable to PSCo.

•$15 million during 2019, of which $4 million was attributable to PSCo.

•$11 million during 2018, of which $5 million was attributable to PSCo.

Targeted asset allocations:

	Pension Benefits				Postretirement Benefits
	2020		2019		2020		2019
Domestic and international equity securities	35	%	37	%	15	%	15	%
Long-duration fixed income securities	35		30		—		—
Short-to-intermediate fixed income securities	13		14		72		72
Alternative investments	15		17		9		9
Cash	2		2		4		4
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 2018, the PSCo postretirement plan was amended to add the 5% cash balance formula.

In 2020 and 2019, there were no significant plan amendments made which affected the projected benefit obligation.

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
2021	$	83	$	31	$	2	$	29
2022	83		31		2		29
2023	82		30		2		28
2024	82		30		2		28
2025	82		29		2		27
2026-2030	393		130		12		118

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 $12 million in 2020 and $11 million in 2019 and 2018.

XML

Commitments and Contingencies

12 Months Ended

Dec. 31, 2020

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

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, management does not anticipate that the ultimate liabilities, if any, would have a material effect on PSCo’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.

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 three MGP, landfill or other disposal sites across its service territory.

PSCo has recognized its best estimate of costs/liabilities that will result from final resolution of these issues, however, the outcome and timing is 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 CCR landfills and surface impoundments. Currently, PSCo has six regulated ash units in operation.

PSCo is conducting groundwater sampling and monitoring and implementing assessment of corrective measures at certain CCR landfills and surface impoundments. Increases above background concentrations were detected at four locations.

Subsequently, assessment monitoring samples were collected at these locations. As a result, PSCo is evaluating options for corrective action at two locations, one of which indicates potential offsite impacts to groundwater. Until PSCo completes its assessments, it is uncertain what impact, if any, there will be on the operations, financial condition or cash flows.

In August 2020, the EPA published its final rule to implement a cease receipt and initiate a closure date of April 2021 for all CCR impoundments affected by the August 2018 D.C. Circuit ruling. The D.C. Circuit concluded that the EPA cannot allow utilities to continue to use unlined impoundments (including clay lined impoundments) for the storage or disposal of coal ash. This final rule required Xcel Energy to expedite closure plans for one impoundment.

PSCo is pursuing options to build an alternative bottom ash collection system that will be constructed and in service in advance of the April 11, 2021 deadline. Once the alternative bottom ash system is operational, the existing impoundment will initiate closure per the CCR Rule.

Closure costs for existing impoundments are included in the calculation of the ARO.

Federal CWA WOTUS Rule — In April 2020, the EPA and U.S. Army Corps of Engineers (“Agencies”) replaced the 2015 WOTUS rule and narrowed the definition of WOTUS (“2020 WOTUS Rule”). The new definition simplifies the process whether waters are subject to CWA jurisdiction and streamlines the permitting process.

In June 2020, the U.S. District Court for the District of Colorado stayed the effective date of the 2020 WOTUS Rule in Colorado, where the pre-2015 definition of WOTUS is now in effect. Regardless of which definition is applicable in the states in which we operate, PSCo does not anticipate that compliance costs will be material.

Federal CWA ELG — In 2015, the EPA issued a final ELG rule for power plants that discharge treated effluent to surface waters as well as utility-owned landfills that receive CCRs. In October 2020, the EPA published a final rule revising the regulations.

The retirement of units affected by the final ELG rule is subject to regulatory approval. The exact total cost of ELG compliance is therefore uncertain but PSCo does not anticipate that compliance costs will be material.

Federal CWA Section 316(b) — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing impingement and entrainment of aquatic species. PSCo estimates the likely cost for complying with impingement and entrainment requirements is immaterial. PSCo anticipates these costs will be fully recoverable through regulatory mechanisms.

Environmental Requirements — Air

Regional Haze Rules — The regional haze program requires sulfur dioxide, nitrogen oxide and particulate matter emission controls at power plants to reduce visibility impairment in national parks and wilderness areas. The program includes best available retrofit technology and reasonable further progress. The regional haze first planning period requirements were approved by the EPA and implemented by 2016.

All states are now subject to a second round of regional haze planning/rulemaking, focusing on additional reductions to meet reasonable progress requirements. Any additional impacts to PSCo facilities are expected to be minimal.

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

PSCo’s AROs were as follows:

	2020
(Millions  of Dollars)	Jan. 1, 2020		Amounts Incurred (a)		Amounts Settled (b)		Accretion		Cash Flow Revisions (c)		Dec. 31, 2020
Electric
Steam, hydro and other production	$	100	$	—	$	—	$	4	$	33	$	137
Wind	16		26		(3)		1		—		40
Distribution	14		—		—		1		—		15
Natural gas
Transmission and distribution	190		—		—		8		5		203
Miscellaneous	3		—		—		—		—		3
Common
Miscellaneous	1		—		—		—		—		1
Total liability	$	324	$	26	$	(3)	$	14	$	38	$	399

(a)Amounts incurred related to the Cheyenne Ridge wind farm placed in service in 2020.

(b)Amounts settled related to removal of wind facilities.

(c)In 2020, 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 ash containment facilities.

	2019
(Millions  of Dollars)	Jan. 1, 2019		Accretion		Cash Flow Revisions (a)		Dec. 31, 2019 (b)
Electric
Steam, hydro and other production	$	102	$	5	$	(7)	$	100
Wind	14		1		1		16
Distribution	13		1		—		14
Miscellaneous	3		—		(3)		—
Natural gas
Transmission and distribution	201		9		(20)		190
Miscellaneous	4		—		(1)		3
Common
Miscellaneous	1		—		—		1
Total liability	$	338	$	16	$	(30)	$	324

(a)In 2019, AROs were revised for changes in timing and estimates of cash flows. Changes in gas transmission and distribution AROs were primarily related to increased gas line mileage and number of services, which were more than offset by decreased inflation rates. Revisions in steam, hydro, and other production AROs primarily related to changes in cost estimates for pond remediation.

(b)There were no ARO amounts incurred or settled in 2019.

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, 2020. 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 3.9%). 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 minimum lease payments for the purposes of lease accounting and disclosure.

Leases with an initial term of 12 months or less are classified as short-term leases and are not recognized on the consolidated balance sheet.

Operating lease ROU assets:

(Millions of Dollars)	Dec. 31, 2020		Dec. 31, 2019
PPAs	$	591	$	585
Other	68		69
Gross operating lease ROU assets	659		654
Accumulated amortization	(159)		(80)
Net operating lease ROU assets	$	500	$	574

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, 2020		Dec. 31, 2019
Gas storage facilities	$	201	$	200
Gas pipeline	21		21
Gross finance lease ROU assets	222		221
Accumulated amortization	(90)		(82)
Net finance lease ROU assets	$	132	$	139

Components of lease expense:

(Millions of Dollars)	2020		2019		2018
Operating leases
PPA capacity payments	$	100	$	98	$	97
Other operating leases (a)	13		14		14
Total operating lease expense (b)	$	113	$	112	$	111
Finance leases
Amortization of ROU assets	$	7	$	6	$	6
Interest expense on lease liability	18		19		19
Total finance lease expense	$	25	$	25	$	25

(a)Includes short-term lease expense of $1 million, $2 million and $1 million for 2020, 2019 and 2018, respectively.

(b)PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income. Expense for other operating leases is included in O&M expense and electric fuel and purchased power.

Commitments under operating and finance leases as of Dec. 31, 2020:

(Millions of Dollars)	PPA (a) (b) Operating Leases		Other Operating Leases		Total Operating Leases		Finance Leases
2021	$	101	$	15	$	116	$	24
2022	84		15		99		21
2023	70		10		80		20
2024	63		10		73		20
2025	63		5		68		19
Thereafter	163		12		175		381
Total minimum obligation	544		67		611		485
Interest component of obligation	(74)		(8)		(82)		(352)
Present value of minimum obligation	$	470	$	59	529		133
Less current portion					(97)		(7)
Noncurrent operating and finance lease liabilities					$	432	$	126
Weighted-average remaining lease term in years					7.1		38.0

(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.

Non-Lease PPAs — PSCo has entered into PPAs with other utilities and energy suppliers with various expiration dates through 2033 for purchased power to meet system load and energy requirements and operating reserve obligations. In general, these agreements provide for energy payments, based on actual energy delivered and capacity payments. Certain PPAs accounted for as executory contracts contain minimum energy purchase commitments.

Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $10 million, $12 million and $21 million in 2020, 2019 and 2018, 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, 2020, 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
2021	$	3
2022	3
2023	3
2024	3
2025	3
Thereafter	5
Total	$	20

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 2021 and 2060. PSCo is required to pay additional amounts depending on actual quantities shipped under these agreements.

Estimated minimum purchases under these contracts as of Dec. 31, 2020:

(Millions of Dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2021	$	132	$	354	$	116
2022	61		119		115
2023	22		54		67
2024	22		3		37
2025	23		—		36
Thereafter	47		—		475
Total	$	307	$	530	$	846

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. 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 it does not have the power to direct the activities that most significantly impact the entities’ economic performance. PSCo had approximately 1,518 MW and 1,442 MW of capacity under long-term PPAs at Dec. 31, 2020 and 2019, respectively, with entities that have been determined to be VIEs. These agreements have expiration dates through 2032.

XML

Other Comprehensive Income

12 Months Ended

Dec. 31, 2020

Stockholders' Equity Note [Abstract]

Other Comprehensive Income

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

	2020
(Millions of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(24)		$	(3)		$	(27)
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $— and $—, respectively)	1		(a)	—			1
Amortization of net actuarial loss (net of taxes of $— and $1, respectively)	—			2		(b)	2
Net current period other comprehensive income (loss)	1			2			3
Accumulated other comprehensive loss at Dec. 31	$	(23)		$	(1)		$	(24)

(a)Included in interest charges.

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

	2019
(Millions of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(26)		$	—		$	(26)
Losses (gains) reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $— and $—, respectively)	2		(a)	—			2
Amortization of net actuarial gains (net of taxes of $— and $(1), respectively)	—			(3)		(b)	(3)
Net current period other comprehensive income	2			(3)			(1)
Accumulated other comprehensive loss at Dec. 31	$	(24)		$	(3)		$	(27)

(a)Included in interest charges.

XML

Segments and Related Information

12 Months Ended

Dec. 31, 2020

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 electricity which is transmitted and distributed in Colorado. This segment includes sales for resale and provides wholesale transmission service to various entities in the United States. Regulated electric utility also includes PSCo’s wholesale commodity and trading operations.

•Regulated Natural Gas — The regulated natural gas utility segment transports, stores and distributes 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, and 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.

To report income from operations for regulated electric and regulated natural gas utility segments, the majority of costs are directly assigned to each segment. However, some costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators. 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)	2020		2019		2018
Regulated Electric
Operating revenues - external	$	3,116	$	3,033	$	3,031
Intersegment revenue	1		1		—
Total revenues	$	3,117	$	3,034	$	3,031
Depreciation and amortization	497		455		416
Interest charges and financing costs	173		173		142
Income tax expense	13		45		103
Net income	460		465		429
Regulated Natural Gas
Operating revenues - external	$	1,024	$	1,161	$	1,015
Intersegment revenue	—		—		1
Total revenues	$	1,024	$	1,161	$	1,016
Depreciation and amortization	152		141		140
Interest charges and financing costs	50		50		43
Income tax expense	29		33		13
Net income	126		119		121
All Other
Total revenues (a)	$	43	$	43	$	40
Depreciation and amortization	6		6		5
Interest charges and financing costs	1		1		1
Income tax expense (benefit)	3		2		(3)
Net income (loss)	2		(6)		2
Consolidated Total
Total revenues (a)	$	4,184	$	4,238	$	4,087
Reconciling eliminations	(1)		(1)		(1)
Total operating revenues	$	4,183	$	4,237	$	4,086
Depreciation and amortization	655		602		561
Interest charges and financing costs	224		224		186
Income tax expense	45		80		113
Net income	588		578		552

(a)    Operating revenues include $5 million, $5 million and $4 million of intercompany revenue for the years ended Dec. 31, 2020, 2019 and 2018, respectively. See Note 13 for further information.

XML

Related Party Transactions

12 Months Ended

Dec. 31, 2020

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)	2020		2019		2018
Operating revenues:
Other	$	5	$	5	$	4
Operating expenses:
Other operating expenses — paid to Xcel Energy Services Inc.	571		532		519

Accounts receivable and payable with affiliates at Dec. 31:

	2020				2019
(Millions of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Minnesota	$	—	$	1	$	19	$	—
NSP-Wisconsin	—		1		—		—
SPS	—		6		—		—
Other subsidiaries of Xcel Energy Inc.	8		50		34		44
	$	8	$	58	$	53	$	44

XML

Summarized Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2020

Quarterly Financial Information Disclosure [Abstract]

Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended
(Millions of Dollars)	March 31, 2020		June 30, 2020		Sept. 30, 2020		Dec. 31, 2020
Operating revenues	$	1,057	$	911	$	1,081	$	1,134
Operating income	196		161		290		176
Net income	129		108		218		133

	Quarter Ended
(Millions of Dollars)	March 31, 2019		June 30, 2019		Sept. 30, 2019		Dec. 31, 2019
Operating revenues	$	1,223	$	910	$	1,044	$	1,060
Operating income	210		163		284		200
Net income	139		102		204		133

XML

Schedule II, Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2020

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)	2020		2019		2018
Balance at Jan. 1	$	21	$	21	$	20
Additions charged to costs and expenses	24		17		16
Additions charged to other accounts (a)	4		6		5
Deductions from reserves (b)	(20)		(23)		(20)
Balance at Dec. 31	$	29	$	21	$	21

(a)Recovery of amounts previously written-off.

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

XML

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2020

Accounting Policies [Abstract]

Business and System of Accounts

General — PSCo is engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and in 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 various state regulatory commissions. Certain amounts in the consolidated financial statements or notes have been reclassified for comparative purposes; however, such reclassifications did not affect net income, total assets, liabilities, equity or cash flows.

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 the operating costs associated with these facilities is included in its consolidated statements of income.

Subsequent Events

PSCo has evaluated events occurring after Dec. 31, 2020 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 in recording transactions and balances resulting from business operations. Estimates are used on 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 of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. 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 from its balance sheet. 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 financial statements. PSCo defers income taxes for all temporary differences between pretax financial and taxable income and between the book and tax bases of assets and liabilities. PSCo uses rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the period that includes the enactment date.

The effects of 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, which would be refundable to utility customers over the remaining life of the related assets. PSCo anticipates that a tax rate increase would result in the establishment of a regulatory asset, subject to regulatory approval.

Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of regulatory assets and liabilities related to income taxes. 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.

PSCo follows the applicable accounting guidance to measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns. PSCo recognizes a tax position in its 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.

PSCo reports interest and penalties related to income taxes within other (expense) income 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 are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property.

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.

PSCo records depreciation expense using the straight-line method over the plant’s 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 recovered in rates as authorized by the appropriate regulatory entities. The amount of removal costs are based on current factors used in existing depreciation rates. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.1% in 2020, 2.9% in 2019 and 2.6% in 2018.

See Note 3 for further information.

Asset Retirement Obligations

AROs — PSCo accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement 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 depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount 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 liability 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. If an environmental expense is related to facilities currently in use, such as 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 proceeds. 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. 

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

See Note 10 for further information.

Revenue From Contracts With Customers

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.

PSCo does not recognize a separate financing component of its collections from customers as contract terms are short-term in nature. PSCo presents its revenues net of any excise or sales taxes or fees.

See Note 6 for further information.

Cash and Cash Equivalents

Cash and Cash Equivalents — PSCo considers investments in instruments with a remaining maturity of three 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, 2020 and 2019, the allowance for bad debts was $29 million and $21 million, respectively.

Inventory

Inventory — Inventory is recorded at average cost and consisted of the following:

(Millions of Dollars)	Dec. 31, 2020		Dec. 31, 2019
Inventories
Materials and supplies	$	63	$	63
Fuel	73		77
Natural gas	53		52
Total inventories	$	189	$	192

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. 

Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted NAVs. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used to establish 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, PSCo may use quoted prices for similar contracts or internally prepared valuation models to determine fair value. 

For the pension and postretirement plan assets, published trading data and pricing models, generally using the most observable inputs available, are utilized to estimate 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 interest rate, utility commodity price and commodity trading activities, including forward contracts, futures, swaps and options. Any derivative instruments not qualifying for the normal purchases and normal sales exception are recorded on the consolidated balance sheets at fair value as derivative instruments. Classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues and interest rate hedging transactions are recorded as a component of interest expense. 

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 a derivative exists and/or whether an instrument may be exempted from derivative accounting if designated as a normal purchase or normal sale.

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. AFUDC 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 for establishing utility rates.

Alternative Revenue Programs

Alternative Revenue — Certain rate rider mechanisms (including decoupling and DSM programs) qualify as alternative revenue programs. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate. When certain criteria are met, including expected collection within 24 months, revenue is recognized equal to the revenue requirement, which may include incentives and return on rate base items. Billing amounts are revised periodically for differences between total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers.

See Note 6 for further information.

Conservation Programs — 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 annual period 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

Emission Allowances — Emission allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emission allowances and sales of these allowances are included in electric revenues.

Renewable Energy Credits

RECs — Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. PSCo records that cost as a regulatory asset when the amount is recoverable in future rates.

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

XML

Summary of Significant Accounting Policies Inventory (Tables)

12 Months Ended

Dec. 31, 2020

Balance Sheet Related Disclosure - Inventory [Abstract]

Public Utilities, Inventory

Inventory — Inventory is recorded at average cost and consisted of the following:

(Millions of Dollars)	Dec. 31, 2020		Dec. 31, 2019
Inventories
Materials and supplies	$	63	$	63
Fuel	73		77
Natural gas	53		52
Total inventories	$	189	$	192

XML

Property Plant and Equipment Property Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2020

Property, Plant and Equipment [Abstract]

Public Utility Property, Plant, and Equipment

Major classes of property, plant and equipment

(Millions of Dollars)	Dec. 31, 2020		Dec. 31, 2019
Property, plant and equipment, net
Electric plant	$	15,736	$	14,362
Natural gas plant	5,037		4,631
Common and other property	1,191		1,113
Plant to be retired (a)	225		260
CWIP	510		913
Total property, plant and equipment	22,699		21,279
Less accumulated depreciation	(5,229)		(5,124)
Property, plant and equipment, net	$	17,470	$	16,155

(a)Includes regulator-approved retirements of Comanche Units 1 and 2 and jointly owned Craig Unit 1. Also includes PSCo’s planned retirement of jointly owned Craig Unit 2.

Schedule of Jointly Owned Utility Plants

Joint Ownership of Generation, Transmission and Gas Facilities

Jointly owned assets as of Dec. 31, 2020:

(Millions of Dollars, Except Percent Owned)	Plant in Service		Accumulated Depreciation		CWIP		Percent Owned
Electric generation:
Hayden Unit 1	$	153	$	92	$	—	76	%
Hayden Unit 2	150		73		—		37
Hayden common facilities	42		25		—		53
Craig Units 1 and 2	81		44		—		10
Craig common facilities	39		24		—		7
Comanche Unit 3	899		137		16		67
Comanche common facilities	25		2		—		82
Electric transmission:
Transmission and other facilities	176		59		2		Various
Gas transmission:
Rifle, CO to Avon, CO	22		8		—		60
Gas transmission compressor	8		1		—		50
Total	$	1,595	$	465	$	18

XML

Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2020

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets

Components of regulatory assets:

(Millions of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2020				Dec. 31, 2019
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Pension and retiree medical obligations	9	Various	$	28	$	478	$	23	$	494
Depreciation differences		One to 11 years	16		154		15		140
Net AROs (a)	1, 10	Various	—		132		—		119
Recoverable deferred taxes on AFUDC		Plant lives	—		110		—		105
Excess deferred taxes — TCJA	7	Various	3		56		3		55
Purchased power contract costs		Term of related contract	3		22		2		24
Property tax		Various	16		21		1		30
Conservation programs (b)	1	One to two years	11		11		8		11
Gas pipeline inspection costs		One to two years	—		9		—		8
Losses on reacquired debt		Term of related debt	1		3		1		4
Contract valuation adjustments (c)	1, 8	Term of related contract	6		—		3		—
Recoverable purchased natural gas and electric energy costs		Less than one year	6		—		—		—
Other		Various	31		63		8		48
Total regulatory assets			$	121	$	1,059	$	64	$	1,038

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

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

(c)Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.

Regulatory Liabilities

Components of regulatory liabilities:

(Millions of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2020				Dec. 31, 2019
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Deferred income tax adjustments and TCJA refunds (a)	7	Various	$	5	$	1,368	$	5	$	1,403
Plant removal costs	1, 10	Various	—		615		—		351
Effects of regulation on employee benefit costs (b)		Various	—		203		—		183
Renewable resources and environmental initiatives		Various	—		59		—		45
Revenue decoupling		One to two years	10		41		—		—
ITC deferrals	1	Various	—		40		—		26
Conservation programs (c)	1	Less than one year	39		—		30		—
Deferred electric, natural gas and steam production costs		Less than one year	17		—		8		—
Other		Various	29		11		26		29
Total regulatory liabilities			$	100	$	2,337	$	69	$	2,037

(a)Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA.

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

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

XML

Borrowings and Other Financing Instruments (Tables)

12 Months Ended

Dec. 31, 2020

Debt Disclosure [Abstract]

Money Pool [Table Text Block]

Money pool borrowings for PSCo were as follows:

(Millions of Dollars, Except Interest Rates)	Three Months Ended Dec. 31, 2020			Year Ended Dec. 31
				2020			2019			2018
Borrowing limit	$	250		$	250		$	250		$	250
Amount outstanding at period end	57			57			39			—
Average amount outstanding	104			59			7			25
Maximum amount outstanding	218			250			50			156
Weighted average interest rate, computed on a daily basis	0.08		%	0.60		%	2.29		%	1.93		%
Weighted average interest rate at end of period	0.07			0.07			1.63			N/A

Schedule of Short-term Debt [Table Text Block]

Commercial paper borrowings for PSCo were as follows:

(Millions of Dollars, Except Interest Rates)	Three Months Ended Dec. 31, 2020			Year Ended Dec. 31
				2020			2019			2018
Borrowing limit	$	700		$	700		$	700		$	700
Amount outstanding at period end	136			136			—			307
Average amount outstanding	8			30			154			55
Maximum amount outstanding	136			230			432			309
Weighted average interest rate, computed on a daily basis	0.19		%	1.59		%	2.67		%	2.28		%
Weighted average interest rate at end of period	0.20			0.20			N/A			2.95

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

Debt-to-Total Capitalization Ratio (a)				Amount Facility May Be Increased (millions)		Additional Periods for Which a One-Year Extension May Be Requested (b)
2020		2019
44	%	44	%	$	100	2

Schedule of Line of Credit Facilities [Table Text Block]

(millions):

Credit Facility (a)		Drawn (b)		Available
$	700	$	144	$	556

(a)This credit facility matures in June 2024.

(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 (millions of dollars):

Financing Instrument	Interest Rate	Maturity Date	2020		2019
First mortgage bonds	3.20	Nov. 15, 2020	—		400
First mortgage bonds	2.25	Sept. 15, 2022	300		300
First mortgage bonds	2.50	March 15, 2023	250		250
First mortgage bonds	2.90	May 15, 2025	250		250
First mortgage bonds	3.70	June 15, 2028	350		350
First mortgage bonds (a)	1.90	Jan. 15, 2031	375		—
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 (b)	4.05	Sept. 15, 2049	400		400
First mortgage bonds (b)	3.20	March 1, 2050	550		550
First mortgage bonds (a)	2.70	Jan. 15, 2051	375		—
Unamortized discount			(30)		(24)
Unamortized debt issuance cost			(46)		(41)
Current maturities			—		(400)
Total long-term debt			$	5,724	$	4,985

^[3],[4]

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

Maturities of long-term debt:

(Millions of Dollars)
2021	$	—
2022	300
2023	250
2024	—
2025	250

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) 2020 and 2019
10,000,000	$	0.01	—

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

[2] This credit facility matures in June 2024.

[3] 2019 financing.

[4] 2020 financing

XML

Revenues (Tables)

12 Months Ended

Dec. 31, 2020

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

PSCo’s operating revenues consisted of the following:

	Year Ended Dec. 31, 2020
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	1,073	$	650	$	12	$	1,735
C&I	1,512		225		27		1,764
Other	48		—		—		48
Total retail	2,633		875		39		3,547
Wholesale	212		—		—		212
Transmission	62		—		—		62
Other	56		125		—		181
Total revenue from contracts with customers	2,963		1,000		39		4,002
Alternative revenue and other	153		24		4		181
Total revenues	$	3,116	$	1,024	$	43	$	4,183

	Year Ended Dec. 31, 2019
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	1,006	$	750	$	11	$	1,767
C&I	1,579		281		28		1,888
Other	50		—		—		50
Total retail	2,635		1,031		39		3,705
Wholesale	166		—		—		166
Transmission	52		—		—		52
Other	32		107		—		139
Total revenue from contracts with customers	2,885		1,138		39		4,062
Alternative revenue and other	148		23		4		175
Total revenues	$	3,033	$	1,161	$	43	$	4,237

	Year Ended Dec. 31, 2018
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	991	$	606	$	11	$	1,608
C&I	1,560		224		25		1,809
Other	48		—		—		48
Total retail	2,599		830		36		3,465
Wholesale	175		—		—		175
Transmission	54		—		—		54
Other	55		84		—		139
Total revenue from contracts with customers	2,883		914		36		3,833
Alternative revenue and other	148		101		4		253
Total revenues	$	3,031	$	1,015	$	40	$	4,086

XML

Preferred Stock (Tables)

12 Months Ended

Dec. 31, 2020

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) 2020 and 2019
10,000,000	$	0.01	—

XML

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2020

Income Tax Disclosure [Abstract]

Summary of Statute of Limitations Applicable to Open Tax Years

Tax Year(s)	Expiration
2014 - 2016	July 2021

Reconciliation of Unrecognized Tax Benefits

Unrecognized tax benefits - permanent vs temporary:

(Millions of Dollars)	Dec. 31, 2020		Dec. 31, 2019
Unrecognized tax benefit — Permanent tax positions	$	7	$	7
Unrecognized tax benefit — Temporary tax positions	2		5
Total unrecognized tax benefit	$	9	$	12

Changes in unrecognized tax benefits:

(Millions of Dollars)	2020		2019		2018
Balance at Jan. 1	$	12	$	10	$	10
Additions based on tax positions related to the current year	2		1		1
Additions for tax positions of prior years	6		1		—
Reductions for tax positions of prior years	(11)		—		—
Settlements with taxing authorities	—		—		(1)
Balance at Dec. 31	$	9	$	12	$	10

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, 2020		Dec. 31, 2019
NOL and tax credit carryforwards	$	(8)	$	(8)

Interest Payable related to Unrecognized Tax Benefits

Interest payable related to unrecognized tax benefits:

(Millions of Dollars)	2020		2019		2018
Payable for interest related to unrecognized tax benefits at Jan. 1	$	(1)	$	(1)	$	—
Interest income (expense) related to unrecognized tax benefits	1		—		(1)
Payable for interest related to unrecognized tax benefits at Dec. 31	$	—	$	(1)	$	(1)

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)	2020		2019
Federal tax credit carryforwards	$	143	$	83
State NOL carryforwards	190		388
State tax credit carryforwards, net of federal detriment (a)	18		18
Valuation allowances for state credit carryforwards, net of federal benefit (b)	(8)		(8)

(a)State tax credit carryforwards are net of federal detriment of $5 million as of both Dec. 31, 2020 and 2019.

(b)Valuation allowances for state tax credit carryforwards were net of federal benefit of $2 million as of both Dec. 31, 2020 and 2019.

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:

	2020		2019		2018
Federal statutory rate	21.0	%	21.0	%	21.0	%
State income tax on pretax income, net of federal tax effect	3.6		3.6		3.7
Increases (decreases) in tax from:
Wind PTCs	(10.3)		(7.5)		(0.6)
Plant regulatory differences (a)	(5.0)		(3.3)		(4.5)
Other tax credits, net NOL & tax credit allowances	(1.1)		(1.3)		(0.6)
Amortization of excess nonplant deferred taxes	(0.2)		(0.2)		(1.4)
Change in unrecognized tax benefits	(0.2)		0.3		0.1
Other, net	(0.7)		(0.4)		(0.7)
Effective income tax rate	7.1	%	12.2	%	17.0	%

.

Schedule of Components of Income Tax Expense (Benefit)

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

(Millions of Dollars)	2020		2019		2018
Current federal tax expense (benefit)	$	44	$	(9)	$	79
Current state tax expense (benefit)	4		(5)		14
Current change in unrecognized tax benefit	(3)		(1)		(1)
Deferred federal tax (benefit) expense	(26)		61		5
Deferred state tax expense	26		33		17
Deferred change in unrecognized tax expense	2		3		2
Deferred ITCs	(2)		(2)		(3)
Total income tax expense	$	45	$	80	$	113

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

(Millions of Dollars)	2020		2019		2018
Deferred tax expense excluding items below	$	46	$	132	$	75
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(43)		(35)		(51)
Tax expense allocated to other comprehensive income, adoption of ASC Topic 326, adoption of ASU No. 2018-02, and other	(1)		—		—
Deferred tax expense	$	2	$	97	$	24

Schedule of Deferred Tax Assets and Liabilities

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

(Millions of Dollars)	2020		2019 (a)
Deferred tax liabilities:
Differences between book and tax bases of property	$	2,132	$	2,039
Regulatory assets	257		253
Operating lease assets	129		148
Pension expense and other employee benefits	19		22
Other	6		7
Total deferred tax liabilities	$	2,543	$	2,469
Deferred tax assets:
Regulatory liabilities	$	319	$	327
Tax credit carryforward	161		101
Operating lease liabilities	129		148
Bad debts	8		5
NOL carryforward	7		14
Deferred ITCs	5		6
Tax credit valuation allowances	(8)		(8)
Other	25		25
Total deferred tax assets	$	646	$	618
Net deferred tax liability	$	1,897	$	1,851

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

XML

Fair Value of Financial Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2020

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, 2020	Dec. 31, 2019
MWh of electricity	17	9
MMBtu of natural gas	93	32

(a)Not reflective of net positions in the underlying commodities.

(b)Notional amounts for options included on a gross basis, but are weighted for the probability of exercise.

Financial Impact of Qualifying Cash Flow Hedges on Accumulated Other Comprehensive Loss

(Millions of Dollars)	2020		2019		2018
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(24)	$	(26)	$	(27)
After-tax net realized losses on derivative transactions reclassified into earnings	1		2		1
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(23)	$	(24)	$	(26)

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, 2020
Other derivative instruments
Natural gas commodity	$	—	$	(10)
Total	$	—	$	(10)
Year Ended Dec. 31, 2019
Other derivative instruments
Natural gas commodity	$	—	$	(5)
Total	$	—	$	(5)
Year Ended Dec. 31, 2018
Other derivative instruments
Natural gas commodity	$	—	$	8
Total	$	—	$	8

	Pre-Tax (Gains) Losses Reclassified into Income During the Period from:
(Millions of Dollars)	Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)			Pre-Tax Gains (Losses) Recognized During the Period in Income
Year Ended Dec. 31, 2020
Derivatives designated as cash flow hedges
Interest rate	$	1	(a)	$	—		$	—
Total	$	1		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	3	(b)
Natural gas commodity	—			8		(c)	(8)		(c)
Total	$	—		$	8		$	(5)

(a)    Recorded to interest charges.

(b)    Recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.

(c)    Amounts for the year ended Dec. 31, 2020, included no settlement gains or losses on derivatives entered to mitigate natural gas price risk for electric generation recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset or liability, as appropriate. Remaining settlement losses for the years ended Dec. 31, 2020, relate to natural gas operations and are 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 or liability, as appropriate.

	Pre-Tax (Gains) Losses Reclassified into Income During the Period from:
(Millions of Dollars)	Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)			Pre-Tax Gains (Losses) Recognized During the Period in Income
Year Ended Dec. 31, 2019
Derivatives designated as cash flow hedges
Interest rate	$	2	(a)	$	—		$	—
Total	$	2		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	3	(b)
Natural gas commodity	—			1		(c)	(4)		(c)
Total	$	—		$	1		$	(1)

(a)    Recorded to interest charges.

(b)    Recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.

(c)    Amounts for the year ended Dec. 31, 2019, included no settlement gains or losses on derivatives entered to mitigate natural gas price risk for electric generation recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset or liability, as appropriate. Remaining settlement losses for the years ended Dec. 31, 2019, relate to natural gas operations and are 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 or liability, as appropriate.

	Pre-Tax (Gains) Losses Reclassified into Income During the Period from:
(Millions of Dollars)	Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)			Pre-Tax Gains (Losses) Recognized During the Period in Income
Year Ended Dec. 31, 2018
Derivatives designated as cash flow hedges
Interest rate	$	1	(a)	$	—		$	—
Total	$	1		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	3	(b)
Natural gas commodity	—			(4)		(c)	(3)		(c)
Total	$	—		$	(4)		$	—

(a)    Recorded to interest charges.

(b)    Recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.

(c)    Amounts for the year ended Dec. 31, 2018, included $1 million of settlement losses on derivatives entered to mitigate natural gas price risk for electric generation recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset or liability, as appropriate. Remaining settlement losses for the years ended Dec. 31, 2018, relate to natural gas operations and are 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 or liability, as appropriate.

Derivative Assets and Liabilities Measured at Fair Value on a Recurring Basis by Hierarchy Level

PSCo’s derivative assets and liabilities measured at fair value on a recurring basis were as follows:

	Dec. 31, 2020												Dec. 31, 2019
	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	$	41	$	1	$	43	$	(28)	$	15	$	2	$	11	$	1	$	14	$	(10)	$	4
Natural gas commodity	—		6		—		6		—		6		—		3		—		3		—		3
Total current derivative assets	$	1	$	47	$	1	$	49	$	(28)	$	21	$	2	$	14	$	1	$	17	$	(10)	$	7
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	1	$	27	$	8	$	36	$	(20)	$	16	$	1	$	8	$	1	$	10	$	(10)	$	—
Total noncurrent derivative assets	$	1	$	27	$	8	$	36	$	(20)	16		$	1	$	8	$	1	$	10	$	(10)	$	—
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	1	$	46	$	7	$	54	$	(33)	$	21	$	2	$	17	$	—	$	19	$	(13)	$	6
Natural gas commodity	—		6		—		6		—		6		—		3		—		3		—		3
Total current derivative liabilities	$	1	$	52	$	7	$	60	$	(33)	$	27	$	2	$	20	$	—	$	22	$	(13)	$	9
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	1	$	24	$	46	$	71	$	(20)	$	51	$	1	$	47	$	15	$	63	$	(10)	$	53
Total noncurrent derivative liabilities	$	1	$	24	$	46	$	71	$	(20)	$	51	$	1	$	47	$	15	$	63	$	(10)	$	53

(a)PSCo nets derivative instruments and related collateral on its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2020 and 2019. At Dec. 31, 2020 and 2019, derivative assets and liabilities include no obligations to return cash collateral, respectively. At Dec. 31, 2020 and 2019, derivative assets and liabilities include rights to reclaim cash collateral of $5 million and $3 million, respectively. The 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 for the years ended Dec. 31, 2020, 2019 and 2018:

	Year Ended Dec. 31
(Millions of Dollars)	2020		2019		2018
Balance at Jan. 1	$	(13)	$	—	$	—
Settlements	—		(2)		—
Net transactions recorded during the period:
Losses recognized in earnings (a)	(31)		(11)		—
Balance at Dec. 31	$	(44)	$	(13)	$	—

(a)Level 3 losses recognized in earnings are subject to offsetting gains of derivative instruments categorized as levels 1 and 2 in the income statement.

PSCo recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the years ended Dec. 31, 2020, 2019 and 2018.

Fair Value of Long-Term Debt

As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value:

	2020				2019
(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	5,724	$	7,040	$	5,385	$	6,039

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, 2020 and 2019, 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

	2020				2019
(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	5,724	$	7,040	$	5,385	$	6,039

XML

Benefit Plans and Other Postretirement Benefits (Tables)

12 Months Ended

Dec. 31, 2020

Benefit Plans and Other Postretirement Benefits [Abstract]

Target Asset Allocations and Plan Assets Measured at Fair Value

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

	Dec. 31, 2020 (a)										Dec. 31, 2019 (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	$	75	$	—	$	—	$	—	$	75	$	46	$	—	$	—	$	—	$	46
Commingled funds	518		—		—		388		906		497		—		—		355		852
Debt securities	—		270		1		—		271		—		241		2		—		243
Equity securities	27		—		—		—		27		30		—		—		—		30
Other	2		2		—		—		4		(41)		1		—		(7)		(47)
Total	$	622	$	272	$	1	$	388	$	1,283	$	532	$	242	$	2	$	348	$	1,124

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

	Dec. 31, 2020 (a)										Dec. 31, 2019 (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	$	24	$	—	$	—	$	—	$	24	$	20	$	—	$	—	$	—	$	20
Insurance contracts	—		45		—		—		45		—		45		—		—		45
Commingled funds	64		—		—		61		125		62		—		—		68		130
Debt securities	—		207		—		—		207		—		203		1		—		204
Other	—		3		—		—		3		—		2		—		—		2
Total	$	88	$	255	$	—	$	61	$	404	$	82	$	250	$	1	$	68	$	401

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

	Pension Benefits				Postretirement Benefits
	2020		2019		2020		2019
Domestic and international equity securities	35	%	37	%	15	%	15	%
Long-duration fixed income securities	35		30		—		—
Short-to-intermediate fixed income securities	13		14		72		72
Alternative investments	15		17		9		9
Cash	2		2		4		4
Total	100	%	100	%	100	%	100	%

Change in Projected Benefit Obligation

	Pension Benefits				Postretirement Benefits
(Millions of Dollars)	2020		2019		2020		2019
Change in Benefit Obligation:
Obligation at Jan. 1	$	1,330	$	1,229	$	380	$	377
Service cost	30		26		1		1
Interest cost	46		52		13		16
Plan amendments	—		—		—		—
Actuarial loss	102		108		52		12
Plan participants’ contributions	—		—		6		7
Medicare subsidy reimbursements	—		—		1		1
Benefit payments	(80)		(85)		(38)		(34)
Obligation at Dec. 31	$	1,428	$	1,330	$	415	$	380
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	1,124	$	966	$	401	$	372
Actual return on plan assets	189		197		32		52
Employer contributions	50		46		3		4
Plan participants’ contributions	—		—		6		7
Benefit payments	(80)		(85)		(38)		(34)
Fair value of plan assets at Dec. 31	$	1,283	$	1,124	$	404	$	401
Funded status of plans at Dec. 31	$	(145)	$	(206)	$	(11)	$	21
Amounts recognized in the Consolidated Balance Sheet at Dec. 31:
Noncurrent liabilities	(145)		(206)		(11)		21
Net amounts recognized	$	(145)	$	(206)	$	(11)	$	21

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)	2020		2019		2020		2019
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	432	$	482	$	81	$	45
Prior service credit	(1)		(4)		(6)		(10)
Total	$	431	$	478	$	75	$	35
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	$	25	$	22	$	—	$	—
Noncurrent regulatory assets	404		452		75		35
Deferred income taxes	1		1		—		—
Net-of-tax accumulated other comprehensive income	1		3		—		—
Total	$	431	$	478	$	75	$	35

Measurement date Dec. 31, 2020 Dec. 31, 2019 Dec. 31, 2020 Dec. 31, 2019

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 (expense) income 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)	2020			2019			2018			2020			2019			2018
Service cost	$	30		$	26		$	29		$	—		$	1		$	1
Interest cost	46			52			47			13			15			15
Expected return on plan assets	(70)			(69)			(69)			(17)			(19)			(23)
Amortization of prior service credit	(3)			(3)			(3)			(4)			(5)			(6)
Amortization of net loss	30			25			31			1			3			4
Settlement charge (a)	—			3			5			—			—			—
Net periodic pension cost (credit)	33			34			40			(7)			(5)			(9)
Effects of regulation	4			4			(4)			3			1			2
Net benefit cost (credit) recognized for financial reporting	$	37		$	38		$	36		$	(4)		$	(4)		$	(7)
Significant Assumptions Used to Measure Costs:
Discount rate	3.49		%	4.31		%	3.63		%	3.47		%	4.32		%	3.62		%
Expected average long-term increase in compensation level	3.75			3.75			3.75			N/A			N/A			N/A
Expected average long-term rate of return on assets	6.84			6.84			6.84			4.50			4.50			5.30

(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 2019 and 2018, as a result of lump-sum distributions during each plan year, PSCo recorded a total pension settlement charge of $3 million and $5 million, respectively. An immaterial amount was recorded in the income statement in 2019 and 2018. There were no settlement charges recorded to the qualified pension plans in 2020.

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
2021	$	83	$	31	$	2	$	29
2022	83		31		2		29
2023	82		30		2		28
2024	82		30		2		28
2025	82		29		2		27
2026-2030	393		130		12		118

XML

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2020

Commitments and Contingencies Disclosure [Abstract]

Operating and Finance Lease Commitments, Maturity

Commitments under operating and finance leases as of Dec. 31, 2020:

(Millions of Dollars)	PPA (a) (b) Operating Leases		Other Operating Leases		Total Operating Leases		Finance Leases
2021	$	101	$	15	$	116	$	24
2022	84		15		99		21
2023	70		10		80		20
2024	63		10		73		20
2025	63		5		68		19
Thereafter	163		12		175		381
Total minimum obligation	544		67		611		485
Interest component of obligation	(74)		(8)		(82)		(352)
Present value of minimum obligation	$	470	$	59	529		133
Less current portion					(97)		(7)
Noncurrent operating and finance lease liabilities					$	432	$	126
Weighted-average remaining lease term in years					7.1		38.0

(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.

Assets and Liabilities, Lessee [Table Text Block]

Operating lease ROU assets:

(Millions of Dollars)	Dec. 31, 2020		Dec. 31, 2019
PPAs	$	591	$	585
Other	68		69
Gross operating lease ROU assets	659		654
Accumulated amortization	(159)		(80)
Net operating lease ROU assets	$	500	$	574

Finance lease ROU assets:

(Millions of Dollars)	Dec. 31, 2020		Dec. 31, 2019
Gas storage facilities	$	201	$	200
Gas pipeline	21		21
Gross finance lease ROU assets	222		221
Accumulated amortization	(90)		(82)
Net finance lease ROU assets	$	132	$	139

Estimated Minimum Purchases Under Fuel Contracts

Estimated minimum purchases under these contracts as of Dec. 31, 2020:

(Millions of Dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2021	$	132	$	354	$	116
2022	61		119		115
2023	22		54		67
2024	22		3		37
2025	23		—		36
Thereafter	47		—		475
Total	$	307	$	530	$	846

Estimated Future Payments for Capacity and Energy Pursuant to Purchased Power Agreements

At Dec. 31, 2020, 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
2021	$	3
2022	3
2023	3
2024	3
2025	3
Thereafter	5
Total	$	20

Asset Retirement Obligations

PSCo’s AROs were as follows:

	2020
(Millions  of Dollars)	Jan. 1, 2020		Amounts Incurred (a)		Amounts Settled (b)		Accretion		Cash Flow Revisions (c)		Dec. 31, 2020
Electric
Steam, hydro and other production	$	100	$	—	$	—	$	4	$	33	$	137
Wind	16		26		(3)		1		—		40
Distribution	14		—		—		1		—		15
Natural gas
Transmission and distribution	190		—		—		8		5		203
Miscellaneous	3		—		—		—		—		3
Common
Miscellaneous	1		—		—		—		—		1
Total liability	$	324	$	26	$	(3)	$	14	$	38	$	399

(a)Amounts incurred related to the Cheyenne Ridge wind farm placed in service in 2020.

(b)Amounts settled related to removal of wind facilities.

(c)In 2020, 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 ash containment facilities.

	2019
(Millions  of Dollars)	Jan. 1, 2019		Accretion		Cash Flow Revisions (a)		Dec. 31, 2019 (b)
Electric
Steam, hydro and other production	$	102	$	5	$	(7)	$	100
Wind	14		1		1		16
Distribution	13		1		—		14
Miscellaneous	3		—		(3)		—
Natural gas
Transmission and distribution	201		9		(20)		190
Miscellaneous	4		—		(1)		3
Common
Miscellaneous	1		—		—		1
Total liability	$	338	$	16	$	(30)	$	324

(a)In 2019, AROs were revised for changes in timing and estimates of cash flows. Changes in gas transmission and distribution AROs were primarily related to increased gas line mileage and number of services, which were more than offset by decreased inflation rates. Revisions in steam, hydro, and other production AROs primarily related to changes in cost estimates for pond remediation.

(b)There were no ARO amounts incurred or settled in 2019.

Lease, Cost [Table Text Block]

Components of lease expense:

(Millions of Dollars)	2020		2019		2018
Operating leases
PPA capacity payments	$	100	$	98	$	97
Other operating leases (a)	13		14		14
Total operating lease expense (b)	$	113	$	112	$	111
Finance leases
Amortization of ROU assets	$	7	$	6	$	6
Interest expense on lease liability	18		19		19
Total finance lease expense	$	25	$	25	$	25

(a)Includes short-term lease expense of $1 million, $2 million and $1 million for 2020, 2019 and 2018, respectively.

(b)PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income. Expense for other operating leases is included in O&M expense and electric fuel and purchased power.

XML

Other Comprehensive Income (Tables)

12 Months Ended

Dec. 31, 2020

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:

	2020
(Millions of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(24)		$	(3)		$	(27)
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $— and $—, respectively)	1		(a)	—			1
Amortization of net actuarial loss (net of taxes of $— and $1, respectively)	—			2		(b)	2
Net current period other comprehensive income (loss)	1			2			3
Accumulated other comprehensive loss at Dec. 31	$	(23)		$	(1)		$	(24)

(a)Included in interest charges.

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

	2019
(Millions of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(26)		$	—		$	(26)
Losses (gains) reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $— and $—, respectively)	2		(a)	—			2
Amortization of net actuarial gains (net of taxes of $— and $(1), respectively)	—			(3)		(b)	(3)
Net current period other comprehensive income	2			(3)			(1)
Accumulated other comprehensive loss at Dec. 31	$	(24)		$	(3)		$	(27)

(a)Included in interest charges.

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

XML

Segments and Related Information (Tables)

12 Months Ended

Dec. 31, 2020

Segment Reporting [Abstract]

Results from Operations by Reportable Segment

PSCo’s segment information:

(Millions of Dollars)	2020		2019		2018
Regulated Electric
Operating revenues - external	$	3,116	$	3,033	$	3,031
Intersegment revenue	1		1		—
Total revenues	$	3,117	$	3,034	$	3,031
Depreciation and amortization	497		455		416
Interest charges and financing costs	173		173		142
Income tax expense	13		45		103
Net income	460		465		429
Regulated Natural Gas
Operating revenues - external	$	1,024	$	1,161	$	1,015
Intersegment revenue	—		—		1
Total revenues	$	1,024	$	1,161	$	1,016
Depreciation and amortization	152		141		140
Interest charges and financing costs	50		50		43
Income tax expense	29		33		13
Net income	126		119		121
All Other
Total revenues (a)	$	43	$	43	$	40
Depreciation and amortization	6		6		5
Interest charges and financing costs	1		1		1
Income tax expense (benefit)	3		2		(3)
Net income (loss)	2		(6)		2
Consolidated Total
Total revenues (a)	$	4,184	$	4,238	$	4,087
Reconciling eliminations	(1)		(1)		(1)
Total operating revenues	$	4,183	$	4,237	$	4,086
Depreciation and amortization	655		602		561
Interest charges and financing costs	224		224		186
Income tax expense	45		80		113
Net income	588		578		552

(a)    Operating revenues include $5 million, $5 million and $4 million of intercompany revenue for the years ended Dec. 31, 2020, 2019 and 2018, respectively. See Note 13 for further information.

XML

Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2020

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)	2020		2019		2018
Operating revenues:
Other	$	5	$	5	$	4
Operating expenses:
Other operating expenses — paid to Xcel Energy Services Inc.	571		532		519

Accounts receivable and payable with affiliates at Dec. 31:

	2020				2019
(Millions of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Minnesota	$	—	$	1	$	19	$	—
NSP-Wisconsin	—		1		—		—
SPS	—		6		—		—
Other subsidiaries of Xcel Energy Inc.	8		50		34		44
	$	8	$	58	$	53	$	44

XML

Summarized Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2020

Quarterly Financial Information Disclosure [Abstract]

Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended
(Millions of Dollars)	March 31, 2020		June 30, 2020		Sept. 30, 2020		Dec. 31, 2020
Operating revenues	$	1,057	$	911	$	1,081	$	1,134
Operating income	196		161		290		176
Net income	129		108		218		133

	Quarter Ended
(Millions of Dollars)	March 31, 2019		June 30, 2019		Sept. 30, 2019		Dec. 31, 2019
Operating revenues	$	1,223	$	910	$	1,044	$	1,060
Operating income	210		163		284		200
Net income	139		102		204		133

XML

Summary of Significant Accounting Policies (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
Depreciation expense expressed as a percentage of average depreciable property	3.10%	2.90%	2.60%
Cash and Cash Equivalents [Abstract]
Maximum number of months of remaining maturity at time of purchase to consider investments in certain instruments as cash equivalents	three months
Accounts and Financing Receivable, after Allowance for Credit Loss, Current and Noncurrent [Abstract]
Accounts Receivable, Allowance for Credit Loss, Current	$ 29	$ 21
Alternative Revenue Programs [Abstract]
Maximum number of months following end of annual period in which revenues are earned to be included in incentive programs	24 months
Number of DSM Products, Commercial and Industrial Customers	20
Number of DSM Products, Residential and Low-income Customers	23
DSM Measurements	1,000
Public Utilities, Inventory [Line Items]
Inventories	$ 189	192
Materials and supplies
Public Utilities, Inventory [Line Items]
Inventories	63	63
Public Utilities, Inventory, Fuel [Member]
Public Utilities, Inventory [Line Items]
Inventories	73	77
Public Utilities, Inventory, Natural Gas [Member]
Public Utilities, Inventory [Line Items]
Inventories	$ 53	$ 52

XML

Accounting Pronouncements - Recently Adopted (Details) - USD ($) $ in Millions		12 Months Ended
	Jan. 01, 2020	Dec. 31, 2020
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Credit Losses, Topic 326 (ASC Topic 326)		$ 1
Retained Earnings
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Credit Losses, Topic 326 (ASC Topic 326)	$ 1	$ 1

XML

Property Plant and Equipment Property Plant and Equipment (Details) - USD ($) $ in Millions		Dec. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment [Line Items]
Property, plant and equipment		$ 22,699	$ 21,279
Accumulated depreciation		5,229	5,124
Property, plant and equipment, net		17,470	16,155
Electric plant
Property, Plant and Equipment [Line Items]
Property, plant and equipment		15,736	14,362
Natural gas plant
Property, Plant and Equipment [Line Items]
Property, plant and equipment		5,037	4,631
Common and other property
Property, Plant and Equipment [Line Items]
Property, plant and equipment		1,191	1,113
Plant to be retired
Property, Plant and Equipment [Line Items]
Property, plant and equipment	[1]	225	260
CWIP
Property, Plant and Equipment [Line Items]
Property, plant and equipment		$ 510	$ 913

[1] Includes regulator-approved retirements of Comanche Units 1 and 2 and jointly owned Craig Unit 1. Also includes PSCo’s planned retirement of jointly owned Craig Unit 2.

XML

Property Plant and Equipment Joint Ownership (Details) $ in Millions	Dec. 31, 2020 USD ($)
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 1,595
Accumulated Depreciation	465
CWIP	18
Electric Generation | Hayden Unit 1
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	153
Accumulated Depreciation	92
CWIP	$ 0
Percent Owned	76.00%
Electric Generation | Hayden Unit 2
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 150
Accumulated Depreciation	73
CWIP	$ 0
Percent Owned	37.00%
Electric Generation | Hayden Common Facilities
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 42
Accumulated Depreciation	25
CWIP	$ 0
Percent Owned	53.00%
Electric Generation | Craig Units 1 and 2
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 81
Accumulated Depreciation	44
CWIP	$ 0
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	24
CWIP	$ 0
Percent Owned	7.00%
Electric Generation | Comanche Unit 3
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 899
Accumulated Depreciation	137
CWIP	$ 16
Percent Owned	67.00%
Electric Generation | Comanche Common Facilities
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 25
Accumulated Depreciation	2
CWIP	$ 0
Percent Owned	82.00%
Electric Transmission | Transmission and Other Facilities
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 176
Accumulated Depreciation	59
CWIP	2
Gas Transportation | Rifle to Avon
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	22
Accumulated Depreciation	8
CWIP	$ 0
Percent Owned	60.00%
Gas Transportation | Gas Transportation Compressor
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 8
Accumulated Depreciation	1
CWIP	$ 0
Percent Owned	50.00%

XML

Regulatory Assets and Liabilities, Regulatory Assets (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 121	$ 64
Regulatory Asset, Noncurrent		1,059	1,038
Regulatory assets not currently earning a return		195	160
Pension and Retiree Medical Obligations
Regulatory Assets [Line Items]
Regulatory Asset, Current		28	23
Regulatory Asset, Noncurrent		478	494
Depreciation differences
Regulatory Assets [Line Items]
Regulatory Asset, Current		16	15
Regulatory Asset, Noncurrent		$ 154	140
Depreciation differences | Minimum
Regulatory Assets [Line Items]
Regulatory Asset, Amortization Period		1 year
Depreciation differences | Maximum
Regulatory Assets [Line Items]
Regulatory Asset, Amortization Period		11 years
Net AROs
Regulatory Assets [Line Items]
Regulatory Asset, Current	[1]	$ 0	0
Regulatory Asset, Noncurrent	[1]	132	119
Recoverable Deferred Taxes on AFUDC Recorded in Plant
Regulatory Assets [Line Items]
Regulatory Asset, Current		0	0
Regulatory Asset, Noncurrent		110	105
Excess deferred taxes - TCJA
Regulatory Assets [Line Items]
Regulatory Asset, Current		3	3
Regulatory Asset, Noncurrent		56	55
Purchased Power Agreements
Regulatory Assets [Line Items]
Regulatory Asset, Current		3	2
Regulatory Asset, Noncurrent		22	24
Property Tax
Regulatory Assets [Line Items]
Regulatory Asset, Current		16	1
Regulatory Asset, Noncurrent		21	30
Conservation programs
Regulatory Assets [Line Items]
Regulatory Asset, Current	[2]	11	8
Regulatory Asset, Noncurrent	[2]	$ 11	11
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
Gas pipeline inspection costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 0	0
Regulatory Asset, Noncurrent		$ 9	8
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
Losses on Reacquired Debt
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 1	1
Regulatory Asset, Noncurrent		3	4
Contract Valuation Adjustments
Regulatory Assets [Line Items]
Regulatory Asset, Current	[3]	6	3
Regulatory Asset, Noncurrent	[3]	0	0
Recoverable Purchased Natural Gas and Electric Energy Costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		6	0
Regulatory Asset, Noncurrent		0	0
Other
Regulatory Assets [Line Items]
Regulatory Asset, Current		31	8
Regulatory Asset, Noncurrent		$ 63	$ 48

[1] Includes amounts recorded for future recovery of AROs.

[2] Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

[3] Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.

XML

Regulatory Assets and Liabilities, Regulatory Liabilities (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 100	$ 69
Regulatory Liability, Noncurrent		2,337	2,037
Deferred Income Tax Adjustments and TCJA Refunds
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[1]	5	5
Regulatory Liability, Noncurrent	[1]	1,368	1,403
Plant Removal Costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		0	0
Regulatory Liability, Noncurrent		615	351
Effects of regulation on employee benefit costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[2]	0	0
Regulatory Liability, Noncurrent	[2]	203	183
Renewable Resources and Environmental Initiatives
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		0	0
Regulatory Liability, Noncurrent		59	45
Sales True Up and Revenue Decoupling [Member]
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		10	0
Regulatory Liability, Noncurrent		$ 41	0
Sales True Up and Revenue Decoupling [Member] | Minimum
Regulatory Liabilities [Line Items]
Regulatory Liability, Amortization Period		1 year
Sales True Up and Revenue Decoupling [Member] | Maximum
Regulatory Liabilities [Line Items]
Regulatory Liability, Amortization Period		2 years
ITC Deferrals
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 0	0
Regulatory Liability, Noncurrent		40	26
Conservation programs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[3]	39	30
Regulatory Liability, Noncurrent	[3]	0	0
Deferred Electric, Gas, and Steam Production Costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		17	8
Regulatory Liability, Noncurrent		0	0
Other
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		29	26
Regulatory Liability, Noncurrent		$ 11	$ 29

[1] Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA.

[2] Includes regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the prepaid pension asset.

[3] Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

XML

Borrowings and Other Financing Instruments, Short-Term Borrowings (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Short-term Debt [Line Items]
Short-term debt	$ 136	$ 136	$ 0
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	136	136	0	307
Average amount outstanding	$ 8	$ 30	$ 154	$ 55
Weighted average interest rate at period end (percentage)	0.20%	0.20%		2.95%
Line of Credit Facility, Interest Rate During Period	0.19%	1.59%	2.67%	2.28%
Maximum amount outstanding	$ 136	$ 230	$ 432	$ 309
Money Pool
Short-term Debt [Line Items]
Borrowing limit	250	250	250	250
Short-term debt	57	57	39	0
Average amount outstanding	$ 104	$ 59	$ 7	$ 25
Weighted average interest rate at period end (percentage)	0.07%	0.07%	1.63%
Line of Credit Facility, Interest Rate During Period	0.08%	0.60%	2.29%	1.93%
Maximum amount outstanding	$ 218	$ 250	$ 50	$ 156

XML

Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 136	$ 0
Letter of Credit
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 8	$ 9
Letter of Credit
Line of Credit Facility [Line Items]
Line of Credit Facility, Expiration Period	1 year

XML

Borrowings and Other Financing Instruments, Credit Facility (Details) - Credit Facility $ in Millions	12 Months Ended
	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Line of Credit Facility [Line Items]
Line Of Credit Facility Debt To Total Capitalization Ratio (as a percent)	44.00%	44.00%
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval	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	700
Drawn	144
Available	$ 556
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

XML

Borrowings and Other Financing Instruments, Long-Term Borrowings (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net	$ (30)	$ (24)
Unamortized Debt Issuance Expense	(46)	(41)
Long-term Debt, Current Maturities	0	(400)
Long-term Debt	5,724	4,985
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	0
Long-term Debt, Maturities, Repayments of Principal in Year Two	300
Long-term Debt, Maturities, Repayments of Principal in Year Three	250
Long-term Debt, Maturities, Repayments of Principal in Year Four	0
Long-term Debt, Maturities, Repayments of Principal in Year Five	250
Deferred Finance Costs, Noncurrent, Net	46	41
First Mortgage Bonds | Series Due Nov. 15, 2020 [Member]
Debt Instrument [Line Items]
Face amount	$ 0	400
Interest rate, stated percentage (in hundredths)	3.20%
First Mortgage Bonds | Series Due Sept. 15, 2022 [Member]
Debt Instrument [Line Items]
Face amount	$ 300	300
Interest rate, stated percentage (in hundredths)	2.25%
First Mortgage Bonds | Series Due March 15, 2023 [Member]
Debt Instrument [Line Items]
Face amount	$ 250	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	0
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	0
Interest rate, stated percentage (in hundredths)	2.70%
Long-term Debt
Debt Instrument [Line Items]
Long-term Debt	$ 5,724	$ 4,985

XML

Borrowings and Other Financing Instruments Preferred Stock (Details) - PSCo [Member] - $ / shares	Dec. 31, 2020	Dec. 31, 2019
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

XML

Revenues (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Retail
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	$ 3,547	$ 3,705	$ 3,465
Retail | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	1,735	1,767	1,608
Retail | C&I
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	1,764	1,888	1,809
Retail | Other
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	48	50	48
Wholesale
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	212	166	175
Transmission
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	62	52	54
Other
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	181	139	139
Total revenue from contracts with customers
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	4,002	4,062	3,833
Alternative revenue and other
Disaggregation of Revenue [Line Items]
Alternative revenue and other	181	175	253
Regulated Electric | Retail
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	2,633	2,635	2,599
Regulated Electric | Retail | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	1,073	1,006	991
Regulated Electric | Retail | C&I
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	1,512	1,579	1,560
Regulated Electric | Retail | Other
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	48	50	48
Regulated Electric | Wholesale
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	212	166	175
Regulated Electric | Transmission
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	62	52	54
Regulated Electric | Other
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	56	32	55
Regulated Electric | Total revenue from contracts with customers
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	2,963	2,885	2,883
Regulated Electric | Alternative revenue and other
Disaggregation of Revenue [Line Items]
Alternative revenue and other	153	148	148
Regulated Natural Gas | Retail
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	875	1,031	830
Regulated Natural Gas | Retail | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	650	750	606
Regulated Natural Gas | Retail | C&I
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	225	281	224
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	125	107	84
Regulated Natural Gas | Total revenue from contracts with customers
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	1,000	1,138	914
Regulated Natural Gas | Alternative revenue and other
Disaggregation of Revenue [Line Items]
Alternative revenue and other	24	23	101
All Other | Retail
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	39	39	36
All Other | Retail | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	12	11	11
All Other | Retail | C&I
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	27	28	25
All Other | Retail | Other
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	0	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	39	39	36
All Other | Alternative revenue and other
Disaggregation of Revenue [Line Items]
Alternative revenue and other	4	4	4
Operating Segments
Disaggregation of Revenue [Line Items]
Total revenues	4,183	4,237	4,086
Operating Segments | Regulated Electric
Disaggregation of Revenue [Line Items]
Total revenues	3,116	3,033	3,031
Operating Segments | Regulated Natural Gas
Disaggregation of Revenue [Line Items]
Total revenues	1,024	1,161	1,015
Operating Segments | All Other
Disaggregation of Revenue [Line Items]
Total revenues	$ 43	$ 43	$ 40

XML

Income Taxes (Details) - USD ($)		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019		Dec. 31, 2018	Dec. 31, 2020	Jan. 01, 2020	Dec. 31, 2019		Jan. 01, 2019	Dec. 31, 2018	Jan. 01, 2018
Income Tax Examination [Line Items]
Present value of minimum obligation						$ 529,000,000
Tax Credit Valuation Allowance		$ (8,000,000)	$ (8,000,000)	[1]
Income tax expense (benefit)		45,000,000	80,000,000		$ 113,000,000
Deferred tax expense (benefit) excluding selected items		46,000,000	132,000,000		75,000,000
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities		(43,000,000)	(35,000,000)		(51,000,000)
Income Tax Expense (Benefit), Intraperiod Tax Allocation		(1,000,000)	$ 0		$ 0
Deferred Tax Assets, Tax Deferred Expense						2,000,000		$ 97,000,000			$ 24,000,000
Tax Credit Carryforward, Amount						143,000,000		83,000,000
Potential Tax Adjustments		$ 0
Federal detriment						5,000,000		5,000,000
Federal Benefit						2,000,000		2,000,000
Deferred Tax Assets, Operating Loss Carryforwards, State and Local						190,000,000		388,000,000
state tax credit carryforward, net of federal detirment	[2]					18,000,000		18,000,000
valuation allowances for state credit carryforwards, net of federal benefit	[3]					(8,000,000)		(8,000,000)
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		21.00%	21.00%		21.00%
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent		3.60%	3.60%		3.70%
Effective Income Tax Rate Reconciliation, Tax Credit, Percent		10.30%	7.50%		0.60%
Effective Income Tax Rate Reconciliation, Other Regulatory Items, Percent	[4]	(5.00%)	(3.30%)		(4.50%)
Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent		(1.10%)	(1.30%)		(0.60%)
Amortization of excess nonplant deferred taxes		(0.20%)	(0.20%)		(1.40%)
Effective Income Tax Rate Reconcilation, Change in unrecognized tax benefits, percent		(0.20%)	0.30%		0.10%
Effective Income Tax Rate Reconciliation, Other Adjustments, Percent		(0.70%)	(0.40%)		(0.70%)
Effective Income Tax Rate Reconciliation, Percent		7.10%	12.20%		17.00%
Tax Audits [Abstract]
Tax Credit Carryforward, Amount						143,000,000		83,000,000
Federal detriment						5,000,000		5,000,000
Potential Federal Tax Adjustments		$ 0
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Allowance for Doubtful Accounts						8,000,000		5,000,000	[1]
Payable for interest related to unrecognized tax benefits						0	$ (1,000,000)	(1,000,000)		$ (1,000,000)	(1,000,000)	$ 0
Unrecognized Tax Benefits, Interest on Income Taxes Expense		(1,000,000)	$ 0		$ (1,000,000)
Unrecognized tax benefit — Permanent tax positions						7,000,000		7,000,000
Unrecognized Tax Benefits That Would Not Impact Effective Tax Rate						2,000,000		5,000,000
Unrecognized Tax Benefits		12,000,000	10,000,000		10,000,000	9,000,000	12,000,000	12,000,000		10,000,000	10,000,000	10,000,000
Unrecognized Tax Benefits, Income Tax Penalties Expense		0	0		0
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions		2,000,000	1,000,000		1,000,000
Unrecognized Tax Benefits Increases Resulting From Prior Period Tax Positions		6,000,000	1,000,000		0
Unrecognized Tax Benefits, Decrease Resulting from Prior Period Tax Positions		11,000,000	0		0
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities		0	0		1,000,000
Unrecognized Tax Benefits [Abstract]
Unrecognized tax benefit — Permanent tax positions						7,000,000		7,000,000
Unrecognized tax benefit — Temporary tax positions						2,000,000		5,000,000
Total unrecognized tax benefit		12,000,000	10,000,000		10,000,000	9,000,000	$ 12,000,000	12,000,000		$ 10,000,000	10,000,000	$ 10,000,000
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at Jan. 1		12,000,000	10,000,000
Unrecognized Tax Benefits Increases Resulting From Prior Period Tax Positions		6,000,000	1,000,000		0
Unrecognized Tax Benefits Decreases Resulting From Prior Period Tax Positions		(11,000,000)	0		0
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities		0	0		(1,000,000)
Balance at Dec. 31		$ 9,000,000	$ 12,000,000		$ 10,000,000
Tax Benefits Associated With Nol And Tax Credit Carryforwards [Abstract]
NOL and tax credit carryforwards						(8,000,000)		(8,000,000)
Net Deferred Tax Liability associated with the Unrecognized Tax Benefit Amounts and Related NOLs and Tax Credit Carryforwards						(6,000,000)		(5,000,000)
Deferred Tax Assets, Operating Loss Carryforwards, State and Local						190,000,000		388,000,000
state tax credit carryforward, net of federal detirment	[2]					18,000,000		18,000,000
valuation allowances for state credit carryforwards, net of federal benefit	[3]					(8,000,000)		(8,000,000)
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Allowance for Doubtful Accounts						8,000,000		5,000,000	[1]
Upper bound of decrease in unrecognized tax benefit that is reasonably possible						3,000,000
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		21.00%	21.00%		21.00%
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent		3.60%	3.60%		3.70%
Effective Income Tax Rate Reconciliation, Tax Credit, Percent		(10.30%)	(7.50%)		(0.60%)
Effective Income Tax Rate Reconciliation, Other Regulatory Items, Percent	[4]	5.00%	3.30%		4.50%
Amortization of excess nonplant deferred taxes		(0.20%)	(0.20%)		(1.40%)
Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent		1.10%	1.30%		0.60%
Effective Income Tax Rate Reconciliation, Other Adjustments, Percent		(0.70%)	(0.40%)		(0.70%)
Effective Income Tax Rate Reconcilation, Change in unrecognized tax benefits, percent		(0.20%)	0.30%		0.10%
Effective Income Tax Rate Reconciliation, Percent		7.10%	12.20%		17.00%
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Income Tax Expense (Benefit)		$ 45,000,000	$ 80,000,000		$ 113,000,000
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred tax expense (benefit) excluding selected items		46,000,000	132,000,000		75,000,000
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities		(43,000,000)	(35,000,000)		(51,000,000)
Income Tax Expense (Benefit), Intraperiod Tax Allocation		(1,000,000)	0		0
Deferred Tax Assets, Tax Deferred Expense						2,000,000		97,000,000			24,000,000
Valuation Allowance [Line Items]
Present value of minimum obligation						529,000,000
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Allowance for Doubtful Accounts						8,000,000		5,000,000	[1]
Tax Credit Valuation Allowance		(8,000,000)	(8,000,000)	[1]
Deferred Tax Assets, Tax Deferred Expense						2,000,000		97,000,000			$ 24,000,000
Net Deferred Tax Liablility [Member]
Income Tax Examination [Line Items]
Differences between book and tax basis of property		2,132,000,000	2,039,000,000	[1]
Regulatory Assets						257,000,000		253,000,000	[1]
Operating Lease Assets						129,000,000		148,000,000	[1]
Deferred tax liability - Pension expense						19,000,000		22,000,000	[1]
Deferred Tax Assets, Tax Deferred Expense, Other						6,000,000		7,000,000	[1]
Deferred Tax Liabilities, Tax Deferred Income						2,543,000,000		2,469,000,000	[1]
Regulatory liabilities						319,000,000		327,000,000	[1]
Present value of minimum obligation						129,000,000		148,000,000	[1]
Deferred ITCs		5,000,000	6,000,000	[1]
Deferred Tax Assets, Other						25,000,000		25,000,000	[1]
Deferred Tax Liabilities, Net						1,897,000,000		1,851,000,000	[1]
Deferred Tax Assets, Tax Deferred Expense						646,000,000		618,000,000	[1]
Deferred Tax Assets, Operating Loss Carryforwards						161,000,000		101,000,000	[1]
Tax Audits [Abstract]
Operating Loss Carryforwards						7,000,000		14,000,000	[1]
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred Tax Assets, Tax Deferred Expense						646,000,000		618,000,000	[1]
Valuation Allowance [Line Items]
Differences between book and tax basis of property		2,132,000,000	2,039,000,000	[1]
Regulatory Assets						257,000,000		253,000,000	[1]
Operating Lease Assets						129,000,000		148,000,000	[1]
Deferred tax liability - Pension expense						19,000,000		22,000,000	[1]
Deferred Tax Assets, Tax Deferred Expense, Other						6,000,000		7,000,000	[1]
Deferred Tax Liabilities, Tax Deferred Income						2,543,000,000		2,469,000,000	[1]
Regulatory liabilities						319,000,000		327,000,000	[1]
Deferred Tax Assets, Operating Loss Carryforwards						161,000,000		101,000,000	[1]
Present value of minimum obligation						129,000,000		148,000,000	[1]
Operating Loss Carryforwards						7,000,000		14,000,000	[1]
Deferred ITCs		5,000,000	6,000,000	[1]
Deferred Tax Assets, Other						25,000,000		25,000,000	[1]
Deferred Tax Assets, Tax Deferred Expense						646,000,000		618,000,000	[1]
Deferred Tax Liabilities, Net						$ 1,897,000,000		$ 1,851,000,000	[1]
income tax expense [Member]
Income Tax Examination [Line Items]
Deferred ITCs		(2,000,000)	(2,000,000)		3,000,000
Current Federal Tax Expense (Benefit)		44,000,000	(9,000,000)		79,000,000
Current State and Local Tax Expense (Benefit)		4,000,000	(5,000,000)		14,000,000
Current Change In Unrecognized Tax Expense (Benefit)		(3,000,000)	(1,000,000)		(1,000,000)
Deferred Federal Income Tax Expense (Benefit)		(26,000,000)	61,000,000		5,000,000
Deferred State and Local Income Tax Expense (Benefit)		26,000,000	33,000,000		17,000,000
Deferred Change In Unrecognized Tax Expense (Benefit)		2,000,000	3,000,000		2,000,000
Income tax expense (benefit)		45,000,000	80,000,000		113,000,000
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current Federal Tax Expense (Benefit)		44,000,000	(9,000,000)		79,000,000
Current State and Local Tax Expense (Benefit)		4,000,000	(5,000,000)		14,000,000
Current Change In Unrecognized Tax Expense (Benefit)		(3,000,000)	(1,000,000)		(1,000,000)
Deferred Federal Income Tax Expense (Benefit)		(26,000,000)	61,000,000		5,000,000
Deferred State and Local Income Tax Expense (Benefit)		26,000,000	33,000,000		17,000,000
Deferred Change In Unrecognized Tax Expense (Benefit)		2,000,000	3,000,000		2,000,000
Income Tax Expense (Benefit)		45,000,000	80,000,000		113,000,000
Valuation Allowance [Line Items]
Deferred ITCs		$ (2,000,000)	$ (2,000,000)		$ 3,000,000

[1] Prior periods have been reclassified to conform to current year presentation.

[2] State tax credit carryforwards are net of federal detriment of $5 million as of both Dec. 31, 2020 and 2019.

[3] Valuation allowances for state tax credit carryforwards were net of federal benefit of $2 million as of both Dec. 31, 2020 and 2019.

[4] Regulatory differences for income tax primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit of excess deferred credits are offset by corresponding revenue reductions and additional prepaid pension asset amortization.

XML

Interest Rate Derivatives (Details) $ in Millions	Dec. 31, 2020 USD ($)
Interest Rate Swap
Derivative [Line Items]
Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net	$ 1

XML

Commodity Derivatives (Details) MWh in Millions, MMBTU in Millions, $ in Millions		Dec. 31, 2020 USD ($) MMBTU MWh	Dec. 31, 2019 MMBTU MWh
Derivative [Line Items]
Cash Flow Hedges Derivative Instruments at Fair Value, Net | $		$ 0
Electric Commodity
Derivative [Line Items]
Notional Amount | MWh	[1],[2]	17	9
Natural Gas Commodity
Derivative [Line Items]
Notional Amount | MMBTU	[1],[2]	93	32

[1] Not reflective of net positions in the underlying commodities.

[2] Notional amounts for options included on a gross basis, but are weighted for the probability of exercise.

XML

Consideration of Credit Risk and Concentrations (Details) - Credit Concentration Risk $ in Millions	Dec. 31, 2020 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	7
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 | $	$ 99
Percentage of wholesale, trading and non trading commodity credit exposure for the most significant counterparties	66.00%
No Investment Grade Ratings from External Credit Rating Agencies
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 | $	$ 19
Percentage of wholesale, trading and non trading commodity credit exposure for the most significant counterparties	13.00%
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	2
Wholesale, trading and non trading commodity credit exposure for the most significant counterparties | $	$ 19
Percentage of wholesale, trading and non trading commodity credit exposure for the most significant counterparties	13.00%

XML

Qualifying Cash Flow Hedges (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020		Dec. 31, 2019		Dec. 31, 2018
Financial Impact of Qualifying Cash Flow Hedges on Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax, Beginning Balance	$ (24)		$ (26)		$ (27)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	1		2		1
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax, Ending Balance	(23)		(24)		(26)
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	(10)		(5)		8
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)	(8)		(1)		(4)
Derivative, Gain (Loss) on Derivative, Net	(5)		(1)		0
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	3	[1]	3	[2]	3	[3]
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	(10)		(5)		8
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)	(8)	[4]	(1)	[5]	4	[6]
Derivative, Gain (Loss) on Derivative, Net	(8)	[4]	(4)	[5]	(3)	[6]
Not Designated as Hedging Instrument | Natural Gas Commodity for Electric Generation [Member]
Impact of Derivative Activity [Abstract]
Derivative Instruments Gain (Loss) Reclassified To Regulatory Assets And Liabilities Net	0		0		1
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)		(2)		(1)
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	(1)	[7]	(2)	[8]	(1)	[9]
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 operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.

[2] Recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.

[3] Recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.

[4] Amounts for the year ended Dec. 31, 2020, included no settlement gains or losses on derivatives entered to mitigate natural gas price risk for electric generation recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset or liability, as appropriate. Remaining settlement losses for the years ended Dec. 31, 2020, relate to natural gas operations and are 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 or liability, as appropriate.

[5] Amounts for the year ended Dec. 31, 2019, included no settlement gains or losses on derivatives entered to mitigate natural gas price risk for electric generation recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset or liability, as appropriate. Remaining settlement losses for the years ended Dec. 31, 2019, relate to natural gas operations and are 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 or liability, as appropriate.

[6] Amounts for the year ended Dec. 31, 2018, included $1 million of settlement losses on derivatives entered to mitigate natural gas price risk for electric generation recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset or liability, as appropriate. Remaining settlement losses for the years ended Dec. 31, 2018, relate to natural gas operations and are 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 or liability, as appropriate

[7] Recorded to interest charges.

[8] Recorded to interest charges.

[9] Recorded to interest charges.

XML

Credit Related Contingent Features (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Derivative, Gross Liability Position, Aggregate Fair Value	$ 0	$ 0
Derivative, Gross Liability with Cross Default Position, Aggregate Fair Value	46
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, 2020	Dec. 31, 2019	Dec. 31, 2018
Derivatives, Fair Value [Line Items]
Return Cash Collateral		$ 0	$ 0
Reclaim Cash Collateral		5	3
Commodity Contract
Derivatives, Fair Value [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs, Beginning Balance		(13)	0	$ 0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Settlements		0	(2)	0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings	[1]	(31)	(11)	0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs, Ending Balance		(44)	(13)	0
Transfers Between Levels, Net		0	0	$ 0
Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		49	17
Netting	[2]	(28)	(10)
Derivative Asset, Net		21	7
Fair Value Measured on a Recurring Basis | Other Current Assets | Level 1
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		1	2
Fair Value Measured on a Recurring Basis | Other Current Assets | Level 2
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		47	14
Fair Value Measured on a Recurring Basis | Other Current Assets | Level 3
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		1	1
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Contract
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		43	14
Netting	[2]	(28)	(10)
Derivative Asset, Net		15	4
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	2
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		41	11
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		1	1
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity Contract
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		6	3
Netting	[2]	0	0
Derivative Asset, Net		6	3
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity Contract | Level 1
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		0	0
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity Contract | Level 2
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		6	3
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity Contract | Level 3
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		0	0
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		36	10
Netting	[2]	(20)	(10)
Derivative Asset, Net		16	0
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Level 1
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		1	1
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Level 2
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		27	8
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Level 3
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		8	1
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Contract
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		36	10
Netting	[2]	(20)	(10)
Derivative Asset, Net		16	0
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		1	1
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		27	8
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		8	1
Fair Value Measured on a Recurring Basis | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		60	22
Netting	[2]	(33)	(13)
Derivative Liability, Net		27	9
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Level 1
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		1	2
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Level 2
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		52	20
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Level 3
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		7	0
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Contract
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		54	19
Netting	[2]	(33)	(13)
Derivative Liability, Net		21	6
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	2
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		46	17
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		7	0
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity Contract
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		6	3
Netting	[2]	0	0
Derivative Liability, Net		6	3
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity Contract | Level 1
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		0	0
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity Contract | Level 2
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		6	3
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity Contract | Level 3
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		0	0
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		71	63
Netting	[2]	(20)	(10)
Derivative Liability, Net		51	53
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Level 1
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		1	1
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Level 2
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		24	47
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Level 3
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		46	15
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Contract
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		71	63
Netting	[2]	(20)	(10)
Derivative Liability, Net		51	53
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		1	1
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		24	47
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		$ 46	$ 15

[1] Level 3 losses recognized in earnings are subject to offsetting gains of derivative instruments categorized as levels 1 and 2 in the income statement.

[2] PSCo nets derivative instruments and related collateral on its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2020 and 2019. At Dec. 31, 2020 and 2019, derivative assets and liabilities include no obligations to return cash collateral, respectively. At Dec. 31, 2020 and 2019, derivative assets and liabilities include rights to reclaim cash collateral of $5 million and $3 million, respectively. The 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, 2020	Dec. 31, 2019
Derivatives, Fair Value [Line Items]
Long-term Debt, Gross	$ 5,724	$ 5,385
Level 2
Derivatives, Fair Value [Line Items]
Long-term debt, Fair Value	$ 7,040	$ 6,039

XML

Benefit Plans and Other Postretirement Benefits, Pension Benefits (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Jan. 01, 2020	Jan. 01, 2019
Target Pension Asset Allocations [Abstract]
annual interest crediting rates		$ 2.24	$ 3.11	$ 3.86
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan assets at net asset value		388,000,000	348,000,000
Fair value of plan assets		1,283,000,000	1,124,000,000		$ 1,124,000,000	$ 966,000,000
Pension Benefits [Abstract]
Total benefit obligation		1,428,000,000	1,330,000,000		$ 1,330,000,000	$ 1,229,000,000
Net benefit cost recognized for financial reporting		$ 37,000,000	$ 38,000,000	$ 36,000,000
Minimum number of years historical achieved weighted average annual returns used to determine investment return assumptions (in years)		20 years
Expected average long-term rate of return on assets (as a percent)		6.84%	6.84%	6.84%
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		$ 0	$ (3,000,000)	$ (5,000,000)
Pension Plan [Member] | PSCo [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets			1,124,000,000
Target Pension Asset Allocations [Abstract]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement			(3,000,000)	$ (5,000,000)
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Pension Benefits [Abstract]
Total benefit obligation		3,000,000
Xcel Energy Inc. | Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Pension Benefits [Abstract]
Total benefit obligation		43,000,000	39,000,000
Net benefit cost recognized for financial reporting		6,000,000	4,000,000
Equity Securities [Member] | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan assets at net asset value		0	0
Fair value of plan assets		$ 27,000,000	$ 30,000,000
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)		35.00%	37.00%
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)		35.00%	30.00%
Short-to-intermediate fixed income securities [Member] | Pension Plan [Member]
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)		13.00%	14.00%
Alternative Investments [Member] | Pension Plan [Member]
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)		15.00%	17.00%
Cash | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan assets at net asset value		$ 0	$ 0
Fair value of plan assets		$ 75,000,000	$ 46,000,000
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)	6.38%

XML

Benefit Plans and Other Postretirement Benefits, Fair Value of Pension Plan Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Jan. 01, 2020	Jan. 01, 2019
Pension Plan [Member]
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 1,283	$ 1,124		$ 1,124	$ 966
Plan assets at net asset value	(388)	(348)
Actuarial (gain) loss	102	108
Plan amendments	0	0
Interest cost	46	52	$ 47
Total benefit obligation	1,428	1,330		1,330	1,229
Service cost	30	26	29
Defined Benefit Plan, Benefit Obligation, Benefits Paid	(80)	(85)
Actual return (loss) on plan assets	189	197
Employer contributions	50	46
Defined Benefit Plan, Plan Assets, Benefits Paid	(80)	(85)
Medicare subsidy reimbursements	0	0
Plan participants' contributions	0	0
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant	0	0
Pension Plan [Member] | PSCo [Member]
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		1,124
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	622	532
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	272	242
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	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	75	46
Plan assets at net asset value	0	0
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	75	46
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	0
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	0
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	906	852
Plan assets at net asset value	(388)	(355)
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	518	497
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	0
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	0
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	271	243
Plan assets at net asset value	0	0
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	0
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	270	241
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	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	27	30
Plan assets at net asset value	0	0
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	27	30
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	0
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	0
Pension Plan [Member] | Other
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	4	(47)
Plan assets at net asset value	0	(7)
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	2	(41)
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
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	0
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	404	401		401	372
Plan assets at net asset value	(61)	(68)
Actuarial (gain) loss	52	12
Plan amendments	0	0
Interest cost	13	15	15
Total benefit obligation	415	380		$ 380	$ 377
Service cost	1	1	$ 1
Defined Benefit Plan, Benefit Obligation, Benefits Paid	(38)	(34)
Actual return (loss) on plan assets	32	52
Employer contributions	3	4
Defined Benefit Plan, Plan Assets, Benefits Paid	(38)	(34)
Medicare subsidy reimbursements	1	1
Plan participants' contributions	6	7
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant	6	7
Other Postretirement Benefits Plan [Member] | PSCo [Member]
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Interest cost		16
Service cost	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	88	82
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	255	250
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	0	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	24	20
Plan assets at net asset value	0	0
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	24	20
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	0
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	0
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	125	130
Plan assets at net asset value	(61)	(68)
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	64	62
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	0
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	0
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	207	204
Plan assets at net asset value	0	0
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	0
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	207	203
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	0	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	3	2
Plan assets at net asset value	0	0
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	0
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	3	2
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	$ 0

XML

Benefit Plans and Other Postretirement Benefits, Pension Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2021 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($) Plan	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Postretirement Cash Balance Formula				5.00%
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Utilities Operating Expense, Maintenance, Operations, and Other Costs and Expenses			$ 811.0	$ 810.0	$ 788.0
Significant Assumptions Used to Measure Costs [Abstract]
Liability, Defined Benefit Plan, Noncurrent			161.0	212.0
Other Pension, Postretirement and Supplemental Plans [Member]
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1	$ 3.0	$ 3.0
Obligation at Dec. 31			3.0
Other Pension, Postretirement and Supplemental Plans [Member] | Xcel Energy Inc.
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1	43.0	43.0	39.0
Obligation at Dec. 31			43.0	39.0
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Net benefit cost recognized for financial reporting			6.0	4.0
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated Benefit Obligation at Dec. 31			1,353.0	1,267.0
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1	1,428.0	1,428.0	1,330.0
Service cost			30.0	26.0	29.0
Interest cost			46.0	52.0	47.0
Plan amendments			0.0	0.0
Actuarial (gain) loss			102.0	108.0
Benefit payments			(80.0)	(85.0)
Obligation at Dec. 31			1,428.0	1,330.0
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	1,283.0	$ 1,283.0	1,124.0
Actual return (loss) on plan assets			189.0	197.0
Employer contributions			50.0	46.0
Plan participants' contributions			0.0	0.0
Benefit payments			(80.0)	(85.0)
Fair value of plan assets at Dec. 31			1,283.0	1,124.0
Funded Status of Plans at Dec. 31 [Abstract]
Funded status			145.0	206.0
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss			432.0	482.0
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, Prior Service Cost (Credit), before Tax			(1.0)	(4.0)
Total			431.0	478.0
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			25.0	22.0
Noncurrent regulatory assets			404.0	452.0
Deferred income taxes			1.0	1.0
Net-of-tax accumulated OCI			1.0	3.0
Total			$ 431.0	$ 478.0
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)			2.71%	3.49%
Expected average long-term increase in compensation level (as a percent)			3.75%	3.75%
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost			$ 30.0	$ 26.0	29.0
Interest cost			46.0	52.0	47.0
Expected return on plan assets			(70.0)	(69.0)	(69.0)
Amortization of prior service (credit) cost			(3.0)	(3.0)	(3.0)
Amortization of net loss			30.0	25.0	31.0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement			0.0	(3.0)	(5.0)
Net periodic pension cost			33.0	34.0	40.0
Defined Benefit Plan, Costs Not Recognized Due To Regulation			4.0	4.0	(4.0)
Net benefit cost recognized for financial reporting			$ 37.0	$ 38.0	$ 36.0
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)			3.49%	4.31%	3.63%
Expected average long-term increase in compensation level (as a percent)			3.75%	3.75%	3.75%
Expected average long-term rate of return on assets (as a percent)			6.84%	6.84%	6.84%
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			145.0	206.0
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position			(145.0)	(206.0)
Pension Plan [Member] | PSCo [Member]
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1			1,124.0
Fair value of plan assets at Dec. 31				1,124.0
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period			$ 50.0	46.0	$ 22.0
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement				$ (3.0)	$ (5.0)
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)		6.38%
Pension Plan [Member] | Subsequent Event | PSCo [Member]
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period	$ 45.0

XML

Benefit Plans and Other Postretirement Benefits, Postretirement Health Care Benefits (Details)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
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	2.65%	3.47%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Pre-65	5.50%	6.00%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Post-65	5.00%	5.10%
Ultimate health care trend assumption rate (as a percent)	4.50%	4.50%
Defined Benefit Plan Period Until Ultimate Health Care Trend Rate Is Reached	5	3
Other Postretirement Benefits Plan [Member] | Domestic and international equity securities
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	15.00%	15.00%
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)	72.00%	72.00%
Other Postretirement Benefits Plan [Member] | Alternative investments
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	9.00%	9.00%
Other Postretirement Benefits Plan [Member] | Cash
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	4.00%	4.00%
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	2.71%	3.49%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase	3.75%	3.75%
Pension Plan [Member] | Domestic and international equity securities
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	35.00%	37.00%
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)	35.00%	30.00%
Pension Plan [Member] | Short-to-intermediate fixed income securities
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	13.00%	14.00%
Pension Plan [Member] | Alternative investments
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	15.00%	17.00%
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, 2020	Dec. 31, 2019	Dec. 31, 2018	Jan. 01, 2020	Jan. 01, 2019
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 404	$ 401		$ 401	$ 372
Plan assets at net asset value	61	68
Service cost	1	1	$ 1
PSCo [Member]
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Service cost	0
Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	88	82
Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	255	250
Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	1
Debt Securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	207	204
Plan assets at net asset value	0	0
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	0
Debt Securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	207	203
Debt Securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	1
Cash
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	24	20
Plan assets at net asset value	0	0
Cash | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	24	20
Cash | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Cash | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Insurance contracts
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	45	45
Plan assets at net asset value	0	0
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	0
Insurance contracts | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	45	45
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	0
Other
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	3	2
Plan assets at net asset value	0	0
Other | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Other | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	3	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	0
Commingled funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	125	130
Plan assets at net asset value	61	68
Commingled funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	64	62
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	0
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	$ 0

XML

Benefit Plans and Other Postretirement Benefits, Postretirement Benefit Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Significant Assumptions Used to Measure Costs [Abstract]
Liability, Defined Benefit Plan, Noncurrent	$ 161	$ 212
Defined Contribution Plan, Administrative Expense	12	11	$ 11
Other Postretirement Benefits Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan assets at net asset value	61	68
Plan amendments	0	0
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1	380
Service cost	1	1	1
Interest cost	13	15	15
Medicare subsidy reimbursements	1	1
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant	6	7
Actuarial (gain) loss	52	12
Benefit payments	(38)	(34)
Obligation at Dec. 31	415	380
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	401
Actual return (loss) on plan assets	32	52
Plan participants' contributions	6	7
Employer contributions	3	4
Benefit payments	(38)	(34)
Fair value of plan assets at Dec. 31	404	401
Funded Status of Plans at Dec. 31 [Abstract]
Funded status	(11)	21
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss	81	45
Prior service (credit) cost	6	10
Total	75	35
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	$ 75	$ 35
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Pre-65	5.50%	6.00%
Ultimate health care trend assumption rate (as a percent)	4.50%	4.50%
Period until ultimate trend rate is reached (in years)	5	3
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	$ 1	$ 1	1
Interest cost	13	15	15
Expected return on plan assets	(17)	(19)	(23)
Amortization of prior service (credit) cost	(4)	(5)	(6)
Amortization of net loss	1	3	4
Net periodic pension cost	$ (7)	$ (5)	$ (9)
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)	3.47%	4.32%	3.62%
Expected average long-term rate of return on assets (as a percent)	4.50%	4.50%	5.30%
Liability, Defined Benefit Plan, Noncurrent	$ 11	$ 21
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position	$ (11)	$ 21
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	2.65%	3.47%
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Current Regulatory Assets	$ 0	$ 0
Deferred Income Taxes	0	0
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Net-Of-Tax Accumulated Other Comprehensive Income	0	0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	0	0	$ 0
Defined Benefit Plan, Costs Not Recognized Due To Regulation	3	1	2
Net benefit cost recognized for financial reporting	$ (4)	$ (4)	(7)
Target pension asset allocations (as a percent)	100.00%	100.00%
Defined Benefit Plan, Expected Future Benefit Payment, Next Twelve Months	$ 31
Defined Benefit Plan, Expected Future Prescription Drug Subsidy Receipt, Next Twelve Months	2
Defined Benefit Plan Net Projected Benefit Payments In Year One	29
Defined Benefit Plan, Expected Future Benefit Payment, Year Two	31
Defined Benefit Plan, Expected Future Prescription Drug Subsidy Receipt, Year Two	2
Defined Benefit Plan Net Projected Benefit Payments In Year Two	29
Defined Benefit Plan, Expected Future Benefit Payment, Year Three	30
Defined Benefit Plan, Expected Future Prescription Drug Subsidy Receipt, Year Three	2
Defined Benefit Plan Net Projected Benefit Payments In Year Three	28
Defined Benefit Plan, Expected Future Benefit Payment, Year Four	30
Defined Benefit Plan, Expected Future Prescription Drug Subsidy Receipt, Year Four	2
Defined Benefit Plan Net Projected Benefit Payments In Year Four	28
Defined Benefit Plan, Expected Future Benefit Payment, Year Five	29
Defined Benefit Plan, Expected Future Prescription Drug Subsidy Receipt, Year Five	2
Defined Benefit Plan Net Projected Benefit Payments In Year Five	27
Defined Benefit Plan, Expected Future Benefit Payment, Five Fiscal Years Thereafter	130
Defined Benefit Plan, Expected Future Prescription Drug Subsidy Receipt, after Year Five	12
Defined Benefit Plan Net Projected Benefit Payments In Five Fiscal Years Thereafter	$ 118
Other Postretirement Benefits Plan [Member] | Domestic and international equity securities
Significant Assumptions Used to Measure Costs [Abstract]
Target pension asset allocations (as a percent)	15.00%	15.00%
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)	72.00%	72.00%
Other Postretirement Benefits Plan [Member] | Alternative investments
Significant Assumptions Used to Measure Costs [Abstract]
Target pension asset allocations (as a percent)	9.00%	9.00%
Other Postretirement Benefits Plan [Member] | Cash
Defined Benefit Plan Disclosure [Line Items]
Plan assets at net asset value	$ 0	$ 0
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	20
Fair value of plan assets at Dec. 31	$ 24	$ 20
Significant Assumptions Used to Measure Costs [Abstract]
Target pension asset allocations (as a percent)	4.00%	4.00%
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan assets at net asset value	$ 388	$ 348
Plan amendments	0	0
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1	1,330
Service cost	30	26	29
Interest cost	46	52	47
Medicare subsidy reimbursements	0	0
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant	0	0
Actuarial (gain) loss	102	108
Benefit payments	(80)	(85)
Obligation at Dec. 31	1,428	1,330
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	1,124
Actual return (loss) on plan assets	189	197
Plan participants' contributions	0	0
Employer contributions	50	46
Benefit payments	(80)	(85)
Fair value of plan assets at Dec. 31	1,283	1,124
Funded Status of Plans at Dec. 31 [Abstract]
Funded status	(145)	(206)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss	432	482
Prior service (credit) cost	1	4
Total	431	478
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	404	452
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	30	26	29
Interest cost	46	52	47
Expected return on plan assets	(70)	(69)	(69)
Amortization of prior service (credit) cost	(3)	(3)	(3)
Amortization of net loss	30	25	31
Net periodic pension cost	$ 33	$ 34	$ 40
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)	3.49%	4.31%	3.63%
Expected average long-term rate of return on assets (as a percent)	6.84%	6.84%	6.84%
Liability, Defined Benefit Plan, Noncurrent	$ 145	$ 206
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position	$ (145)	$ (206)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	2.71%	3.49%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase	3.75%	3.75%
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Current Regulatory Assets	$ 25	$ 22
Deferred Income Taxes	1	1
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Net-Of-Tax Accumulated Other Comprehensive Income	1	3
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	0	3	$ 5
Defined Benefit Plan, Costs Not Recognized Due To Regulation	4	4	(4)
Net benefit cost recognized for financial reporting	$ 37	$ 38	$ 36
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	3.75%	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	$ 83
Defined Benefit Plan, Expected Future Benefit Payment, Year Two	83
Defined Benefit Plan, Expected Future Benefit Payment, Year Three	82
Defined Benefit Plan, Expected Future Benefit Payment, Year Four	82
Defined Benefit Plan, Expected Future Benefit Payment, Year Five	82
Defined Benefit Plan, Expected Future Benefit Payment, Five Fiscal Years Thereafter	393
Pension Plan [Member] | Domestic and international equity securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets at net asset value	0	$ 0
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	30
Fair value of plan assets at Dec. 31	$ 27	$ 30
Significant Assumptions Used to Measure Costs [Abstract]
Target pension asset allocations (as a percent)	35.00%	37.00%
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)	35.00%	30.00%
Pension Plan [Member] | Short-to-intermediate fixed income securities
Significant Assumptions Used to Measure Costs [Abstract]
Target pension asset allocations (as a percent)	13.00%	14.00%
Pension Plan [Member] | Alternative investments
Significant Assumptions Used to Measure Costs [Abstract]
Target pension asset allocations (as a percent)	15.00%	17.00%
Pension Plan [Member] | Cash
Defined Benefit Plan Disclosure [Line Items]
Plan assets at net asset value	$ 0	$ 0
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	46
Fair value of plan assets at Dec. 31	$ 75	$ 46
Significant Assumptions Used to Measure Costs [Abstract]
Target pension asset allocations (as a percent)	2.00%	2.00%

XML

Benefit Plans and Other Postretirement Benefits, Projected Benefit Payments (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Defined Contribution Plan, Administrative Expense		$ 12	$ 11	$ 11
Other Postretirement Benefits Plan [Member]
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2020		31
2021		31
2022		30
2023		30
2024		29
2025-2029		130
Expected Medicare Part D Subsidies [Abstract]
2020		2
2021		2
2022		2
2023		2
2023		2
2025-2029		12
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
2020		29
2021		29
2022		28
2023		28
2024		27
2025-2029		118
Pension Plan [Member]
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2020		83
2021		83
2022		82
2023		82
2024		82
2025-2029		393
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		150	154	150
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	$ 125
Pension Plan [Member] | PSCo [Member]
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Total contributions to Xcel Energy's pension plans during the period		50	46	22
Pension Plan [Member] | PSCo [Member] | Subsequent Event
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Total contributions to Xcel Energy's pension plans during the period	45
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	15	11
Defined Benefit Plan, Overfunded 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	$ 10
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		$ 3	$ 4	$ 5

XML

Benefit Plans and Other Postretirement Benefits Plan Amendments (Details)	12 Months Ended
	Dec. 31, 2019
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Postretirement Cash Balance Formula	5.00%

XML

Commitments and Contingencies Gas Trading Litigation (Details)	Dec. 31, 2020
Gas Trading Litigation [Member]
Public Utilities, General Disclosures [Line Items]
Loss Contingency, Pending Claims, Number	2
Breckenridge Litigation [Domain]
Public Utilities, General Disclosures [Line Items]
Loss Contingency, Pending Claims, Number	3,000,000

XML

Commitments and Contingencies MGP Sites (Details)	Dec. 31, 2020 Site
Other MGP, Landfill, or Disposal Sites [Domain]
Loss Contingencies [Line Items]
Number of identified MGP, landfill, or disposal sites under current investigation and/or remediation	3

XML

Commitments and Contingencies Environmental Requirements - Water and Waste (Details) - Federal Coal Ash Regulation [Domain]	Dec. 31, 2020
Loss Contingencies [Line Items]
Number of regulated ash units that will still be in operation by the end of 2019	6
Number of sites where statistically significant increases over established groundwater standards exist	4
Number of sites where corrective action options are being evaluated for locations with statistically significant increases above background concentrations	2
Number of sites where monitoring results indicate potential offsite impacts to groundwater	1
Number of impoundments where closure plans will be expedited	1

XML

Commitments and Contingencies, Asset Retirement Obligations (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2020		Dec. 31, 2019
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		$ 324	[1]	$ 338
Amounts Incurred	[2]	26
Amounts Settled	[3]	(3)
Accretion		14		16
Cash Flow Revisions		38	[4]	(30)	[5]
Ending balance		399		324	[1]
Electric Plant Steam and Other Production Ash Containment
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		100	[1]	102
Amounts Incurred	[2]	0
Amounts Settled	[3]	0
Accretion		4		5
Cash Flow Revisions		33	[4]	(7)	[5]
Ending balance		137		100	[1]
Electric Plant Wind Production
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		16	[1]	14
Amounts Incurred	[2]	26
Amounts Settled	[3]	(3)
Accretion		1		1
Cash Flow Revisions		0	[4]	1	[5]
Ending balance		40		16	[1]
Electric Plant Electric Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		14	[1]	13
Amounts Incurred	[2]	0
Amounts Settled	[3]	0
Accretion		1		1
Cash Flow Revisions		0	[4]	0	[5]
Ending balance		15		14	[1]
Electric Plant Other
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		0	[1]	3
Accretion				0
Cash Flow Revisions	[5]			(3)
Ending balance	[1]			0
Natural Gas Plant Gas Transmission and Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		190	[1]	201
Amounts Incurred	[2]	0
Amounts Settled	[3]	0
Accretion		8		9
Cash Flow Revisions		5	[4]	(20)	[5]
Ending balance		203		190	[1]
Natural Gas Plant Other
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		3	[1]	4
Amounts Incurred	[2]	0
Amounts Settled	[3]	0
Accretion		0		0
Cash Flow Revisions		0	[4]	(1)	[5]
Ending balance		3		3	[1]
Common and Other Property Common Miscellaneous
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		1	[1]	1
Amounts Incurred	[2]	0
Amounts Settled	[3]	0
Accretion		0		0
Cash Flow Revisions		0	[4]	0	[5]
Ending balance		$ 1		$ 1	[1]

[1] There were no ARO amounts incurred or settled in 2019

[2] Amounts incurred related to the Cheyenne Ridge wind farm placed in service in 2020.

[3] Amounts settled related to removal of wind facilities.

[4] In 2020, 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 ash containment facilities.

[5] In 2019, AROs were revised for changes in timing and estimates of cash flows. Changes in gas transmission and distribution AROs were primarily related to increased gas line mileage and number of services, which were more than offset by decreased inflation rates. Revisions in steam, hydro, and other production AROs primarily related to changes in cost estimates for pond remediation.

XML

Commitments and Contingencies, Leases (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Lessee, Lease, Description [Line Items]
Maximum Length - Short-Term Leases		12 months
Operating Lease, Weighted Average Discount Rate, Percent		3.90%
Short-term Lease, Cost		$ 1	$ 2	$ 1
Operating Lease, Assets and Liabilities, Lessee [Abstract]
Operating Lease, Right-of-Use Asset, Gross		659	654
Operating Lease, Right-of-Use Asset, Accumulated Depreciation		(159)	(80)
Operating lease right-of-use assets		500	574
Finance Lease, Assets and Liabilities, Lessee [Abstract]
Finance Lease, Right-of-Use Asset, Gross		222	221
Finance Lease, Right-of-Use Asset, Accumulated Depreciation		(90)	(82)
Finance Lease, Right-of-Use Asset		132	139
Lease, Cost [Abstract]
Operating Lease, Cost	[1]	113	112	111
Finance Lease, Right-of-Use Asset, Amortization		7	6	6
Finance Lease, Interest Expense		18	19	19
Finance Lease, Cost		25	25	25
Lessee, Operating Lease, Liability, Payment, Due [Abstract]
2021		116
2022		99
2023		80
2024		73
2025		68
Thereafter		175
Total minimum obligation		611
Interest component of obligation		(82)
Present value of minimum obligation		529
Less current portion		(97)	(86)
Operating lease liabilities		$ 432	518
Operating Lease, Weighted Average Remaining Lease Term		7 years 1 month 6 days
Lessee, Finance Lease, Description [Abstract]
2021		$ 24
2022		21
2023		20
2024		20
2025		19
Thereafter		381
Total minimum obligation		485
Interest component of obligation		(352)
Present value of minimum obligation		133
Less current portion		(7)
Noncurrent operating and finance lease liabilities		$ 126
Finance Lease, Weighted Average Remaining Lease Term		38 years
Property, Plant and Equipment, Other Types [Member]
Operating Lease, Assets and Liabilities, Lessee [Abstract]
Operating Lease, Right-of-Use Asset, Gross		$ 68	69
Lease, Cost [Abstract]
Operating Lease, Cost	[2]	13	14	14
Lessee, Operating Lease, Liability, Payment, Due [Abstract]
2021		15
2022		15
2023		10
2024		10
2025		5
Thereafter		12
Total minimum obligation		67
Interest component of obligation		(8)
Present value of minimum obligation		59
Gas Storage Facilities [Member]
Finance Lease, Assets and Liabilities, Lessee [Abstract]
Finance Lease, Right-of-Use Asset, Gross		201	200
Gas Pipeline
Finance Lease, Assets and Liabilities, Lessee [Abstract]
Finance Lease, Right-of-Use Asset, Gross		21	21
Purchased Power Agreements
Operating Lease, Assets and Liabilities, Lessee [Abstract]
Operating Lease, Right-of-Use Asset, Gross		591	585
Lease, Cost [Abstract]
Operating Lease, Cost		100	$ 98	$ 97
Lessee, Operating Lease, Liability, Payment, Due [Abstract]
2021	[3],[4]	101
2022	[3],[4]	84
2023	[3],[4]	70
2024	[3],[4]	63
2025	[3],[4]	63
Thereafter	[3],[4]	163
Total minimum obligation	[3],[4]	544
Interest component of obligation	[3],[4]	(74)
Present value of minimum obligation	[3],[4]	$ 470
WYCO, Inc. [Member]
Lessee, Finance Lease, Description [Abstract]
Equity Method Investment, Ownership Percentage		50.00%

[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 short-term lease expense of $1 million, $2 million and $1 million for 2020, 2019 and 2018, respectively.

[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.

XML

Commitments and Contingencies, Purchased Power Agreements (Details) - Capacity - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Purchased Power Agreements (PPAs) [Abstract]
Payments for capacity	$ 10	$ 12	$ 21
Estimated Future Payments Under PPAs [Abstract]
2021	3
2022	3
2023	3
2024	3
2025	3
Thereafter	5
Total	$ 20

XML

Commitments and Contingencies, Fuel Contracts (Details) $ in Millions	Dec. 31, 2020 USD ($)
Coal
2021	$ 132
2022	61
2023	22
2024	22
2025	23
Thereafter	47
Total	307
Natural Gas Supply
2021	354
2022	119
2023	54
2024	3
2025	0
Thereafter	0
Total	530
Natural Gas Storage and Transportation
2021	116
2022	115
2023	67
2024	37
2025	36
Thereafter	475
Total	$ 846

XML

Commitments and Contingencies, Variable Interest Entities (Details) - MW	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Maximum
Purchased Power Agreements (PPAs) [Abstract]
Long term purchased power agreements expiration	2032
Equity Method Investment, Nonconsolidated Investee or Group of Investees [Member]
Purchased Power Agreements (PPAs) [Abstract]
Generating capacity (in MW)	1,518	1,442

XML

Commitments and Contingencies ARO Phantom (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020 USD ($)
Asset Retirement Obligations [Line Items]
Amounts Settled	$ 3	[1]
Amounts Incurred	26	[2]
Electric Plant Steam and Other Production Ash Containment
Asset Retirement Obligations [Line Items]
Amounts Settled	0	[1]
Amounts Incurred	0	[2]
Electric Plant Wind Production
Asset Retirement Obligations [Line Items]
Amounts Settled	3	[1]
Amounts Incurred	26	[2]
Electric Plant Electric Distribution
Asset Retirement Obligations [Line Items]
Amounts Settled	0	[1]
Amounts Incurred	0	[2]
Natural Gas Plant Gas Transmission and Distribution
Asset Retirement Obligations [Line Items]
Amounts Settled	0	[1]
Amounts Incurred	0	[2]
Natural Gas Plant Other
Asset Retirement Obligations [Line Items]
Amounts Settled	0	[1]
Amounts Incurred	0	[2]
Common and Other Property Common Miscellaneous
Asset Retirement Obligations [Line Items]
Amounts Settled	0	[1]
Amounts Incurred	$ 0	[2]

[1] Amounts settled related to removal of wind facilities.

[2] Amounts incurred related to the Cheyenne Ridge wind farm placed in service in 2020.

XML

Other Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020		Dec. 31, 2019		Dec. 31, 2018
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	$ 6,996
Income tax expense (benefit)	45		$ 80		$ 113
Accumulated other comprehensive loss at end of period	7,592		6,996
Gains and Losses on Cash Flow Hedges
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	(24)		(26)
Amortization of net actuarial income (loss)	0		0
Net current period other comprehensive income (loss)	1		2
Accumulated other comprehensive loss at end of period	(23)		(24)		(26)
Gains and Losses on Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Income tax expense (benefit)	0		0
Reclassification from AOCI, Current Period, Tax	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]	(2)	[2]
Defined Benefit Pension and Postretirement Items
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	(3)		0
Amortization of net actuarial income (loss)	(2)		3	[3]
Net current period other comprehensive income (loss)	2		(3)
Accumulated other comprehensive loss at end of period	(1)		(3)		0
Defined Benefit Pension and Postretirement Items | Reclassification out of Accumulated Other Comprehensive Income
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Income tax expense (benefit)	0		0
Reclassification from AOCI, Current Period, Tax	1		(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	(27)		(26)
Amortization of net actuarial income (loss)	(2)		3
Net current period other comprehensive income (loss)	3		(1)
Accumulated other comprehensive loss at end of period	(24)		(27)		$ (26)
Total | Interest Rate Swap
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amortization of net actuarial income (loss)	$ (1)		$ (2)

[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.

XML

Segments and Related Information (Details) - USD ($) $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting Information [Line Items]
Operating revenue, Regulated Natural Gas										$ 1,024	$ 1,161	$ 1,015
Unregulated Operating Revenue										43	43	40
Regulated and Unregulated Operating Revenue		$ 1,134	$ 1,081	$ 911	$ 1,057	$ 1,060	$ 1,044	$ 910	$ 1,223	4,183	4,237	4,086
Depreciation and amortization										655	602	561
Interest charges and financing costs										224	224	186
Income tax expense (benefit)										45	80	113
Net income (loss)		$ 133	$ 218	$ 108	$ 129	$ 133	$ 204	$ 102	$ 139	588	578	552
Intercompany Revenue										5	5	4
Regulated Electric
Segment Reporting Information [Line Items]
Revenues Including Intersegment Revenues										3,117	3,034	3,031
Depreciation and amortization										497	455	416
Interest charges and financing costs										173	173	142
Income tax expense (benefit)										13	45	103
Net income (loss)										460	465	429
Regulated Natural Gas
Segment Reporting Information [Line Items]
Revenues Including Intersegment Revenues										1,024	1,161	1,016
Depreciation and amortization										152	141	140
Interest charges and financing costs										50	50	43
Income tax expense (benefit)										29	33	13
Net income (loss)										126	119	121
All Other
Segment Reporting Information [Line Items]
Depreciation and amortization										6	6	5
Interest charges and financing costs										1	1	1
Income tax expense (benefit)										3	2	(3)
Net income (loss)										2	(6)	2
Operating Segments
Segment Reporting Information [Line Items]
Regulated and Unregulated Operating Revenue	[1]									4,184	4,238	4,087
Operating Segments | Regulated Electric
Segment Reporting Information [Line Items]
Electric										3,116	3,033	3,031
Operating Segments | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenue, Regulated Natural Gas										1,024	1,161	1,015
Operating Segments | All Other
Segment Reporting Information [Line Items]
Unregulated Operating Revenue	[1]									43	43	40
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	0
Intersegment Eliminations | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenue, Regulated Natural Gas										$ 0	$ 0	$ 1

[1] Operating revenues include $5 million, $5 million and $4 million of intercompany revenue for the years ended Dec. 31, 2020, 2019 and 2018, respectively. See Note 13 for further information.

XML

Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	$ 8	$ 53
Accounts payable	58	44
NSP-Minnesota
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	0	19
Accounts payable	1	0
NSP-Wisconsin
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	0	0
Accounts payable	1	0
SPS
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	0	0
Accounts payable	6	0
Other subsidiaries of Xcel Energy Inc.
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	8	34
Accounts payable	50	44
Other Expense
Operating expenses
Costs and Expenses, Related Party	571	532	$ 519
Other Revenue
Operating revenues
Operating Revenue from Related Parties	$ 5	$ 5	$ 4

XML

Summarized Quarterly Financial Data (Unaudited) (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Quarterly Financial Information Disclosure [Abstract]
Regulated and Unregulated Operating Revenue	$ 1,134	$ 1,081	$ 911	$ 1,057	$ 1,060	$ 1,044	$ 910	$ 1,223	$ 4,183	$ 4,237	$ 4,086
Operating income	176	290	161	196	200	284	163	210	823	857	793
Net income	$ 133	$ 218	$ 108	$ 129	$ 133	$ 204	$ 102	$ 139	$ 588	$ 578	$ 552

XML

Schedule II, Valuation and Qualifying Accounts (Details) - Allowance for Bad Debts - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Jan. 1		$ 21	$ 21	$ 20
Charged to costs and expenses		24	17	16
Charged to other accounts	[1]	4	6	5
Deductions from reserves	[2]	(20)	(23)	(20)
Balance at Dec. 31		$ 29	$ 21	$ 21

[1] Recovery of amounts previously written-off.

[2] Deductions related primarily to bad debt write-offs